Author: Mark Young

A series of high value mergers in the U.S. Permian Basin led to a sharp increase in global upstream deal value in Q2, according to Evaluate Energy’s latest quarterly M&A report.

“Between April and June, we saw $35 billion in new E&P deals agreed,” said Eoin Coyne, report co-author and senior M&A analyst. “This is eight times higher than the same time last year at the height of the pandemic, and a significant uptick on last quarter where $19 billion in new deals were agreed.”

The full report is available for free download here.

Coyne pointed to flat deal counts to illustrate the impact of a series of high value U.S. mergers (particularly in the Permian).

“Despite the sharp rise in deal value in Q2, what we refer to as ‘significant deal counts’ were remarkably similar to Q1 2021,” he said. Relative to Q1, Q2 saw just two more deals valued at over $100 million (for a total of 30), and the same number of deals valued at over $50 million and $10 million (36 and 54, respectively).

“Meanwhile, we saw $18 billion in new deals agreed in the Permian including deals by Cabot Oil & Gas and Pioneer Natural Resources, and eight deals in total in the U.S. with a value greater than $1 billion.”

For deal analysis in the U.S. and a summary of Q2 green energy deals by oil and gas producers, plus an overview of upstream M&A activity in Canada from Tourmaline Oil, Tamarack Valley Energy and Whitecap Resources, download the full Evaluate Energy report here.

Canada’s oil producers contradicted almost every key cash spending pattern across the North American oil and gas industry in Q1, despite enjoying the same increase in operating cash flow thanks to increasing commodity prices, according to new analysis from Evaluate Energy.

Below is a summary of how the 15 producers – which excludes any of Canada’s oilsands majors – bucked two of the key overarching industry trends identified in a new report, available to download here.

Trend #1: Free cash flow surges in Q1

The new report examines 86 U.S. and Canadian oil and gas producers. For most, the sudden injection of Q1 cash flow meant a major increase in free cash flow (the $ difference between operating cash flow and capital spending). The full group of 86 companies in Evaluate Energy’s report recorded a combined US$9.3 billion in free cash flow in Q1 2021, with capex only reaching 53% of operating cash flow. Average free cash flow for the group between 2018 and 2020 was just US$1.4 billion.

This heavily juxtaposes the behaviour of the 15 Canadian oil producers in that group of 86. For them, capex almost matched operating cash flow in two straight quarters following a recent free cash flow high of around C$500 million in Q3 2020. In Q1 2021, the two figures were a mere $43 million apart, meaning capital spending was at a level reaching 95% of operating cash flow in the quarter.

Trend #2: Debt repayment grows at expense of increasing capital spending

With capex increasing almost entirely in line with operating cash flow, the behaviour of Canadian oil producers related to debt repayment was completely different to the rest of the companies in Evaluate Energy’s report.

Comparing Q1 2020 and Q1 2021, the industry at large saw net debt repayments skyrocket to 39% of total cash outflow for the 86 companies as a group, having been around 6% just a year earlier. The rise in operating cash flow in early 2021 saw focus shift quickly to balance sheet repair rather than capital spending.

The 15 Canadian oil producers, however, saw debt repayment fall back in importance year-over-year to just 20% of total cash spending compared to 32% in Q1 2020. It is also worth noting that debt-related spending would still have fallen back in Q1 2021 to 29% of cash outflow even if Enerplus’ Q1 $529 million corporate acquisition-related cash spend had not taken place.

For more on Canada’s oil producers and company-by-company data, as well as the segmented cash flow trends for their U.S.-based counterparts, oilsands producing majors and North American gas-weighted producers, download Evaluate Energy’s cash flow report for Q1 2021 at this link.

Early 2021 saw revenues and operating cash flow soar in the North American oil and gas industry.

A new report from Evaluate Energy studies how far this sudden cash injection changed spending habits for 86* U.S. and Canadian oil and gas producers. The full report – focused on cash used for capital spending, net debt repayments, dividends and more – is available for free download at this link.

