Author: Paul Harris

UK oil and gas deals around US$6bn in H1 2017

Around US$6 billion in M&A activity involving UK oil and gas companies has taken place during the first half of 2017 – with more activity predicted for the remainder of the year and into 2018.

Total’s recent deal to acquire Maersk Oil & Gas A/S heads the list of deals involving North Sea assets this year, according to Evaluate Energy M&A data.

Source: Evaluate Energy M&A Database

Assets changing hands and the increasing diversity in their ownership suggests that the UK Continental Shelf may start to benefit from a badly needed investment boost, according to the findings of an annual economic report authored by Oil & Gas UK.

“There are still serious issues facing our industry which has suffered heavy job losses since the oil price slump,” said Deirdre Michie, CEO of Oil & Gas UK. “But we are hopeful that the tide is turning and expect employment levels to stabilise if activity picks up.”

The report says low levels of exploration and appraisal activity remain a serious concern with drilling at record lows. Oil & Gas UK said the basin needs further capital investment, as only three new field approvals have been sanctioned since the start of 2016.

Additional report findings:

  • The cost of lifting oil from the North Sea has almost halved since 2014 – this improvement to unit operating cost is greater than improvements achieved by any other basin
  • Production has increased by 16% since 2014 – driven by production efficiency improvements, brownfield investment and new field start-ups
  • Changes to the tax regime have helped create one of the most competitive fiscal regimes for upstream investment globally

Click here to learn more about EE’s database of M&A deals.

PSAC launches 2017 Well Cost Study in new digital format


CanOils JWN Energy Logo

Today, the Petroleum Services Association of Canada (PSAC) and JWN announce the launch of the 2017 PSAC Well Cost Study in a new digitized format, offering users a fully customizable database to compare well costs in more than 150 categories.

The Study provides financial, geological and technical data, plus detailed wellbore graphics for each well, allowing users to quickly review detailed estimates for Canadian drilling and completion costs.

PSAC President and CEO Mark Salkeld said: “The Study is an essential tool for producers, development planners, drilling/completions engineers and petroleum service companies. Well costs are assembled by independent drilling experts and include approximately 50 typical wells drilled across Canada, detailed wellbore graphics for every representative well, plus data on more than 100 drilling and completion cost components.”

Bemal Mehta, Senior Vice-President Energy Intelligence at JWN, said: “The PSAC Well Cost Study is a dream come true for engineers and other professionals who spend hours manually putting together Authorizations for Expenditures (AFEs) for drilling and completions programs. Now they have access to digital data that is fully searchable, comparable and customizable and we guarantee the PSAC Well Cost Study will provide you with the most accurate drilling and completions estimates in the business – it’s data for professionals prepared by professionals.”

Among the key benefits of the new digital format:

  • Customizable cost comparisons on typical well costs
  • Quickly build cost estimates for development planning
  • Anonymously acquire drilling and completion costs
  • Benchmark by PSAC region, formation of interest, well type, completion style
  • Download data to Excel in a familiar Approval for Expenditure (AFE) format

Since it was first published in 1981, PSAC’s Well Cost Study has been released twice a year in order to recognize changing costs between summer and winter drilling activity and related expenses. Previously the data was available in PDF format only. By partnering with JWN, the data is now organized in a fully searchable database containing current and historical costs in each category.

“Going digital will significantly increase the Study’s value,” added Salkeld, “as it will continue to capture seasonal changes in costs and enable users to customize reports across different formations, at different times of the year, for much more effective reporting results. PSAC works hard to provide the most current ‘typical’ well costs and this tool will keep this significant report on the leading edge for years to come.”

The new study is powered by Canoils, a leading provider of financial and asset-level oil and gas data for the Canadian market. The PSAC data neatly complements the existing information found within Canoils’ database. Prices for the 2017 PSAC Well Cost Study data start at $3,500. Discounts are available for PSAC members. For more information, click here.

