Rig contractor Ensco has revealed that three “independent advisory firms” urged its shareholders vote for the merger with rival firm Rowan.
The Institutional Shareholder Service (ISS) is understood to have recommended to shareholders that the deal will have “a positive impact on Ensco’s balance sheet”, adding that support the proposed merger “remains warranted”.
The deal was additionally advised upon by firms Glass, Lewis & Co. and Egan-Jones.
Ensco board members also recommend the merger.
The firm’s president and chief executive Carl Trowell said: “We are pleased that ISS, Glass Lewis and Egan-Jones recognize the compelling strategic and financial rationale of our planned merger with Rowan.
“We believe that the combined company will be an industry-leading offshore driller that will allow shareholders to participate in significant, long-term value creation opportunities.
“With a fleet of high-specification floaters and jack-ups, diverse customer base, broad geographic presence and enhanced financial position, the combined company will be able to compete strongly across market cycles.”
It’s never ideal if you own a fleet of crude tankers and the world’s oil producers remove millions of barrels of cargo from the market to avert a glut. Nor is a collapse in charter rates normally the best news.
While both those things happened in the past few months, the people paid to evaluate the shipping industry’s prospects are actually turning a little more bullish.
The analysts’ optimism stems from a conviction that the world’s refineries will have to process more crude in order to supply ships with new kinds of fuel in 2020 under rules set out by the International Maritime Organization. On top of that, historic trade flows are at risk of disruption as OPEC and allied producers curb output of one type of crude at a time when American drillers boost supplies of another.
“Despite the latest meltdown, we remain bullish about the tanker market mainly because we believe IMO 2020 requirements will push for oil production growth, which will support freight rates” from the second half of this year, said Espen Fjermestad, an analyst at Fearnley Securities AS in Oslo. “Refineries will need to increase runs to meet increased demand.”
The Baltic Dirty Tanker Index, a wide measure of charter rates mostly for moving crude, has plunged almost 30 percent in the past three months. The Organization of Petroleum Exporting Countries and allied producers agreed late last year that they would cut more than 200 million barrels of total output through June — large portion of which would normally be delivered by sea.
Undeterred, shipping analysts surveyed by Bloomberg have, since early November, raised their forecasts for what every class of mainstream crude carrier will earn this year. Two of the tanker-market’s biggest pureplay stocks — Euronav NV and Frontline Ltd. — are overwhelmingly dominated with buy recommendations.
Very large crude carriers, also known as VLCCs, will earn $29,200 a day in 2019, analysts’ estimates compiled by Bloomberg show. That compares with $28,200 a day that they predicted in early November. The vessels’ average earnings slumped to $15,561 a day last year, the lowest since at least 2009, according to Clarkson Research Services Ltd.
The freight market will benefit from IMO 2020 later this year, say firms including Clarksons Platou and Evercore ISI. The measures, designed to limit sulfur emissions, are expected to boost the amount of crude being processed because refineries will need to make more diesel-like fuels.
In addition, measures that would once have been disastrous for owners — curbs by OPEC and its allies — aren’t concerning the tanker market as much as they would have once. The reductions are primarily hitting supplies of heavier crudes that are high in sulfur, while booming supplies from the U.S. tend to be lighter and less sulfurous.
That situation will have to correct later this year to avoid shortages of heavier crudes, resulting in extra flows of the grades, according to Fjermestad.
The risks to supplies of heavier crude was highlighted late last month by U.S. government’s decision to impose sweeping sanctions on Venezuela’s state oil company, which appears to be an effective ban on selling the country’s crude to the U.S — and potentially across the world.
The Latin American country pumps some of the heaviest crude on the planet and replacing its supplies to the U.S. with barrels from the Middle East would drive up cargo distances. It’s important to note, though, that Venezuela exported well over 1 million barrels a day on average last year, so a full halt to those shipments would hit tanker demand hard, especially if OPEC’s Persian Gulf members don’t fill the void.
The “crude tanker outlook looks challenging over the next 2-3 quarters under the pressure of the OPEC cuts,” Fotis Giannakoulis, an analyst at Morgan Stanley, said in a note. “However, U.S. sanctions on PDVSA could lead to substantial ton-mile expansion due to disruptions in Venezuelan oil flows, potentially helping the sector to remain profitable if output remains robust.”
Heavier crude is more suited to making IMO-compliant fuel. Refineries produce about 25 percent to 30 percent of middle distillates using light U.S. oil, compared with about 35 percent from heavy crude, according to Fjermestad.
Tanker spot rates will continue to decline in the first half of the year because of oil supply cuts and fleet growth, according to Jonathan Chappell, an analyst focusing on marine transportation equities at Evercore ISI. After that, things should improve.
“With refinery utilization rising and newbuild deliveries set to slow, we are expecting a relatively strong snapback in rates, which is likely to be exacerbated by expected trade route disruption associated with the preparation for the onset of IMO 2020,” he said.
The director of a UK energy trade body has said her organisation is “hoping” for an Offshore Wind Sector Deal conclusion in the first quarter of 2019.
Emma Pinchbeck, executive director of RenewableUK, was clarifying her position after it was reported in local English media she’d revealed the deal was “done”.
The Grimsby Telegraph reported that Ms Pinchbeck informed audience members at this week’s GRP19 Conference that a Sector Deal had been finalised, but that she was yet to see the details.
Mr Pinchbeck said today that she had made it clear that the details of the sector deal are still being “worked out”.
In a comment to Energy Voice, Ms Pinchbeck said: “We’re hoping that the Offshore Wind Sector Deal will be concluded within the first quarter of this year.
