EIA: Reporting U.S. companies see oil reserves decline for second consecutive year

Proved oil and liquids reserves for 67 U.S.-listed companies fell for the second year in a row in 2016, according to fresh analysis from the U.S. Energy Information Administration (EIA) using Evaluate Energy data.

The EIA’s analysis, which can be viewed in full at this link, concludes that the decline was primarily due to a handful of larger companies recording a significant drop in Canadian oilsands reserves.

Other causes listed by the EIA include high production levels, downward revisions of existing resources and relatively low levels of extensions and discoveries.

The full article, which also includes analysis on these 67 companies’ production portfolios, is available at this link.

EIA has also released its annual financial review for global oil and gas in 2016, which can be downloaded here. This report is also based entirely on oil and gas company data provided by Evaluate Energy.

Predicted costs for drilling and completing a well in the Cardium this summer

This summer, the costs to drill and complete horizontal wells within the Cardium formation are up to 63% cheaper than the most expensive horizontal wells elsewhere in Alberta.

That is according to the latest PSAC well cost data for summer 2017, which includes detailed cost estimates for many directional, horizontal and vertical type wells across all major western Canadian regions and formations.

“Horizontal drilling in core areas of Alberta’s Montney and Duvernay resource plays is typically more expensive than in the Cardium,” said Chris Wilson, managing director of CanOils and Evaluate Energy. “The PSAC data certainly reinforces those perceptions and crucially quantifies the size and nature of the disparity. We’ve discovered, for instance, that some Cardium drilling, casing and completion costs can be between Cdn$1.7-3.0 million cheaper than a comparable well in the Duvernay.”

Recently, the Cardium has been one of the most active formations within Alberta, with more than 2,000 wells in production today that were licensed within the past five years.

In total, the PSAC study for summer 2017 covers 18 carefully-selected horizontal or directional type wells of varying lengths across various formations and depths in Alberta, to provide a detailed overview of typical drilling costs in the province. The data, collected and assembled by independent drilling experts, shows that these 18 representative Alberta wells range in costs to drill, case and complete from Cdn$0.6 million to Cdn$4.8 million. The five Cardium type wells within this group range in costs from Cdn$1.8 million to Cdn$3.1 million, meaning that costs for Cardium operators are in the mid-to-low range of Alberta drilling costs.

Source: PSAC Well Cost Study, Summer 2017 – Powered by CanOils

The data also shows that, on average, horizontal wells in the Cardium are more expensive to drill than typical horizontal and directional wells in Saskatchewan, but mostly cheaper than horizontal wells in British Columbia.

The PSAC study includes seven horizontal and directional type wells in Saskatchewan of varying lengths across various depths and formations, which range from Cdn$0.5 million to Cdn$1.3 million to drill, case and complete. This stands in stark contrast to British Columbia, where the costs of the four horizontal wells included in the study range far more wildly from Cdn$2.5 million up to almost Cdn$12 million, due to costs attached to the deepest wells within the relatively ultra-expensive Horn River Basin.

Full details on all drilling costs for all Cardium type wells in the Foothills, Foothills Front and Central Alberta PSAC regions of Alberta, are available in the PSAC well cost study. Find out more about the study and accessing the data here.

Map of currently producing Cardium wells that were licensed since January 2012 (2000+ wells)

Source: CanOils Assets, click here for map legend – Map accurate as of April 30, 2017

Active hedgers covered 63% of natural gas production in Q1 2017

Active hedgers among the TSX-listed oil and gas producers covered 63% of their combined natural gas production – and 48% of combined oil production – with a range of hedging contracts in Q1 2017.

Data from CanOils’ updated hedging contracts module shows that, in Q1 2017, there were 42 TSX-listed companies with hedging contracts covering more than 10% of their oil and gas production portfolios. These companies eventually produced 1.1 million boe/d of oil and natural gas liquids (NGLs) and 6.3 bcf/d of natural gas between them during this period.

See: Why do oil and gas companies hedge?

“Gas producers appeared to be more cautious in their approach to commodity pricing than oil producers, using hedging contracts to cover a greater volume overall and a far greater percentage of their total output during the first quarter,” said Isabelle Li, senior financial analyst for Canoils. “Gas prices have been lower for far longer than oil prices, so this caution is perhaps to be expected.”

Source: CanOils Hedging, find out more here.

This apparent caution may be one reason behind the type of hedging contract that was most prevalent among the gas producing peer group.