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About JWN

For more than 75 years, JWN has provided trusted energy intelligence. Our energy professionals provide the information, insight and analysis organizations need to stay informed and understand what’s happening in the energy industry. JWN provides a range of products and services to help companies gain the insights they need to stay competitive including industry and company benchmarking, custom data sets, market intelligence, custom intelligence and outlook reports, integrated marketing solutions, and events and conferences. JWN’s flagship products include the Daily Oil Bulletin (DOB), Oilweek and the Comprehensive Oilfield Service and Supply Directory (COSSD).

About Petroleum Services Association of Canada (PSAC)

The Petroleum Services Association of Canada is the national trade association representing the service, supply and manufacturing sectors within the upstream petroleum industry. PSAC is Working Energy and as the voice of this sector, advocates for its members to enable the continued innovation, technological advancement and in-the-field experience they supply to Canada’s energy explorers and producers, helping to increase efficiency, improve safety and protect the environment.

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Analysis of LLR impact in Canada’s largest 2016 M&A deal

A new case study has been created that analyzes changes to Licensee Liability Ratings following Canada’s biggest oil and gas M&A deal of 2016.

LLR programs ensure costs to suspend, abandon, remediate or reclaim a well, facility or pipelines are not borne by the public if a licensee becomes defunct. To fulfill LLR regulations, the value of an operator’s ongoing assets must outweigh any abandonment/reclamation costs.

LLR also impacts M&A deals. Before permitting the completion of a deal, provincial regulators must be satisfied that a deal will not take the acquirer or seller below the specified provincial LLR thresholds. Using LLR data, which is now a standard feature in every CanOils Assets subscription on a well-by-well basis, can help you make sure your M&A deal is safe from this happening.

This new case study provides an analysis of Seven Generation Energy Ltd.’s acquisition of Montney lands and wells from Paramount Resources Ltd. for Cdn$1.9 billion. It estimates the impact this deal had on both companies’ LLR positions, and offers useful insight for potential buyers and sellers of assets.


Click here to download free the 4-page case study.

Book a Demo:CanOils Assets LLR & Suspended Well Data

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How we’re using LLR well data to assess Canadian oil and gas producers


New tools have been developed to help Canadian oil and gas producers measure more easily the impact of LLR regulations on well operations and potential asset deals.

Recent changes in Alberta to how the Licensee Liability Rating is applied bring into focus the importance of these regulations in an economy where assets may be under threat.

You’re likely aware that LLR programs ensure costs to suspend, abandon, remediate or reclaim a well, facility or pipelines are not borne by the public if a licensee becomes defunct. To fulfill LLR regulations, the value of an operator’s ongoing assets must outweigh any abandonment/reclamation costs.

We’re using a new tool that allows us to quickly calculate the LLR for individual and clusters of wells. The CanOils Assets LLR data, a new standard addition to every CanOils Assets subscription, also allows us to easily measure how a potential asset purchase or sale could alter a company’s LLR position.

Book a Demo:CanOils Assets LLR & Suspended Well Data

CanOils Assets LLR data includes deemed assets and liability estimates for wells in Alberta, Saskatchewan and British Columbia. This degree of data transparency is excellent for business development and the service and supply sector. We’ve been using the data for pro-forma analysis of M&A transactions and to identify companies in need of abandonment or reclamation services.

For a more detailed look at how the CanOils Assets LLR data can benefit business development, click here for a short case study, which includes pre- and post-transaction LLR estimates for Canada’s biggest deal of 2016.

We’ve also been reviewing the CanOils Corporate LMR Summary module. This module delivers the LMR ratio for all companies as reported by each provincial regulator (AB, SK, BC). For SK, this includes the value of any security deposits provided. Importantly from a business development perspective, the tool can help us find companies whose LMR ratios may be problematic. We’ve found this data especially useful in conjunction with our regular financial reporting. To learn more, click here.

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U.S. oil and gas production growth stalls as companies cut cap-ex by 57% since 2014

Dramatic shifts have taken place in the way U.S. oil and gas operators view cash flow, capital expenditure (cap-ex) and market risk – with companies closer today to being able to fund cap-ex plans with only their operating cash flow than at any point since the price downturn began.