“The joint industry-Government body, the Offshore Wind Industry Council is working hard on this.
“The deal aims to deliver at least a third of the country’s electricity from offshore wind by 2030, attracting £48 billion in investment in UK infrastructure.
“By the end of the next decade, we expect the offshore wind industry will employ 27,000 people and that the global market for offshore wind products and services provided by UK-based firms is expected to be worth nearly £5 billion a year.”
US oil firm Apache Corporation has said that it is planning “lower activity” across its business in 2019.
The company, who operate a number of North Sea assets, revealed that it has put in place a lower investment budget of £1.8 billion.
But the firm added that despite lower activity it is still projecting a production range of 410 to 440 thousand barrels of oil equivalent (BOE) per day.
Apache own a controlling share of the North Sea Forties field, with further operating interests in the Beryl, Nevis, Nevis South, Skene and Buckland fields, and a non-operated interests in the Maclure and Nelson fields.
The Houston-headquartered firm also confirmed that 70-75% of the reduced budget will be allocated within its US business.
John J. Christmann, chief executive and president of Apache Corporation, said: “We believe Apache offers a very competitive investment proposition both within the E&P sector and relative to other sectors in the market.
“In a flat oil price environment, we believe we can deliver a combination of sustainable production and operating cash flow growth, strong returns, a stable dividend that currently yields more than 3 percent, and return at least 50 percent of any free cash flow to our shareholders.
“Additionally, Apache offers significant upside value potential through its current 100 percent ownership in Block 58 offshore Suriname, as well as its portfolio of unconventional exploration projects in the Lower 48.”
In December, Apache Corporation revealed the Garten well in the UK North Sea had started producing oil.
The exploration well was successfully drilled 180 miles north-east of Aberdeen in March 2018.
First oil followed less than eight months later, at the end of November.
The well is currently pumping out 13,700 barrels of oil per day and 15.7m cubic feet of gas.
Garten, 100% owned by Apache, is expected to yield more than 10m barrels of oil.
SSE has cut its earnings outlook, lost another 240,000 customers and said it is assessing options for its retail arm following the collapse of a merger with rival npower.
The energy giant pointed to competitive pressures as it saw the number of domestic energy accounts fall from 6.04 million at the end of September to 5.88 million in December.
In a third quarter trading update, SSE also said it is considering a standalone demerger and listing, a sale or ring-fencing of its energy services arm.
It comes after SSE and npower were last year forced to call off their plans to merge the unit, blaming “challenging market conditions” and the Government’s price cap.
The companies said the deal was affected by multiple factors, including the performance of their businesses, clarity on the final level of the Government’s default tariff cap and changing energy market conditions.
SSE also warned on Friday that earnings per share would be 6p lower than previously expected, coming in at a range of 64p and 69p, down from earlier estimates of 70p to 75p.
It put this down to not being able to recognise income from the UK’s Capacity Market scheme following a court ruling.
Boss Alistair Phillips-Davies said: “We continue to make good progress in our core businesses of regulated energy networks and renewable energy, complemented by flexible thermal generation and business energy sales.
“We are also making progress in assessing the options for the future of the energy services business.
“SSE has a clear strategy and good long-term prospects for its high-quality core businesses and assets that contribute to the transition to a low-carbon economy and will support the creation of value and delivery of our dividend plan in the years to come.”
Since the Npower failure, SSE has sold its stake in two Scottish wind farms for £635 million and offloaded half of its telecoms network business to Infracapital for up to £380 million.
Aker Solutions has seen its income almost double in the last year on the back of higher revenues and an expanding order book.
The energy services firm has announced its full-year financial results, reporting net income before tax of £71m, nearly twice that of 2017 which was £35.8.
Revenues in the fourth quarter were the highest since 2015 at £624.8million.
Aker reported “record demand” for front-end engineering services, adding that investments in digitalisation and technology were key in securing work.
The firm said there are “continued signs of recovery in the global market” with more projects being sanctioned and break-even costs coming down.
Aker Solutions chief executive Luis Araujo
Orders totalled £476.4m, bringing the firm’s total backlog to £3.1bn, with major work secured in the South China Sea with Cnooc and on Equinor’s Northern Lights carbon capture project in Norway.
Chief executive Luis Araujo said: “In 2018, we saw a record number of studies and front-end engineering work for larger and more complex projects than previous years – a positive sign of more work to come.
“As we have already seen at Johan Sverdrup, Johan Castberg and Troll, early involvement puts us in a strong position to secure more work.
“”Delivering cost efficiency and standardization to our customers is increasingly linked to our digital capabilities.
“Working closely with clients and suppliers in early stages of projects, we are able to simplify and standardize our processes and products.
“This is shared through our global organization, ultimately saving time and money for our clients.”
Cluff Natural Resources (CLNR) has announced it will farm-out a southern North Sea licence to Shell, with the possibility of an agreement on a second.
The deal will see CLNR farm-out 70% of its P2252 licence to the energy giant, which contains the Penascola prospect estimated to hold around 100 million barrels of oil equivalent.
Cluff will retain the remaining 30% non-operated interest and the costs will be “satisfied by each party in proportion to their working interests”.
The agreed work programme includes shooting of at least 400km2 of new seismic data over the Penascola prospect this summer to support a well investment decision before the end of 2020.
CLNR’s share price has surged following the announcement.
Shell has also been granted the option to acquire 50% of Cluff’s P2437 licence by April 30 for £463,335.