There are many different types of hedging contracts related to commodity pricing in place for TSX companies according to CanOils, but for the purposes of this article, they have been classified into three main categories:

  • Swaps – Either a fixed sales price or a pre-defined differential percentage to any given commodity pricing benchmark is agreed beforehand for a given volume of production over a given period of time.
  • Collars – A company agrees a ceiling and floor price for a pre-defined volume of their production to be sold over a given period of time. If the pre-defined pricing benchmark goes over the ceiling price, the production is sold at the ceiling price, and if the benchmark drops below the floor, it is sold at the floor price. Slightly riskier than the swap, as you have less certainty. Three-way collars have been included here too. A three-way collar is a cheaper option than a standard two-way collar for the oil or gas producer but also introduces a sub-ceiling price to give the company issuing the hedge a greater level of protection. Due to their lower cost, three-way collars tend to be more appealing to smaller producers.
  • Other – a selection of less common contract types have been included in this category, including various types of puts, calls and spreads.

CanOils’ hedging data shows that at the start of Q1 2017 among the TSX’s active hedgers, gas producers were covered by far more swap deals than any other type of contract. 73% (or 491,000 boe/d) of all gas production that was hedged in Q1 2017 was hedged in a swap deal.

While caution or a greater need for cash flow certainty – depending on how you look at it – is likely one reason behind this, it could also be that collars or other contract types were simply either not available or less attractive cost-wise for natural gas this quarter. “Swaps are also simpler than other contract types,” adds Li.

Source: CanOils Hedging, find out more here.

Swaps were also the most common oil contract too, but only 50% (269,000 boe/d) of all oil hedged by TSX companies in Q1 2017 was under a swap deal, with collars and three-way collars relatively more popular for oil producers.

This relative increase in popularity could be down to the fact that oil prices have fluctuated to a far higher degree than gas prices in recent times. No doubt oil producers were eager to enjoy at least some of the upside of any sustained price increase that this fluctuation may yield, despite the slightly increased risk to their cash flow positions.


  • All data on active hedging contracts for Q1 2017 was taken from each company’s financial report or management, discussion and analysis (MD&A) report for the three month period ending Dec 31, 2016.
  • CanOils hedging data includes all contracts that every TSX and TSX-V company has in place, including those active in future periods.
  • All production data was taken from each company’s MD&A for the three month period ended March 31, 2017.

Why do oil and gas companies hedge?

Hedging oil and gas production for months or even years into the future is a vital tool for companies to provide certainty to their cash flow statements, by potentially securing future revenues for a specific, pre-determined period of time.

For details on CanOils’ new and improved hedging module, please click here.

While entering into a hedging contract means that producers forgo the benefits of any significant commodity price increase, the company is simultaneously protected against a dramatic decline in prices.

Some companies may value this cash flow certainty over the potential upside at any given time for many different reasons. For example, there may be companies that have huge capital expenditure plans to create significant production growth for the next few years, and while the upside of a short-term price increase is appealing, it is not worth jeopardising any growth plans should prices actually decline. So these companies may elect to take out a hedging contract to ensure its budget is safe for the future of the company.

Some companies may just want to keep dividend payments stable in difficult times to avoid losing investors, while others could be at or close to their break even already in terms of commodity prices. Agreeing hedging deals would help to ensure the company stays afloat through a difficult period and is protected against any further fall in prices.

There may also be companies that are in a position where external finance (e.g. raising cash by securing new debt or issuing new shares) may be unavailable, unwanted or hard to come by; hedging contracts can act as an alternative funding guarantee.

Of course, not all companies take this approach at all for various reasons; indeed, some of even the TSX’s largest producers including Suncor Energy Inc. and Husky Energy Inc. do not hedge. But for those that do, it is possible to partly decipher each company’s attitude to price risk through their own hedging contract portfolio.

Every TSX and TSX-V-listed company’s outstanding hedging contracts active in 2017, 2018 and even 2019 is available in the new and improved CanOils hedging module. For more information on the module and the data provided, click here.

Pengrowth Energy has now agreed to sell Cdn$1.7 billion in assets since 2013

New data available in CanOils’ M&A review for April 2017 illustrates the flurry of sales activity undertaken by Pengrowth Energy Corp. (TSX:PGF) since 2013 – with deals for its assets totalling more than Cdn$1.7 billion.

Almost Cdn$460 million of these deals have been agreed since the start of 2017, with the company having been strongly focused on debt repayment in recent periods.