U.S. oil and gas companies spent 57% less in cap-ex in Q2 2016 compared to the end of 2014 on a rolling 12 month basis – and this is finally having a material impact on production. That is one of the key findings of a far-reaching study of cash flow trends for 68 U.S. oil and gas companies by Evaluate Energy.

The study examines the size of the financing gap that exists between a company’s operating cash flow and its cap-ex spending. This gap varies very significantly, depending on the size of company and location of its production, and this large cut in cap-ex is undoubtedly a key driver of falling financing gaps in more recent periods.

Click here to read the full report.


Source: Evaluate Energy Study – Cash flow in U.S. Oil & Gas

The size of the internal financing gap is crucial, not least because it determines how far each company is able to fund cap-ex via after-tax profits and conversely its level of reliance upon external cash to fund development plans. It also provides a gauge of company confidence – and, crucially, it points to how far benchmark prices would need to rise to ensure a company could entirely fund cap-ex using just operating cash flow.

The sharp cut off in cap-ex over the past two years is finally starting to bite on production. Cap-ex has been cut across the board since the end of 2014. While production trended upward from 2013 for a few quarters into 2015, we are now starting to see the rate of growth decline. While Q2 2016 production is around 40% higher than Q1 2013, it is similar to Q1 2016.


Source: Evaluate Energy Study – Cash flow in U.S. Oil & Gas

“This production plateau does not bode well for near-term cash flow growth, assuming there is no sudden and significant recovery in commodity prices,” said Mark Young, senior analyst at Evaluate Energy. “Cash from operations will fall if production begins to drop, and this could lead to further cap-ex cuts.”

The Evaluate Energy study provides analysis on pricing per region based on an analysis of 68 representative U.S. oil and gas companies within its coverage of all U.S. stock exchange-listed operators.

“U.S. oil and gas companies are moving closer to being able to fund cap-ex plans with only operating cash flow than at any point during the past three years,” said Young. “But relatively smaller producers have a much greater reliance on externally sourced cash with greater financing gaps than larger producers.”

Click here to read the full report, which also studies the varying financing gaps between Bakken, Marcellus and Permian Basin producers.


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Why Europe is pivotal to LNG growth

Europe will play a pivotal role in the performance of LNG markets globally amid ongoing concerns over gas over-supply, reduced demand in some quarters and pressure on prices.

The major question remains the extent to which Europe can absorb increased gas volumes as part of goals to de-carbonize economies, promote renewables, ensure pricing remain competitive, safeguard energy security and deliver diversity of supply.

Monika Zsigri, an energy policy officer with the European Commission, confirmed that as EU domestic gas production decreased, net EU gas imports increased by 11% last year. LNG shipments bound for Europe rose 6%, as did LNG’s share of the imported gas mix, to 13%.

Qatar remains the largest supplier of LNG to Europe, with a 56% market share, followed by Algeria and Nigeria. While the direct impact of U.S. LNG has not been significant in Europe, it is putting downward pressure on prices. “There is a lot of gas in the market, and the market is fairly flat in Asia,” Zsigri said at the LNGgc Conference in London this week.

LNG import capacities are set to increase dramatically in several European countries by 2025, notably in the United Kingdom, France, Ukraine, Poland, Greece and Croatia, according to Evaluate Energy data.


Source: Evaluate Energy (see note 1)

Costanza Jacazio, a senior gas analyst at the International Energy Authority, expects demand to stabilize in Europe followed by a gradual recovery due in part to retiring coal and nuclear plants. But she said the global rebalancing of markets would depend on the pace of expansion in China, together with other developing Asian nations.

“Japan and Korea will play a much less important role in absorbing new LNG production coming onto the market [in the next five years],” she said. “This means the rest of the world needs to take this incremental LNG.”