The licence contains the Selene prospect, estimated to hold around 90million barrels of oil equivalent, and lies adjacent to Shell’s Barque gas field infrastructure.
If a decision is taken to drill an exploration well, Shell would cover 75% of the costs up to a total of £19.3m.
CLNR, which was founded by oil and gas veteran Algy Cluff, described it as an “endorsement” of the quality of the licences.
Chief executive Graham Swindells said: “We are delighted to be able to announce the farm-out of Licence P2252 and the terms of an option to farm out Licence P2437 with a partner of this standing.
Graham Swindells, CEO of Cluff Natural Resources
“This partnership is a clear endorsement of the quality of the licences in our portfolio and demonstrates the Cluff technical team’s ability to identify and transform overlooked or less understood opportunities.
“We are particularly excited at the prospect of embarking on our partnership with Shell with both parties sharing a commitment to further development in the Southern North Sea.
“Most importantly, we now have direct visibility over the route to future drilling activity, and the potential to create further significant value for shareholders.
“We look forward to building our partnership with Shell and successfully developing these prospects.”
A spokesman for Shell said:“This deal is consistent with our strategy to continually reshape and high-grade our portfolio.
“We look forward to partnering with Cluff on these licences and applying our extensive exploration expertise to help develop this highly promising gas prospect in the Southern North Sea”
Cluff, which has been on a long-running hunt for a partner, announced in November that it entered into an exclusivity agreement with a “major international oil and gas company” back in November.
The firm also confirmed today it is no longer in non-exclusive negotiations with its preferred bidder for the P2248 licence, as the bidder could not demonstrate the financial capacity to fund the work.
CLNR has until 29 February to find a partner or it will be forced to drop the licence.
A top deal-maker for North Sea firms has called for an end to commercial behaviours which are “extremely damaging” for the industry.
Bob Ruddiman, head of oil and gas at legal firm Pinsent Masons, said the combination of “risk-averse” lawyers and companies with unrealistic expectations was “corrosive”, while speaking at Subsea Expo yesterday.
He added that this goes against the industry’s plan to maximise oil and gas recovery from the region, and firms should instead be “constantly curious” in trying new approaches.
Mr Ruddiman said:“Lawyers are, both by nature and training, often risk-averse and will find and envisage problems which only then a smaller sub-set of their group will find solutions to.
“In negotiations, often the problem is sub-consciously seen as helpful because it slows progress and the potential risk is postponed – and I say that not in jest, I mean that seriously.
“This over-cautious stance is then often compounded by commercial behaviours, which are unrealistic in respect to the relative merits of the commercial positions and outcomes.
“The combination of these two is extremely damaging from a number of perspectives.
“It leads to corrosive outcomes and is definitely opposed to MER (the maximising economic recovery strategy).”
The partner at Pinsent Masons also gave a warning that the dearth, and failure, of some large EPC contractors was down to “unrealistic” allocation of risk during the boom years of the oil and gas industry.
Mr Ruddiman said he believes commercial behaviours have improved since the Wood Review was published in 2014, which first set out the recommendations for the MER strategy.
He added that examples set by the Oil and Gas Authority, along with operators like Shell and Apache, shows the potential the industry has going forward.
However he said there needs to be a change in mindsets on various commercial models, such as those between operator and contractor, work between neighbouring license holders and tier one contractors and their sub-contractors.
In a “call to arms”, Mr Ruddiman said greater trust is needed on commercial models for the future, as well as an “enlightened approach” to collaborating and being open to learn from other industries in commercial and legal terms.
He added: “There needs to be a mindset which is curious, not questioning, and a genuine understanding of what everybody at the table needs and brings to it.
“There needs to be candour and establishment of trust. Without trust there is a relationship in name only, and not something solid to build upon.
“There’s a huge opportunity ahead of us but we’re not going to make the most of it if we just do things the way we have always done it so that’s a call to arms to try and change mindsets.
Organisers of the Subsea Expo yesterday toasted record attendance as the leading industry conference came to a close.
More than 6,500 visitors made their way to the Aberdeen Exhibition and Conference Centre during the three-day event.
The conference, which celebrates the UK’s £7.5bn subsea sector, welcomed local firms as well as delegates from around the word, including the US, Middle East, South America, Africa and Asia.
More than 170 businesses showcased their products and services at the event, which is the largest of its kind in Europe, organised by Subsea UK.
Yesterday’s closing sessions focussed on revitalising and extending the life of the North Sea, as well as bringing in the next generation.
Skills body Opito organised for more than 100 young people from across Aberdeen and Aberdeenshire to view the inner workings of the North Sea’s underwater sector.
The students met with a range of firms as part of the Energise Your Future event, which included the use of technology for a “virtual tour” of the seabed.
Neil Gordon, chief executive of Subsea UK, said: “From the conference programme to the exhibition floor, Subsea Expo 2019 clearly reflected the strength and ingenuity of our industry and the efforts that are being made to ensure the UK subsea sector maintains its world leading position for decades to come.
“This year’s event attracted more delegates, more international visitors, more exhibitors, more speakers and more young people than ever before, underlining the importance of our sector both in the UK and globally.
“The innovation and technology on show was a clear reminder of why our supply chain is envied around the world and the interest from overseas visitors emphasised our unparalleled expertise.”
The conference was opened on Tuesday by Scottish energy minister Paul Wheelhouse and hosted a range of discussions with industry leaders on topics including underwater vehicles, decommissioning and digital transformation.