Source: CanOils M&A Database – find out more here

The company’s most recent sale, a Cdn$185 million sale in the Swan Hills area, is featured heavily in CanOils’ latest report alongside all major April upstream deals in Canada.

In total, the month witnessed Cdn$855.5 million in new upstream deals announced for E&P assets across the whole of Canada, meaning Pengrowth’s most recent deal was around 22% of the overall April total. For more on all this month’s activity, download the report here.

The report also provides analysis on every new upstream asset that was listed for sale in Canada this month. While the size of assets was well below the rolling 12-month average of 20,000 boe/d, April did see some interesting minor assets put up for sale. For more, download CanOils’ M&A review for April 2017 here.

Whitecap, Raging River added the most employees of TSX-listed producers in 2016

Whitecap Resources Inc. and Raging River Exploration Ltd. saw full time and part time employee numbers increase by a combined 62% and 54%, respectively, between 2015 and 2016, according to annual data available on CanOils.

The two companies top the list of TSX producers to increase employee numbers this past year, despite the continued challenging environment for oil and gas producers worldwide.

Source: CanOils – find out more

At the other end of the spectrum, the TSX companies to let the highest portion of employees go this year were TransAtlantic Petroleum Ltd. and Perpetual Energy Inc. These companies cut their workforces by 59% and 57%, respectively, between 2015 and 2016.

Source: CanOils – find out more

Note: All figures include full and part time employees only. Consultants or contractors are excluded.

Canadian upstream oil and gas M&A hits Cdn$32.8 billion in March 2017

Major deals in the oilsands sector this month meant that the total upstream M&A spend in March 2017 alone eclipsed the annual totals for each of the past five years except for 2014, according to CanOils’ latest monthly M&A review, which can be downloaded here.

Source: CanOils M&A Review, March 2017 (All deals are allocated according to the date of their original announcement)

Cdn$32.1 billion of the total Cdn$32.8 billion spend in March revolved around oilsands assets. Cenovus Energy Inc. (TSX:CVE) bought out its 50% joint  venture partner, ConocoPhillips (NYSE:COP) in the FCCL partnership, Canadian Natural Resources Ltd. (CNRL, TSX:CNQ) acquired a 70% interest in the AOSP from Royal Dutch Shell (LSE:RDSA) and Marathon Oil Corp. (NYSE:MRO). Shell itself also acquired a minor stake in AOSP from Marathon to complete the spending.

Away from the oilsands, it was also a relatively busy month considering recent deal trends, with over Cdn$700 million spent on conventional and resource play assets. The largest deal saw Painted Pony Petroleum Ltd. (TSX:PPY) acquire 8,500 boe/d of new Montney production, while Enerplus Corp. (TSX:ERF) and Pengrowth Energy Corp. (TSX:PGF) agreed significant asset sales as well.

March also saw Cenovus place nearly 30,000 boe/d of gas weighted production over 1 million acres up for sale. Birchliff Energy Ltd. (TSX:BIR) and Insignia Energy Ltd. (TSX:ISN) were among the other companies to list assets for sale this month.

For full analysis on all these deals and assets for sale, as well as an outlook for the Canadian oilsands industry, download the CanOils Monthly M&A Review for March 2017 here.

Global upstream M&A reaches $65.1 billion in Q1 2017

Q1 2017 saw the highest outlay on global upstream oil and gas M&A for almost two years, with US$65.1 billion in deals declared, according to Evaluate Energy’s latest M&A review.

The previous biggest quarter in terms of value was Q2 2015, when Royal Dutch Shell acquired BG Group. This quarter’s total was in fact the fifth largest quarterly spend since Q1 2010.

Source: Evaluate Energy Global M&A Review, Q1 2017

This quarter’s deal value was of course driven by the significant US$24.5 billion spend in the Canadian oilsands sector, with Cenovus Energy Inc. (TSX:CVE), Canadian Natural Resources Ltd. (TSX:CNQ) and Royal Dutch Shell (LSE:RDSA) all agreeing deals that significantly altered the oilsands landscape during March. It was actually only the fourth time in seven years that Canada saw a greater overall deal value in a quarter since the start of 2010.

Speaking of the United States, it was a record setting quarter for the increasingly popular Permian Basin, where US$18.5 billion in new upstream deals were announced. ExxonMobil Corp. (NYSE:XOM), Noble Energy Inc. (NYSE:NBL) and Parsley Energy Inc. (NYSE:PE) were among the acquirers in the basin this quarter.