Source: Evaluate Energy Cash Flow Review – Q1 2021

Major increase in free cash flow

A sharp rise in Q1 2021 revenues aided by improved commodity prices caused the greatest increase in positive ‘free cash flow’ – the $ difference between operating cash flow and capital expenditures – seen in years. This was caused by capital spending not keeping pace with the sharp rise in revenues.

Debt payments take greater priority

The group of 86 companies used this free cash flow to pay off a far greater amount of debt than has been typical. The report goes further and looks at the individual habits of each sub-group in the study:

• The U.S. oil producer peer group recorded high free cash flow since Q3 2020. This is a complete turnaround for the group that had often recorded capital spending and operating cash flow of very similar amounts.
• Canadian oilsands producers generated huge amounts of free cash flow, which is nothing new for the group. Canada’s other oil-weighted producers were the only group to see capex match the rise in operating cash flow, with behaviour that contradicts almost all cash spending patterns observed in the wider industry.
• U.S. and Canadian gas-heavy producers saw free cash flow suddenly appear in Q1 2021. The Canadian group’s past behaviour is more indicative of this being a temporary occurrence as these producers often operate with a ‘financing gap’ (where capex outweighs operating cash flow) as a group. The data does suggest a temporary occurrence for the U.S. group, too, but it is harder to be certain because the group has been slower to increase capex since the height of the pandemic.

For more details on how producers spent their cash in Q1 2021, as well as information on the results of specific companies included in each peer group, download the full report at this link.

Note

*The 86 companies in this report all fit the following criteria:

• They produced over 5,000 boe/d in Q1 2021;
• Their global production was more than 75% weighted towards North American assets; and,
• They all have a December 31 financial year-end.

A recent survey of industry professionals conducted by Evaluate Energy owners geoLOGIC systems ltd. in partnership with the Daily Oil Bulletin sought to gain a deeper understanding of how data is being used by oil and gas companies.

Detailed results and analysis are available in a new white paper available for free download here.

Some of the key takeaways of the survey, courtesy of Darrell Stonehouse at JWN Energy, are summarized below:

E&P – Cost efficiency is key

• The survey results demonstrate that operators remain laser-focused on managing costs, improving project planning and ensuring capital is deployed where it can deliver the most immediate return.
• E&P companies are also using data to identify large acquisitions and adjacent, bolt-on opportunities.

Oil Services – Business development is top priority

• Oilfield services companies are more focused on business development as their primary requirement when using data.
• The key ‘data goal’ for exploration and development-focused suppliers is operational efficiency to meet customer pricing demands.
• Production-oriented suppliers, meanwhile, are focused more on using data to drive new business.

Vast majority of decision makers are using third party data across the industry

• Nearly 70% of E&P data users incorporate some third-party data in their workflows, with one-third of data users almost always leveraging third-party data.
• Oilfield service data users are slightly less likely to integrate third-party data into workflows, but the survey still showed that around 60% in this sector almost always use outside data to drive business decisions.

Find out more:

• More on these key takeaways, including comments on the results from both geoLOGIC CEO David Hood and President and COO Terry Jbeili, can be found in this piece by Darrell Stonehouse at JWN Energy
• Analysis: Efficiency gains and realities of ‘real-time’ planning dominate E&P data considerations given market uncertainty
• Analysis: Oilfield Services looking for data that provides a competitive edge
• Whitepaper Download: Strategies for data-driven value creation within oil and gas

Evaluate Energy’s latest report shows that global upstream M&A deal spending totalled $19 billion during Q1. Deal counts show an uptick on activity that reflect increased sector confidence and renewed appetite to consolidate/update portfolios as we emerge from the global Covid-19 lockdown.

“The aggregate value of deal-making in Q1 was 5% down on the $20 billion secured during the equivalent quarter last year,” said Eoin Coyne, report co-author and Senior M&A Analyst at Evaluate Energy. “Q1’s total was also 58% lower than the $45 billion seen in Q4 2020, but we did see several very large corporate deals towards the end of last year that skew the picture and make things seem more active than they really were.”