Sally Finnie, business development director at Maritime Developments, said: “We’re coming away from the event encouraged. There has definitely been a more positive mood from the majority of exhibitors and visitors. It has been particularly pleasing to see a real international flavour to the delegates.
“We’re looking to internationalise our business, and there is a lot of interest in Scottish exports in the subsea market.”
Wednesday night also saw the return of the annual Subsea UK awards, celebrating the best and brightest of the industry.
Andy MacGill, engineering director at Infinity Oilfield Services, named Best Small Company at the Subsea UK awards, said: “It has definitely been worthwhile exhibiting here. It has been very busy. I heard record numbers attended the event and it felt like that.
“We have had a lot of footfall at our stand and have made a lot of contacts. Winning the award was the icing on the cake.”
The Health and Safety Executive (HSE) has warned Teekay following a “significant” propane leak on the Petrojarl Foinaven vessel.
The floating production, storage and offloading (FPSO) vessel is stationed west of Shetland on the Foinaven field, which is operated by BP.
An HSE inspector accused Teekay of failing to “take appropriate measures to prevent fire and explosion”.
In its prohibition notice, HSE said certain “fittings” were wrongly removed during an operation to disconnect propane vessels from the FPSO’s flare in November.
A Teekay spokesman said: “We can confirm our receipt of an improvement notice related to the portable propane tank fittings after a propane release onboard the Petrojarl Foinaven on the 24th November 2018.
“Immediate actions were taken to prevent disconnection of said fittings offshore and we continue to work with the regulator in order to close out all actions set out in the improvement notice by the relevant due date.”
Serica Energy has confirmed it is preparing to go to tender for key items for its North Sea Columbus development.
Although a recent acquisition of the Bruce, Keith and Rhum assets is the main focus for Serica, they’re not the only assets being worked on.
In October, the Oil and Gas Authority approved the firm’s plan to develop the 13 million barrel Columbus field in the central North Sea.
Drilling is planned for next year, with first oil targeted in 2021 and Serica is preparing to put contracts out for tender on the project.
Chief executive Mitch Flegg said: “We’re in the process now of preparing for the development, so we’re preparing for the long lead items that we need.
“We’re preparing to go to tender for well management companies and to look at preparing to tender for the rig contract.
“That is something that’s new to this office and new to this team because it’s something that we’ve been managing out of our London office up until now.
“We’re gradually involving the new team in that operation and it’s quite good to flip them around as much as anything, for this office to see that we’re not just going to be about Bruce, Keith and Rhum here. There are other things that are going on within the company.”
With the stronger operational capabilities of the Aberdeen base, Serica feels well equipped to add to its portfolio.
Even though they are focusing on what they have, Mr Flegg said they are continuing their hunt for more North Sea assets.
He said: “It’s about running these assets properly and letting this team maximise the values and opportunities that will come out of these assets, but at the same time looking for the next opportunity.
“We now have this fantastic operating capability that we can use elsewhere, so we are looking for more opportunities to bring more assets into the portfolio.
“We do have the resources to do both of those things, so in no way are we stopping the asset search whilst we bring these assets on board, we’re doing both.”
“Focus” is the mantra at Serica Energy’s new office in Aberdeen and it’s the word that chief executive Mitch Flegg keeps coming back to.
Just a year ago the firm employed only a handful of staff but since then the headcount has swelled to 140 thanks to a series of deals making Serica operator of the Bruce, Keith and Rhum (BKR) assets in the North Sea.
The deals, with BP, Total, BHP and Marubeni, saw Serica take on more than 100 workers from BP as it acquired the northern North Sea fields.
Serica has 60 full-time staff and contractors in place at the new Hill of Rubislaw facility. Mr Flegg said they are focused on giving the assets the attention they need in their mid-to-late life period.
“For us, these are our number one assets,” he said. “Everyone in this office wakes up focused on these assets and that’s how we believe we can extend the life and extend the value of these assets.
“It’s difficult for a company the size of BP to put all of their resources and all of their focus on to something like this because they’ve got a dozen different assets that they are looking after at any one time.
“We recognise that these assets have to have complete focus on them to prolong the life and keep them going for as long as possible.
“That’s to get the maximum benefit for ourselves but also for the country.
“We’re now responsible for the production of something like 5% of the UK’s gas. That’s why we need this facility to keep everything running, and we think we have the right team to do that, to have the focus on these assets to get the most out of them.”
Opening of the new facility was a landmark moment for Serica, which Mr Flegg said elevates the firm into a “different league” in terms of its operational capability.
Among other things, it is equipped with a real-time control room link with staff on the platforms.
The move was part of a long journey for Serica, which announced its initial deal with BP back in November 2017.
A full year later it was completed, with Serica picking up further stakes from Total, BHP and Marubeni, and the firm now owns 98% in Bruce, 100% of Keith and 50% of Rhum.
The deals were also delayed by efforts to obtain a US sanctions waiver for the Rhum field, which is part owned by Iran.
Taking a larger stake in the assets was a long-term goal for the firm so Serica jumped at the chance to complete them, even though it was a “more significant” piece of business than the company initially set out to do.
Ultimately, Mr Flegg believes it will prove the right move for the long-term future of BKR.
He said: “It was a longer process than we anticipated. It was a difficult process. There is a huge amount of work to do, particularly on the IT front nowadays to take over the operatorship.
“It is more significant than we set out to do. We’re really pleased with the way that’s worked out because it allows us to remove some of the partner issues and the misalignments that there were in previous partner groups.
“We think that’s good for the future of all the assets because we can now invest in them for the collective good, whereas before there were different partners in different assets, which made it difficult to make investment.