Carmen Lopez-Contreras, a senior analyst on Repsol’s gas and power team, said declining European power production (for example in the United Kingdom and the Netherlands) and the need to retain gas supplies while countries adopt more renewable energy solutions will bolster gas demand.

“We have a lot of new volumes coming on-stream,” she said. “Demand has not coped with our expectations. Traditional buyers [like Japan and Korea] have not demanded as much LNG as we are used to. They have turned to coal, which is cheaper. Right now we are at the very bottom of gas prices, but this is incentivizing demand.”

Pricing, volume and destination flexibility will be high on the agenda for buyers facing greater uncertainty and volatility in demand.

“It is very likely markets will struggle to absorb incremental supplies,” said Armelle Lecarpentier, chief economist, CEDIGAZ, the international association for natural gas.

She believes the United States is on track to take the role of swing supplier, adding that the trajectory of global gas markets, and the pace of any market rebalancing, will rest strongly on demand in China and developing Asian nations. She sees this flexible LNG going to new importers in South East Asia, South Asia, North Africa and Latin America. She feels the rise of renewables and increased energy efficiency will temper additional European demand.


1) Proposed import capacity for end 2025 is calculated assuming that all currently active import terminals remain in operation and all proposed projects, regardless of current status, reach completion at their respectively scheduled onstream dates.

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Do We Need to Re-think UK Energy Policy?

New inquiry to examine technologies and pricing

The future shape of the UK’s energy market – including sources of domestic supply and pricing strategies – is subject to a new inquiry launched last week.

Led by the House of Lords Economic Affairs Committee, the inquiry will assess whether a combination of policy and subsidies have led to failures in the energy market, and what new action may be needed.

“Coal power stations are being closed and old nuclear stations are coming towards the end of their life,” said committee chair Lord Hollick. “But it is not clear how they will be replaced and at what cost.”

The inquiry centres on the premise that UK energy policy over the last decade has focused on three objectives: maintaining supply and minimizing threats to energy security; keeping supply costs competitive for businesses and consumers users; and, de-carbonization, sought primarily by closing coal-fired plants and offering subsidies to renewable energy infrastructure.

According to a House of Lords release yesterday, a report by the committee two years ago into the economic impact on UK energy policy of shale gas and oil concluded that there had been a lack of clarity and consistency in energy policy over many years.

“This failure of policy had left the UK dangerously close to lacking sufficient electricity generating capacity,” said Lord Hollick. “Over two years later, little has changed.”

The UK, with its history of offshore production, was a net exporter of oil, natural gas liquids and gas until 2005. Since that time, the UK has been reliant on overseas imports to meet domestic demand.


Data from our Evaluate Energy team confirms that in the past decade that disparity has been greatest in 2013, when the UK imported 1.2 million boe/d more than it exported. In 2015, that figure was 1.05 million boe/d.

UK oil/NGL/gas production has declined every year since 2000, when it stood at 4.45 million boe/d, to 1.44 million boe/d in 2014. It increased slightly in 2015, to 1.6 million boe/d.

The committee will seek to identify emerging technologies that could materially alter the UK energy market over the next decade and beyond.

This will likely include discussion over the role played by on-shore shale gas and other alternatives. Earlier this year, former UK energy minister Andrea Leadsom described shale gas as an effective potential “bridging fuel” amid goals to reduce reliance on coal while seeking alternative future power supplies. She viewed shale as a homegrown solution that could create thousands of jobs during development and production.

Lord Hollick added: “The energy market involves an extraordinarily complicated mix of policy interventions and subsidies. Every investment in electricity generating supply is effectively determined by the government. This inquiry will seek to investigate whether current policy is delivering the best deal for energy users and whether it is striking the correct balance between private and public sector involvement.”

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Brexit latest: Disentangling energy policy after UK votes to leave EU

UK energy policy has become rather entangled in the dramatic reorganization of government that has taken place since the nation opted out of the European Union.

It’s barely a week since Theresa May became the new leader of the Conservative party, and by extension the new Prime Minister.