The Evaluate Energy report points to underlying activity telling a clearer, more complete picture:

The number of “significant” deals – Evaluate Energy defines these as deals with a value greater than $100 million – conducted in Q1 2021 (27) was only just below the number recorded in the first three quarters of 2020 combined (32).

Q4 2020 saw over $20 billion more in deal value than Q1 2021, but only three more of these significant deals.

Included in this quarter’s M&A report from Evaluate Energy:

• Canada outpaces the U.S. for upstream deals for first time since Q4 2014
• The largest deal of the quarter sees ARC Resources merge with Seven Generations Energy
• Equinor and Ovintiv both take large losses on U.S. shale sector sales
• North Sea deals return in Europe with over $15 billion in new agreements made since the start of Q4 2020
• A review of upstream companies making Q1 deals in green energy sectors, including Shell, BP and PKN Orlen among others

PDC Energy Inc.’s $1.7 billion acquisition of SRC Energy Inc. was the single-most ‘transformational’ deal last year for any oil, liquids or oilsands portfolio in North America, based on new data from Evaluate Energy.

Source: Evaluate Energy – Oil & Gas Company Performance Data

Evaluate Energy identified the 10 most transformed oil portfolios of 2020 by comparing the volume of barrels of proved (1P) oil, NGL and oilsands reserves added by each company via acquisition in the U.S. and Canada according to year-end reserve reports with North American reserve totals at the start of the year (1).

Data on the companies with the 10 most transformed portfolios in North America can be downloaded for free here.

The PDC acquisition of SRC, originally announced in August 2019 and focused on assets in the Wattenberg core area of the DJ Basin in Colorado, completed in January 2020. It boosted PDC’s oil and liquids portfolio by 162 million barrels of 1P reserves according to its latest reserve report. This represents an increase of 46% compared to the 351 million barrels of 1P oil and NGL reserves it had going into 2020 (1).

“Quite rightly, the large value mergers we’ve seen recently across North America have earned much of the industry’s focus for analysis in the M&A space in recent months, but the data here shows that a large dollar value isn’t the only indicator of a transformative acquisition,” said Eoin Coyne, Senior M&A Analyst at Evaluate Energy.

“By taking out the dollar values and focusing solely on the impact on oil and liquids reserves bases, we can see transformation occurred at all levels of the U.S. and Canadian oil industry in 2020, for majors and much smaller producers alike.”

Coyne points to Chevron and Canada’s Tamarack Valley as a good example.

“The two companies were separated by 2.9 billion barrels in proved U.S. and Canadian oil reserves at the start of 2020 and their respective M&A activity last year was also worlds apart in size; Chevron acquired Noble Energy for $13 billion in the biggest upstream deal of 2020 and Tamarack Valley added just 9 million barrels to its oil reserve base through acquisitions,” he said. “But the data here proves that Tamarack Valley’s activity was far more transformational for the company itself, relatively speaking. The company’s reserves grew by 23% looking at acquisitions alone; Chevron’s grew by 14%.” (1)

The top 10 companies that saw their oil, liquids and oilsands portfolios boosted to the greatest extent through 2020 acquisitions can be downloaded in excel format here.

Related Content

Evaluate Energy’s review of 2020 M&A activity in the upstream industry can be found here. The report includes mergers and acquisitions announced across North America that were not completed by year-end and therefore did not impact corporate reserve levels in time for this analysis.

Notes

1. This data looks at growth by purely comparing barrels assigned to proved reserves acquisitions and start of year proved reserves in the United States and Canada. Any company that completed a North American acquisition last year would have data showing as “growth” in this analysis, but its overall reserves totals may well have fallen year-over-year through other reserve changes not included here.
2. Evaluate Energy’s data provides all reserves changes reported in year-end reports, including barrels added or lost via economic and technical revisions, asset sales, production and extensions and discoveries. For more on our company performance data, click here.