“It was always a long-term aim of ours to look at doing this but the opportunity came up and we did it.”
Mr Flegg said there was “not even a flicker” in terms of interruptions while BKR were changing hands – a point he’s proud of.
“We always set ourselves the goal that we didn’t want to make the transition too difficult,” he said.
“Our aim was always to make sure there was no interruption to production and to make sure there were no HSE incidents.
“We weren’t trying to change everything from day one, it was transition first and transformation later and we’re really pleased and proud that we achieved that.
“There were no HSE incidents, there was no interruption to production – there wasn’t even a flicker.
“We just carried on producing and everything worked pretty much first time.
“It was pretty nerve-wracking that first day but on the switchover everything continued to work, and has continued to do so since.”
Shell said it “has its eye” on more tie-back opportunities for its central North Sea gas hub.
Shearwater plays a key role in the energy giant’s “Central Graben Strategy”, making the platform the main production site for nearby fields like Arran and Fram.
Speaking at the Subsea Expo yesterday, UK Commercial Manager Nina Holm Viste said Shell is eyeing more opportunities to tie-back to Shearwater as part of the plan to prolong the installation’s life.
In December, Shell sanctioned a plan to lay a new pipeline which will reroute gas from Shearwater to the St Fergus terminal in Aberdeenshire, rather than the East Anglia coast.
Analysts said this could make nearby discoveries, which have struggled to reach sanction, more commercially viable.
Jack Allardyce of Cantor Fitzgerald highlighted that the platform could play host to production to the nearby Jackdaw project which has been “mired in development purgatory”.
Speaking at the conference, Ms Viste said: “At the heart of the Central Graben Area plan is Shearwater, a robust host export system.
“The Shearwater strategy is underpinned by the replumb project into FGL (fulmar gas line) and Segal (Shell Esso Gas and Associated Liquids system), and enabled by volumes from Fram, Arran and Columbus. And we also have our eyes on the other tie-backs too.
“This, together with the renewed longevity of Shearwater itself, will enable a true MER outcome for the Central Graben.
“I am proud to say that Shell UK in 2018 took three FIDs in the Shearwater area. This was Shearwater re-plumb, the Fram development and the Arran development. We also enabled the Columbus JV to make their own FID decision.
“In addition we matured the Peirce depressurisation project, and we made a host select decision on Jackdaw. Final investment decisions on these projects are anticipated this or next year.”
Why not “A Common Understanding”? Well, because when it comes to cost sharing, a common understanding is all too rare.
The contribution of well-established processes considered industry-standard and clearly understood by participants to efficient operations is undeniable. And there are many good examples in an industry characterised by complex commercial arrangements and relationships. But equally, many companies think that they can do better and develop their own processes, which a few of them, arguably the minority, may well achieve.
The sharing of costs has been a feature of the oil and gas industry for many years and therefore we expect to see these well-established, clearly understood processes. So why choose to write about it now?
There are two principal reasons why this is more relevant than ever. Firstly, collaboration, which undoubtedly brings efficiencies in operations but requires the sharing of resources and cost. Secondly, as production from mature assets declines, many commercial arrangements switch from a complex tariff model to a “simple” cost share as the tariff based on production or throughput no longer covers the cost of the treatment, processing and transportation.
Now “cost” is a simple principle but when some costs are included in or excluded from a cost pool, and there are options for the basis of the allocation to activities driving cost, there is ample room for the simple principle to become a complex practice requiring many subjective decisions. And this only works when all the costs are in the right place.
Whether you’re working with a new agreement or an older one, which was produced on a typewriter, there is often a disconnect between the legal or commercial intention and the practical accounting application of that intention, not just between the parties to the agreement but sometimes between different functions in the same business. Not so much a common understanding as a lack of understanding. The broad principle of activity driving cost often loses something in translation.
In the world of upstream accounting and finance, there is a set of standard procedures, the appropriately named Standard Oil Accounting Procedures (SOAPs). These were developed by respected industry professionals, originally to narrow the diverse range of accounting practices within the industry. And whilst they are not mandatory, they are used extensively, particularly in areas where costs are shared by ventures. So let’s make use of the tools at our disposal.
Of course, the best way to avoid disagreements or disputes is clarity in drafting agreements. Precise definitions, clear principles supported by examples and calculations of costs eligible or ineligible for inclusion in cost pools are a good start. Great in theory and both desirable and possible when new agreements are drafted, but companies often find themselves working with older agreements where today’s practices perhaps weren’t foreseen.
A little transparency can go a long way in overcoming our natural suspicion. If the objective is to forge truly collaborative relationships and build trust, why wouldn’t you? Some costs are by their very nature confidential or opaque, or even both – for example payroll costs. Audit rights can bring some assurance, but they are not a substitute for engagement at the right time, both by operators and their partners.
Which brings us back to the SOAPs. The SOAPs provide a well-established framework or guidelines for the allocation of shared costs. Use them. Be transparent. Be fair. But, importantly, challenge at the right time. The benefit of the SOAPs is that they are widely recognised and understood, and the principles are clear. Of course, there are grey areas where there are disagreements. But there will be fewer of them if processes are applied fairly consistently across the industry for many years. And if the guidelines don’t cover a situation, ask, discuss and clarify how the procedures adopted meet the general principle or intent.
Ian McPherson, Joint Venture Audit Director at Anderson Anderson & Brown LLP
The crude market had its worst quarter in four years but you wouldn’t be able to tell by looking at Big Oil’s stellar earnings numbers.
