Author: Paul Harris

North American producers are refocusing on increased shareholder returns with abundant free cash flow evident across the board in Q2 2021.

This is according to Evaluate Energy’s latest review of cash spending patterns for 86 North American oil and gas producers, which can be downloaded at this link and, this quarter, includes data on dividend payments and share buybacks.

“When combining dividend payments and net share repurchases, we can see over US$4 billion spent on shareholder returns by the study group for the first time since the pandemic started in late Q1 2020,” said Mark Young, report author and Senior Analyst at Evaluate Energy. “Things are moving slowly but latest data reveals a renewed, concerted effort by producers to return increased earnings to shareholders.”

A jump from just over US$2 billion in total shareholder returns in Q1 to around US$4 billion three months later may not appear all that gradual – this is because two oilsands producers skew the analysis.

“Imperial and Suncor are alone responsible for 80% of 2021’s total buybacks so far. The data may suggest a sudden jump in spending across the board, but these two companies are an anomaly when it comes to the whole group, at least up to the end of June.

“Where we really see more widespread increases in shareholder returns is in dividend per share data, even if the dollar values fail to jump off the page,” said Young.

As the pandemic took hold, the number of companies declaring a quarterly dividend fell sharply from 29 in Q1 2020 to just 20 in Q2 2020. As well as those nine companies that stopped paying dividends entirely, eight more reduced quarterly distributions as cash tightened.

Q1 and Q2 2021 witnessed a recovery – particularly among oil producers who comprised the bulk of North America’s dividend-paying producers before the pandemic.

• By the end of June, 28 of the study group were paying dividends. Q1 and Q2 both saw 12 companies increase dividends per share from the previous quarter
• Cash used for dividends since the start of Q3 2020 increased by an average of US$276 million per quarter for the whole group.

“This US$276 million increase may seem insignificant when billions are being spent on capital budgets and debt repayments, but individual investors will likely approve,” said Young.

Evaluate Energy’s Q2 2021 cash flow review for North American oil and gas producers is available for download now. The report also includes a look at remaining capital budget levels for 2021 and debt-related spending for all 86 companies.

Europe’s oil and gas majors again led the way in terms of green and renewable energy sector deal-making among oil producing peers in Q2, according to Evaluate Energy’s latest M&A report.

“With the energy transition in mind, traditional E&P companies are heavily engaged in deal-making for renewable projects to diversify portfolios,” said Mark Young, report co-author and Senior Oil and Gas Analyst at Evaluate Energy.

“Over the past few years, intense and consistent investor pressure over carbon usage and climate goals has prompted European producers into leading the way. The usual suspects showed up again in Q2, with BP, Equinor, Repsol and TotalEnergies all featuring in our report thanks to deals covering wind, solar and electric vehicle sectors.”

Evaluate Energy’s quarterly M&A report expanded in Q1 to include a review of green and renewable energy sector deals by companies historically associated with oil and gas production. The Q2 report is now available to download free here.

The report includes details of:

• BP and Repsol deals for U.S. renewable sector projects
• BP’s second electric vehicle-related deal in as many quarters
• Three separate Equinor deals, including a solar power acquisition in Poland
• TotalEnergies’ wind farm deal in Taiwan

The report also includes the usual rundown of this quarter’s major upstream oil and gas deals. A total of $35 billion was spent in Q2 in a series of multi-billion-dollar U.S. mergers.

An average of 1.5 million bbl/d were hedged by North American oil producers heading into 2021 in fixed swaps, collars and three-way collars, according to a new Evaluate Energy report on hedging activity and the extent to which companies gained or lost out as per-barrel values stabilised.

“This time last year, it was upstream hedging strategies – particularly longer-term derivatives in place at the end of 2019 – that protected certain North American oil producers,” said Mark Young, report co-author and senior analyst at Evaluate Energy.

“Hedging provided a much-needed glimmer of positivity for North America’s oil producing industry last year. More than $7 billion was raised in realized hedging gains from settled derivatives in 2020 by the companies we analysed. This translates to a 11% boost in E&P revenues for the group over the entire year.

“Based on more recent hedging data, to say the picture has altered in early 2021 feels like a dramatic understatement. Focus has shifted to producers that have hedged to the point where they are missing out on gains from early 2021 price increases.

“It is hard to criticise any producer that was more cautious when it came to hedging heading into the new year. Instead of gambling on exposure to fluctuating oil prices, the chaos of last year plainly made it a priority for many producers to lock in oil volumes even at new lower market prices via hedging. This provides greater certainty and stability around cash flow for internal budgeting processes.”

A total of 72 producers were analysed by Evaluate Energy.

Among the report findings:

• Certain producers missed out on large short-term gains in early 2021 as oil prices rose significantly;
• Oil volumes hedged by these producers fell by just over 400,000 bbl/d overall, but volumes covered by traditional fixed swap and collar derivatives increased over pre-pandemic levels; and
• Many likely lost out by holding more complex three-way collars in 2020 compared to other derivative types; these types of hedging positions have been significantly cut in 2021.

 

New data from Evaluate Energy shows that MEG Energy’s oilsands operations generate the highest overall operating netback per barrel among North America’s most heavily oil-weighted producers.

This analysis was conducted using publicly listed producers in Canada and the United States.

Data on the Top 5 netbacks recorded by oil-heavy and natural gas-heavy producers in Q3 2020 is available here.

“MEG ranks highly in the group because it only produces oil. It has no lower-margin natural gas sales weighing down its revenues, much like most of the companies here in the top 5 oil producers,” said Mark Young, Senior Analyst at Evaluate Energy.

“At just $2/boe back from MEG in Q3 netbacks, one could argue that Pioneer has the ‘best’ netback of the group, as it is only 80% weighted towards oil production,” Young continued. “Every other company in the top 5 oil producers is weighted at least 89% towards oil.”

To download the data, click here.

On the gas-heavy side, it was a similar story.

Three Canadians ranked highly, with netbacks of almost $9.00/boe recorded by Birchcliff Energy, Tourmaline Oil and ARC Resources, but it was one of the American contingent here that stands out.

“Comstock Resources’ $7.46 operating netback per boe is extremely noteworthy from the gas producers,” he said. “The other high ranking gas producers all had a portfolio made up of over 20% oil and liquids in Q3, while Comstock is almost exclusively (98%) a natural gas producer which would limit its revenues per boe relative to the rest of the group.”

Comstock’s low production costs played a large role in generating the relatively high netback. For more on these costs, read our article from last week via the Daily Oil Bulletin.

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.

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.

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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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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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.

Related links:

• CanOils Assets LLR – Book a demo
• CanOils Assets LLR for Business Development – Download our case study
• Alberta’s liability rating system is making it harder for smaller oil and gas producers (Oct. 26, 2016)
• The AER issued a chilling announcement on the first day of summer (June 22, 2016)

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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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.

Notes

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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