By all accounts, she’s settled in quickly: a major cabinet reshuffle involving major (and controversial) new roles for Brexit campaigners, early talks with Scotland’s first minister in view of Scotland’s significant pro-EU support, and preparations for meetings with German and French leaders this week.

She’s also found time to replace the Department of Energy and Climate Change (DECC) with a larger, more extensive and over-arching Department for Business, Energy and Industrial Strategy (BEIS).

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There are two broad schools of thought about whether the switch is a good thing. One is that it is sensible to tie the energy needs of the country ever more tightly with business and industrial development. The flip side is concern that climate change – as an agenda issue – will slide down the priority list, subsumed by pressing business and industrial growth demands.

The creation of the new BEIS department has divided opinion between political groups and environmentalists.

Greg Clark will lead the new department. Under the reshuffle, government energy lead (and recent contender for Prime Minister) Andrea Leadsom becomes environment secretary.

Prime Minister May gave us some clues to her energy priorities at the launch of her national campaign to become Tory leader last week, where she spoke of the need for an energy policy “that emphasizes the reliability of supply and lower costs for users.”

The UK, with its history of offshore production, was a net exporter of oil, natural gas liquids and gas until 2005.

Since that time, however, the UK has been reliant on overseas imports to meet energy needs.

Data from our Evaluate Energy team confirms that in the past decade that disparity has been greatest in 2013, when the UK imported 1.2 million boe/d more than it exported. In 2015, that figure was down slightly, at 1.05 million boe/d.

Overall UK consumption of oil/NGL/gas peaked in 2005, at 3.5 million boe/d. It has declined virtually every year since, and stood at 2.6 million boe/d in 2015.


Source: Evaluate Energy


Source: Evaluate Energy

Meanwhile, our data confirms that UK oil/NGL/gas production has declined every year since 2000, when it stood at 4.45 million boe/d, to 1.44 million boe/d in 2014. It increased slightly in 2015, to 1.6 million boe/d.

Prime Minister May’s tone feels very much in tune with the former DECC list of energy priorities, where security of domestic energy supply ranked very high indeed.

Earlier this year, as energy minister, Leadsom reinforced the need for UK energy security. She was addressing the Shale World UK conference, which focused upon the potential for on-shore UK shale gas.

Leadsom positioned shale gas as an “effective low-carbon bridge” amid broader goals to reduce the nation’s reliance upon coal and secure alternative future power supplies. She viewed shale as a homegrown solution that would in turn create many thousands of jobs during development and ongoing production phases.

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Nigeria’s Oil Export Woes, Attacks on Majors and Why Merger Deals have Virtually Halted

Oil production has fallen dramatically and acquisition deals have ground to a virtual halt so far in 2016 in Nigeria, as the country continues to grapple with militant attacks on energy installations.

The concerns over export levels centre on oil installations in the Niger Delta that have been repeatedly targeted in recent months, creating significant unrest and threatening oil export volumes.

It hardly needs stating that energy production and exports are absolutely pivotal to the health of the economy of Nigeria, where several major international operators have significant stakes. Glacier Media’s Evaluate Energy data indicates that ExxonMobil produced 297,000 barrels a day (b/d), Royal Dutch Shell 275,000 b/d, Chevron 271,000 b/d, Total 228,000 b/d, and ENI SpA 132,000 b/d during 2015.

Crude oil production within the troubled West African state has plummeted during the first half of 2016. In May alone, output had fallen by 461,000 b/d when compared to fourth quarter averages in 2015, to 1.42 million b/d. May production was down 251,000 b/d compared to April as the slide continued, according to OPEC’s report on crude oil production from secondary sources.


Source: OPEC Monthly Oil Market Report – June 2016 (Secondary sources)

Among Africa’s OPEC-member nations, the same OPEC data indicates Nigeria lagged behind Angola in terms of year-to-date crude oil production to May. Our Evaluate Energy data indicates that oil exports from Nigeria topped out in 2010 at 2.25 million b/d. With the exception of a small increase in 2014, exports have fallen every year since 2010, and stood at just over 2 million barrels in 2015.