The world’s five largest publicly traded oil companies exceeded analyst expectations, in some cases obliterating them. The result lends credibility to what they’ve been saying: that they’ve been disciplined, focusing on the lowest-cost barrels which can churn out profits even during incredible market volatility.
“People are waking up to the fact that these companies can operate with a low oil price,” Christyan Malek, an analyst at JPMorgan Chase & Co., said by phone. “We continue to stay bullish on the group.”
Here are the five biggest takeaways from the 2018 earnings season:
1. Cash is king
If there’s one thing Big Oil has learned to excel at, it’s generating mounds of cash. The whole sector became bloated in the years leading up to 2014, as higher and higher crude prices made even ultra-expensive, over-engineered mega-projects look profitable.
Investors punished that short-sighted view, and have continually pressured companies to get lean. As a result, oil majors are focused on barrels that require lower operating and capital expenditures. At BP Plc alone, the company said it cut upstream costs by 45 percent. The result was the highest cash-generating quarter for the five largest oil majors since 2011, which will be used to buy back shares, cut debt and start more high-quality projects.
2. Less focus on reserves
In the old days, the only figure that really mattered to oil companies was the reserves number, and it could be career-ending for a chief executive officer to allow oil fields to deplete without replacing them with as many, or preferably more, new barrels.
The view today is more mixed. While investors rewarded Exxon Mobil Corp. for replacing all of its reserves in the fourth quarter while also turning around falling output, they pushed Royal Dutch Shell Plc shares up when the company said it had only replaced about half its reserves. Chief Financial Officer Jessica Uhl said in an interview on Bloomberg Television that she wasn’t worried about the figure at all: “We’re focusing on growing value and growing our cash flow.”
In the fourth quarter, that attitude was on display. Production fell and investors shrugged it off, as the sector made clear it can do more with less.
3. Downstream holds its own
Downstream was the saving grace of the sector when crude prices collapsed between 2014 and 2017. Refineries got oil cheaply, making it less expensive to turn it into products such as gasoline or diesel.
Companies weren’t as reliant on that division in 2018, since oil prices rose through most of the year, but remained strong through the last quarter, helping the five largest oil companies exceed analyst estimates. Chevron Corp. is the only firm that churned out less in the downstream segment than at the start of 2014, when oil was trading at more than $100 a barrel. The decline was due to divestments in Canada and South Africa as well as expenses associated with maintenance in the U.S., CFO Pat Yarrington said.
4. Debt starts to ease
Buying low and selling high is always a good idea, and some companies, such as Total, piled on the debt to snap up assets during the downturn. As free cash flow ratchets up thanks to companies’ “capital discipline,” they are actively de-leveraging. The move may give them some extra dry powder to buy more production in the future.
The notable exception is BP. The British oil major’s net debt is at its highest level in at least a decade; a combination of a $10.5 billion purchase of U.S. shale assets and the continuing financial burden of making payments for the deadly 2010 Deepwater Horizon catastrophe.
5. Average return ratchets up
Little else makes investors grumpier than wasted capital. And companies acknowledged they did go a bit too far in spending on projects that were ultimately not that profitable in recent years.
Now they’re focused on increasing their average return on capital employed again. European majors Shell, BP and Total all broke out annual figures to show how returns are improving.
Nigeria is the largest economy in Africa and one of the most popular sub-Saharan states to have received foreign investment from European, US and Chinese investors over recent years. It is one of the world’s larger oil producing countries, with daily production of nearly two million barrels, more than twice that of the UK. It has been a member of the Organisation of Petroleum Exporting Countries (OPEC) since 1971.
Nigeria’s economy is heavily oil-dependent, with some statistics putting it as high as two thirds of the government’s income, generated by the petroleum tax regime and the activities of the Nigerian National Petroleum Corporation (NNPC).
The current practice for the award of concession rights is for oil and gas companies to enter into an auction for a production-sharing contract (PSC) with NNPC. NNPC has a number of joint ventures involving foreign investors, including Shell, Chevron, Total, Exxon and Eni.
Aside from the industry-standard co-venturing approach, Nigeria also receives investment in the form of loans. One of the key issues for this form of investment centres on the fact that Nigeria had a debt to the World Bank of around $8.5 billion as of summer 2018.
When providing loans, the World Bank does not seek security from governments who borrow from it but protects its position indirectly through the use of a negative pledge clause (Clause 6.02 of the World Bank’s “General Conditions”). The provision turns on two defined terms in particular:
l Lien – mortgages, pledges, charges, privileges and priorities of any kind;
l Public assets – assets of the member country, of any of its political or administrative subdivisions and of any entity owned or controlled by, or operating for the account or benefit of, the member country or any such subdivision.
The provision seeks to prevent foreign investors from receiving security from the government in priority to the World Bank, by providing that any Lien over public assets in respect of a loan “which will or might result in a priority for the benefit of a creditor in the allocation, realisation or distribution of foreign exchange” shall equally and rateably secure amounts payable by the member state to the bank.
It is clear on this language, and from the practice in Nigeria, that the above restriction would apply to loans to NNPC to help it finance new oil and gas developments.
The negative pledge effectively prevents “standard” project development financing by oil and gas investors as it inhibits the ability to take a “typical” level of security.
The breadth of the pledge and the severity of consequences for its breach are sometimes seen as being counter-productive, as they have the effect of preventing long-term investment for growth.
The government of Nigeria and NNPC are not able to grant security to lenders unless such security also secures the loans from the World Bank. This is even the case where the purpose of the loan is to develop a project, and to generate petroleum revenues, which, but for the loan, would not have existed.