Evaluate Energy’s latest report shows that 72 U.S. and Canadian companies gained a combined $7.6 billion thanks to settled oil and gas derivatives in 2020. This represented a much welcome 11% boost in revenues, which – on a pre-hedging basis – had fallen from $100 billion in 2019 to just $70 billion in 2020 after prices crashed.

“This 11% boost was a lifeline for struggling producers in 2020,” said Isabelle Li, report co-author and Senior Analyst at Evaluate Energy. “Of course, this 11% average is across the whole year. When prices hit rock bottom in the second quarter, hedging was an even more important crutch, boosting revenues by over 35% in that three-month period alone.”

Early 2021 came with oil price increases, however, and will likely see focus shift from these 2020 hedging gains to derivative-related losses being recorded.

“Our data shows that hedging will cause some producers to miss out on short-term gains that could have been made with oil prices climbing at the start of 2021,” continued Li.

“It is, however, tough to criticise any company taking a cautious approach to 2021 before year-end 2020 even if losses are now recorded. As we’ve made clear throughout our report here, favouring long-term planning over potential short-term gains is a strategy that may well appeal much more to some investors given the prices and volatility witnessed only 12 months ago.”

The new report includes:

• Top 10 companies – % increase in revenues thanks to 2020 derivative settlements
• Average prices of oil derivatives in 2021
• Average volumes of oil hedged under swaps, collars and three-way collars in 2021
• The expected impact of 2021 positions on impending Q1 2021 results and the rest of the year to come.

Three Canadian oilsands operators are prominent among larger producers in North America projecting the greatest percentage rise in capital spending in 2021.

Among producers whose daily output exceeds 100,000 boe/d, Cenovus Energy Inc. tops the pile. It plans to almost triple capex spending from C$841 million last year to around C$2.4 billion in 2021. Imperial Oil and Canadian Natural Resources also rank highly with projected increases of 37% and 20%, respectively, based on new Daily Oil Bulletin guidance data.

Sign up for a free DOB trial to gain access to the weekly reports at this link.

The data compares current 2021 budget plans with reported 2020 capital spending based on company annual results compiled within the Evaluate Energy database.

Cenovus’ increase of nearly C$1.7 billion is also the largest increase on a pure dollar level expected in 2021 based on currently available budgets for senior North American producers. Pioneer Natural Resources and ConocoPhillips were the next highest ranked on this metric, with planned increases of around $965 million and $785 million, respectively.

Canada’s other +100,000 boe/d oilsands player Suncor Energy also projects an increase of 9% (~C$355 million) based on its 2021 budget of C$4.15 billion.

The DOB releases updated reports holding all 2021 production, drilling and capital budgets for every North American producer every week.

The report is built using data from the Evaluate Energy guidance product.

Solar power deal making in North American and European markets saw a major uptick in 2020 and early 2021 thanks to growing demand for stakes in future generation capacity.

Click here for detail on these deals on a country-by-country basis.

“We examined deals between the start of January last year up to and including February 15 this year, and the North American uptick compared to 2019 is almost entirely down to acquisitions of future capacity in the U.S., so projects that are not yet online and generating power,” said Eoin Coyne, Senior M&A Analyst at Evaluate Energy.

“As the energy transition continues to pick up steam around the world, gaining access to a growing U.S. solar power generation space has clearly become a priority over the past 12-15 months or so for investors.”

36 GW of the 42 GW (86%) of solar power generation capacity involved in U.S. deals since the start of 2020 was for future planned capacity. More on recent U.S. solar deal making in recent years can be found in this free Excel download.

“Europe’s increase was driven by major increases in capacity changing hands in Spain, while the smaller but no less significant increases in activity seen in the Asia Pacific and Central Asian regions were caused primarily by upticks in capacity being dealt for in Japan and India, respectively.”

Details on Spanish, Japanese and Indian solar power deals since 2018 are included in our latest Top 10 dataset, which ranks all countries based on solar sector deal count between January 1, 2020 and February 15, 2021. Canadian data is also included. The data shows the capacity that changed hands in 2018, 2019 and the 2020-2021 period discussed above, as well as the future and existing generation capacity breakdown for 2020-2021.