As market uncertainty prevails in Nigeria, merger and acquisition activity has fallen dramatically. According to our 2016 data, so far this year just two deals have been announced. That compares to 13 deals announced in each of the two years prior.

The larger of the two deals in 2016 involved Canadian-listed Mart Resources Inc. (TSX: MMT), which agreed a Cdn$367 million deal (including debt) to be acquired by Midwestern Oil & Gas Company Ltd. and San Leon Energy Plc.

Midwestern had originally considered purchasing Mart in March 2015 – a deal that would have been worth around Cdn$524 million (including debt) at the time. Later that year, Mart was courted by Delta Oil Nigeria BV in a Cdn$394 million deal. That deal, however, was terminated due to deteriorating oil prices. Our Canoils Canadian asset team covered in-depth Mart’s various agreements to sell the company in our usual monthly M&A reviews:

The second Nigerian M&A deal so far this year saw MX Oil plc acquired by GEC Petroleum Development Co. Ltd. for US$18 million.

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While M&A deal-flow has dried up, the activities of a militant group, known as the Niger Delta Avengers (NDA), have continued. The NDA’s demands are varied and are reported to include the ownership structure of oil blocks:

Unrest naturally breeds uncertainty. Production continues, but disruption to operations has been painful:

In the past week, the militants struck again. According to reports, the NDA blew up three manifolds operated by Chevron Corp. The NDA claims to have also blown up a well and pipelines in the country’s southern oil hub:

While efforts are made to tackle the disruption, markets will watch on in hope of a resolution. As a side note, a Nigerian, Dr. Mohammed Sanusi Barkindo, takes the helm as secretary general of OPEC next month: Dr. Barkindo is formerly a managing director of state enterprise the Nigerian National Petroleum Corp.

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New Deal for Oil Workers in Norway Averts Strike Action

Offshore oil production in Norway flowed as usual today after strike action by workers was averted.

Norway’s net oil exports in 2015 averaged 1.714 million barrels a day, an increase of 58,000 barrels compared to 2014, according to data from Evaluate Energy and the BP Statistical Review of 2015.

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The majority-state-owned Statoil (Oslo:STL) is by far the country’s biggest oil and gas producer, with 1.23 million boe/d. The second largest producer is ExxonMobil (NYSE:XOM) at 233,000 boe/d followed by Total (Paris:FP) at 227,000 boe/d. Royal Dutch Shell (LSE:RDSA), ConocoPhillips (NYSE:COP), ENI (Milan:ENI), ENGIE (Paris:ENGI), Centrica Plc (LSE:CNA), BP (LSE:BP) and Det Norske (Oslo:DETNOR) are also in the top 10.


Source: Evaluate Energy

About 7,500 employees working in Norway’s offshore oil fields as either drilling personnel or in catering are covered by a new offshore pay settlement, according to the Norwegian Oil and Gas Association in a weekend statement. The Association said the deal was reached between the Norwegian Union of Industry and Energy Workers (Industry Energy), the Norwegian Union of Energy Workers (Safe) and the Norwegian Organization of Managers and Executives.

“These negotiations have been demanding, with a number of different issues which had to be resolved,” said Jan Hodneland, lead negotiator for Norwegian Oil and Gas.

“Given the demanding position which the industry currently finds itself in, it was nevertheless crucial for us to find a solution which ensured that a strike could be avoided.”

The agreement includes a decision to appoint one or more committees during the period covered by the 2016-2018 settlement, “to assess issues related to time spent offshore, as well as changes to the work plan, workplace and work periods.” This is intended to tackle cost challenges faced by companies covered by the offshore agreements, said the Association. “The expectation is that such mutually binding committee discussions will help to strengthen the competitiveness of the Norwegian continental shelf.”

Need to keep in touch with the oil and gas industry in any country worldwide? The Evaluate Energy country subscription helps you do just that.

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