However, there are ways in which lenders can structure their financing arrangements to accommodate the negative pledge.
One such method is to use a forward sales arrangement, whereby the loan made by the foreign investor is made to a (non-state owned) special purpose vehicle (SPV). The SPV agrees to use the
investment to purchase oil from NNPC under a long term sales agreement. The SPV then sells that oil to NNPC-approved off-takers and the cash from such sales is used to reimburse the investor.
The investment landscape is a dynamic one. A general election is due to take place on February 16, 2019 to elect the President and the National Assembly.
A leading opposition candidate to replace the incumbent President, Atiku Abubakar of the Peoples’ Democratic Party, is widely reported to be planning to break up and privatise NNPC and to re-negotiate production-sharing contracts with multinational oil companies.
If Mr Abubakar is elected and is successful, privatisation would likely see the World Bank negative pledge become less of a concern for players in the industry and thereby open the door for more “conventional” forms of project development finance, although on what terms we will have to wait and see.
The achievements of a group of mentors and their mentees in the oil and gas industry have been celebrated at an awards ceremony in Aberdeen.
Eighteen project managers from a number of Aberdeen-based firms completed the Oil and Gas Industry Project Management Mentoring Programme, co-ordinated by the Engineering
Construction Industry Training Board (ECITB).
The six-month scheme allows qualified and experienced project practitioners to impart wisdom and provide guidance to less experienced project professionals with the aim of accelerating their performance and careers. To date, almost 50 participants have benefited, many of whom are working towards chartered status with bodies such as the Association for Project Management.
Evidence shows that while technical skills can be learned online or in a classroom, behavioural and leadership skills can be enhanced via mentoring so, in 2014, ECITB and the Offshore Project
Management Steering Group (OPMSG) set up a pilot scheme to mentor 14 young oil and gas professionals from the Aberdeen area.
It has attracted interest as a blueprint from across the country and other parts of the engineering construction industry, such as nuclear decommissioning.
A number of others successfully completed the Association for Project Management’s Registered Project Professional (RPP), a pan-sector standard for those able to demonstrate the capabilities of a responsible leader with the ability to manage a complex project.
Chris Claydon, chief executive of the ECITB, said: “The delivery of projects to world-leading standards is vital to the future well-being of the oil and gas sector.
“Our project management mentoring programme shows how industry can put aside commercial interests to co-operate for the benefit of the sector as a whole.
“The ECITB is proud to support this and the other project management development programmes that the OPMSG is leading.
“The learning and experience from oil and gas is highly transferable to other sectors and, following the success of this scheme, we are rolling out similar programmes across other sectors.”
Westwood Global Energy reports that at the end of January three exploration wells were drilling on the UKCS: one in the northern North Sea and two in the central North Sea.
The announcement by partners Total and CNOOC on January 29 regarding the Glengorm discovery with estimated resources close to 250 mmboe is headline news, the last discovery of this size being Culzean in 2008.
The rig is still on location but likely to complete soon.
West of Shetland
There is no current E&A drilling in west of Shetland.
Northern North Sea
Equinor spudded its Bigfoot exploration well on January 22 and then re-spudded the well as 9/22a-4A on January 25, presumably for mechanical reasons. The well is a firm commitment with partner BP and is targeting Triassic prospectivity in the Lewis Formation. The well is the first of three wells in a back-to-back campaign in the UK that will utilise the West Phoenix rig.
Central North Sea
CNOOC’s Glengorm exploration well 22/21c-13 was spudded on August 26, 2018 and announced on January 29 as having made a significant gas-condensate discovery in the target Upper Jurassic reservoir, reaching a total depth of 16,588ft. The reservoir was found to be high quality and with 123ft of net pay. Partner Total has reported resources to be close to 250 mmboe, which would make this the largest discovery to be made in the UK since Culzean in 2008.
On December 30, Eni spudded exploration well 22/19c-7 on the HPHT Rowallan prospect with the Ensco 121 rig. It is targeting pre-drill resources of c. 133 mmboe in the Triassic and Middle Jurassic within a fault block structure, analogous to the Culzean field.
Corallian’s Wick exploration well encountered the Beatrice sands reservoir at a depth of 3,063ft, however, these were water-bearing and the well was abandoned as a dry hole at a total depth of 3,281ft MD. The key risk was containment and it is expected that this was the cause of failure.
The rig has now moved to drill the operator’s 98/11 Colter appraisal well in the English Channel.
Southern North Sea
Neptune spudded the 44/12b-7 Fault Block 9 exploration well on October 29 with the Ensco 101 at a location north-east of the operator’s Cygnus field. The well was then abandoned earlier than expected on December 18. The short duration suggests it failed to find commercial gas resources in the target Carboniferous reservoir.
Students from across the north-east got firsthand experience of working in the energy subsea sector yesterday.
A hundred young people from across Aberdeen and Aberdeenshire got to see how deepwater North Sea jobs ebb and flow as they toured a technology focused Subsea Expo 2019.
Part of Opito’s Energise Your Future (EYF) event at the Aberdeen Exhibition and Conference Centre (AECC), high school student’s met with 13 firms as part of a busy Subsea Expro programme.
Marine engineering firm EC-OG offered pupils the chance to use its latest virtual reality technology, transporting them below the waterline to inspect its Subsea Power Hub (SPH) and battery equipment.
Students also got a chance to meet with North Sea-focused firms JFD, Nortek UK, ORCA Hub, Rovco and Tritech.