For full details and the usual in-depth analysis on all the major deals in North America and around the world, access Evaluate Energy’s global M&A review for Q1 2017 by downloading the report here.

5,600 boe/d put up for sale in Canada in February 2017

Putting aside Canadian Natural Resources Ltd.’s (TSX:CNQ) major Cdn$12.7 billion acquisition in the oilsands mining sector from Royal Dutch Shell and Marathon Oil Corp., upstream M&A deal values in Canada have been extremely low at the start of 2017. In fact, January and February combined saw just Cdn$235 million of new deals, one-fifth of the total in December 2016.

However, this slow start could soon be turned around with a large amount of new production placed onto the market in February, according to CanOils latest monthly Canadian upstream M&A review, which can be downloaded here.

In total, new asset listings saw 5,600 boe/d hit the market this past month, with the vast majority coming from voluntary listings rather than receivership processes. The higher profile assets for sale are listed below.

For full details on these listings and all other upstream assets put up for sale in February 2017, download CanOils monthly M&A review here.

Crew Energy Inc.

The largest listing of the month by production saw Crew Energy Inc. (TSX:CR) offer assets with 2,063 boe/d on the Alberta-Saskatchewan border. The offering is being conducted exclusively via TD Securities Inc. The assets are characterised by heavy oil production and include a potential 700 boe/d of production from shut-in wells.

Crescent Point Energy Corp.

Crescent Point Energy Corp. (TSX:CPG) has engaged TD Securities Inc. as its financial advisor to divest 3.22% and 10.05% interests in the Weyburn and Midale units, respectively, in Saskatchewan. These assets produced at a rate of 1,202 bbl/d and generated an operating netback of $23.53 per barrel over the 12-month period ending September 2016.

Paramount Resources Ltd.

Paramount Resources Ltd. (TSX:POU) has retained CB Securities Inc. as its exclusive advisor for the sale of several non-core properties in multiple areas of Alberta and British Columbia. In British Columbia, the company is looking to sell assets in the Sunrise and Cutbank areas. In total the assets produce 813 boe/d (57% gas).


Source: CanOils Assets

For more on the CanOils Assets for Sale product, click here.

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What does it cost to complete a well in Alberta?

Higher commodity prices in Canada are driving a renewed focus on completing wells in Alberta, following a huge increase in the number of drilled but uncompleted wells (DUCs) over the past three years.

PSAC’s new well cost data for Winter 2016 reveals that costs to complete a typical well in different regions of Alberta vary widely.

The chart below shows where it is most expensive to complete a horizontal or directional well for six PSAC regions in Canada. To simplify our findings, each well type within each region has been grouped into high, medium and low completion cost brackets. Dollar amounts and a breakdown of every completion cost component are available in the study itself. Click here for more details.

Source: PSAC Well Cost Study, Winter 2016 – Find out more here. (Alongside each PSAC region in the chart, the target formations of the type wells within the region are listed. These are listed in order from highest completion cost to lowest completion cost.)

During the downturn, DUCs became more abundant across Alberta for a number of reasons.

Many operators were eager to delay the most prolific production period of any well – the first few months – until market pricing offered greater reward. The aftermath of that strategy is playing out now. PSAC’s latest completion cost data can help to predict just how much this patience will pay off for each applicable operator, in terms of margins they can now expect to receive at higher prices.

Other key reasons for keeping high numbers of DUCs include delaying production to boost the size of a company’s non-producing reserves at opportune times. That tactic is used to bolster the attractiveness of an asset to investors or acquirers. Naturally, leaving wells as DUCs may have been the only option for other companies that had simply run out of cash.

Of the six PSAC regions in the above chart, Foothills Front is clearly one of the highest completion cost areas for horizontal wells. “These wells in Foothills Front often target the prolific Cardium formation, which is characterized by highly complex structural uncertainty and thin productive zones separated by thick shales that complicate directional drilling and completion exercises,” said Karl Norrena, Manager, New Product Development at JWN Energy.

At the end of 2016, on top of the fact that it has some of the highest well completion costs in Alberta, Foothills Front also had the greatest number – 320 – of horizontal/directional DUCs that were drilled since September 20141, when the price downturn began, according to the latest data from CanOils Assets.

Source: CanOils Assets – Find out more here.

Click here for more on how DUC data can help service and supply companies identify qualified sales leads.


1) The final drilling date of every well included in the chart was on or after September 1, 2014

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