Louise Brodie, a 16 year-old student from Albyn Sxchool in Aberdeen, said: “I’m interested in engineering already so this event has given me a much better idea of what these companies do and what would be expected of me if I go into the oil and gas industry.
“I’m quite interested in diving jobs as I enjoy things that’re hands-on.”
Fellow student Harris Macdonald, also 16, added: “I liked the machinery and how you make the most of energy where you can.
“I do computing and engineering at the moment but some of the coding aspects relate to some of the stuff we’re already learning in school.”
John McDonald, Opito chief executive, said: “As more and more oil and gas companies embrace new techniques such as virtual reality and artificial intelligence, it is important that young people see and hear first-hand what the future of the industry looks like and the vast and exciting opportunities these developments present to them.”
“Attracting young talent remains a key focus for the sector.
“The recent OPITO UKCS Workforce Dynamics Review showed that if the sector achieves its ambitions set out in Vision 2035,40,000 people will need to be recruited over the next two decades.
“Around 10,000 of those are expected to be in roles that don’t yet exist.”
It is a well-proven maxim that discovering oil can be more of a curse than a blessing and nowhere on the face of the Earth offers better testimony to that than Venezuela, now in the throes of political upheaval.
The prize at stake is a wrecked economy, mass emigration, terrible poverty and an oil industry which is in chronic need of investment in order to stagger on, far less fund any kind of recovery.
Hard to believe that this is the country with the world’s biggest proven oil reserves.
Of course, much of the immediate fault can be attributed to the disastrous government of Nicolas Maduro and even more to his predecessor as president, Hugo Chavez. It is too conveniently simplistic, however, to lay all responsibility at their doors for Venezuela’s problems go back far further than that.
I first visited the country as trade minister almost 20 years ago in the early days of Chavez’s rule. It is worth remembering the circumstances in which he came to power. Parts of the country had been hit with flooding and so feeble were the hovels which clung to the hillsides that 30,000 people died as a result.
It was an episode which crystalised the great Venezuelan enigma.It had been an oil-rich state for three-quarters of a century yet the social and economic infrastructure of the country was an absolute disgrace.
While a wealthy elite flew back and forth between Caracas and Miami, the vast majority of the people lived in poverty. It was they who voted for Chavez, a Bolivarian populist who promised change.
By the late 1930s, Venezuela had become the world’s third biggest oil producer and also the number one exporter. However, it was already suffering from “Dutch Disease”, the curse of many oil-rich economies.
The first stage is for other industries to fall by the wayside – most critically agriculture. Then the strength of an oil-based currency makes importing expensive.
Venezuela has had 80 years of these chronic ailments with high oil prices the only intermittent remedy. The oil industry was nationalised in 1976 and the state company, PDVSA, became a major player globally as well as dominating the domestic economy. It was a generally well run company but increasingly wanted to invest the wealth it generated rather than hand it over to the government for social programmes.
Chavez railed against PDVSA as a “state within a state” which is a common charge against such companies. He drove out the competent management and replaced it with his own people who knew little or nothing about running an international oil company.
At the same time, he syphoned off increasing shares of oil revenue for social programmes and aid to other poor countries. There is no doubt that this was transformational for the lives of many poor Venezuelans and also beneficial to regional allies, notably Cuba with whom Chavez ran a vast “oil in exchange for doctors and teachers” trade.
As long as there was money to fund these programmes, they ensured Chavez of enough popular support to win elections and, in 2002, to successfully resist a Washington-sponsored attempt at a coup.
But the warning signs were not hard to find. A decade ago, I gave some assistance to the Scotch Whisky industry which was trying to stave off the attentions of the Chavez government.
Incredibly, Venezuela was the fifth biggest market for Scotch in the world but Chavez had taken to denouncing it as the “drink of the oligarchs” and demanding that patriots should drink rum instead.
By that time, it was pretty apparent that the country was on a one-way ticket to disaster and also to authoritarian rule. Oil production in the traditional fields around Lake Maracaibo was in sharp decline.
The big hope lay in exploiting the vast resources of heavy oil in the Orinoco basin where necessity had dictated the involvement of foreign companies to invest alongside PDVSA. However, time was not on Venezuela’s side and it might be said that Chavez got out just in time by dying in 2013. By then, the price of oil was in sharp decline.
His anointed successor, Maduro, had to deal with the fall-out – a role for which he was singularly ill-equipped. The past five years have seen a rapid acceleration in poverty, hyper-inflation and emigration.
It would be naive to doubt that the Americans have worked night and day to destabilise the country from the day Chavez was elected.
In Latin America, that remains a “given” whenever any leftist government raises its head. But that alone cannot be blamed for the chaos that now exists and which threatens to destabilise neighbouring countries.
Maduro has looked increasingly to China and Russia for support and they both have strong interests in what happens next – as well as very large debts to collect.
What would once have been seen by the rest of the world as a disturbance within America’s “backyard” is now caught up in much wider geopolitics even if everyone agrees that “something has to be done” on humanitarian grounds, let alone economic ones.
Ideological point-scoring will not do much good for the poor Venezuelan people. For a brief period, they voted for a government which offered the prospect of radical change only to see their hopes dashed by forces far beyond their control – falling oil price – allied to the incompetence of politicians in whom they had placed their trust.
The fact remains that Venezuela has the largest confirmed oil reserves on our planet. It should not have been beyond the wit of man, over the past century, to exploit them in a way that created benefits for the whole society to share in. For Venezuela and many other oil-rich countries, that remains the elusive prize.