Author: Mark Young

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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Statoil joins Shell and other foreign companies in exiting Canadian projects

Norway’s oil and gas powerhouse Statoil ASA has finalised its exit from the Canadian oilsands and is by no means alone in a list of high-profile internationally-based operators to agree a sale of Canadian upstream assets during the past 12 months.

Statoil (Oslo:STL) is selling its interest in the Kai Kos Denseh project to Athabasca Oil Corp. (TSX:ATH) for an initial Cdn$578 million. Analysis of this transaction can be found here.

M&A Jan 2017 CTA

Other significant sales agreed upon in 2016 by non-Canadian companies include:

  • Murphy Oil Corp. (NYSE:MUR) sold a 5% stake in the Syncrude project to Suncor Energy Inc. (TSX:SU) for $937 million in June. Murphy has been a stakeholder in the Syncrude project for 19 years. Murphy also agreed to sell heavy oil assets in Alberta’s Peace River area to Baytex Energy Corp. (TSX:BTE) for Cdn$65 million in November. This sale to Baytex closed in January 2017 – Download CanOils’ latest M&A review for more details.
  • Royal Dutch Shell (LSE:RDSA) sold Alberta Deep Basin and Northern B.C. Montney assets to Tourmaline Oil Corp. (TSX:TOU) for Cdn$1.4 billion in November. That same month, Shell also parted with interests in five Newfoundland and Labrador exploration licenses in a deal with Anadarko Petroleum Corp. (NYSE:APC) for an undisclosed fee.
  • Japan’s Mitsubishi Corp. sold its 50% interest in its Cordova natural gas joint venture with Penn West Petroleum Ltd. (TSX:PWT) to its partner for an undisclosed fee in November.
  • Harvest Operations Corp. (owned by South Korea’s KNOC) sold assets producing 1,500 boe/d in Southeast Saskatchewan to Spartan Energy Corp. (TSX:SPE) in June for Cdn$62 million. Harvest also sold assets in South Alberta to an unnamed party for Cdn$6.7 million in August.

CanOils Monthly M&A review for January 2017 is available to download here.

Despite all of these deals, 2016 was hardly a complete exodus when it came to foreign-based companies and Canadian M&A deals. For example, Calgary Sinoenergy Investment Ltd., a Chinese firm, acquired Long Run Exploration Ltd. in June for Cdn$770 million.

Since then, Sinoenergy has been one of Alberta’s most active operators, according to recent Rig Locator drilling market share data for Q4 2016. Only Canadian Natural Resources Ltd. (TSX:CNQ) and Cenovus Energy Inc. (TSX:CVE) drilled more new operated wells in Q4 2016. U.S.-based Devon Energy Corp. (NYSE:DVN) also figured prominently in terms of wells drilled.

Rig Locator Chart Q4 2016

Source: JWN Rig Locator, Canadian Drilling Activity Market Analysis Q4 2016 Results. Download a sample of the report here.

Rig locator’s market share data also shows that Sinoenergy’s surge in new wells has greatly benefited contractor Bonanza Drilling Corp. In Q4 2016, the company nearly tripled its Western Canadian well count on Q4 2015 by drilling 85% of Sinoenergy’s wells in the period. In fact, behind Precision Drilling Corporation, Bonanza was Alberta’s second most active drilling contractor in Q4 2016, compared to 8th most active a year before.

Rig Locator’s quarterly market share review of Western Canada is available to all Rig Locator members now. A free sample of the report can be downloaded here.

Click here for more information on a rig locator membership.

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Low-cost light oil production drives Viking M&A deals

Low-cost light oil production is the key factor driving dramatic and sustained volumes of M&A activity within Canada’s high-profile Viking formation.

More than Cdn$8 billion in asset and corporate deals involved Viking light oil assets in Eastern Alberta and Saskatchewan in 33 separate deals since 2014, according to CanOils M&A data. Among these deals were Teine Energy’s Cdn$975.0 million acquisition of Penn West assets – the third biggest M&A deal in Canada in 2016 – and Tamarack Valley Energy’s Cdn$407.5 million acquisition of Spur Resources.

Analysis of data from three typical Viking wells reveals that costs are not only low, but that total drilling costs(1) fell even further between the winter drilling seasons of 2015 and 2016. The cost cuts year-on-year, when analysed in relation to the total measured depth(2) of the well, were between 5% and 9% for each Viking type well.

This well cost data is available within the Petroleum Services Association of Canada’s (PSAC) latest well cost study, which has now been digitized for the first time in its 35 year history. Learn more here. The study demonstrates how these costs compare with other prolific Canadian formations, as well as how total drilling costs and the costs of over 100 drilling cost components in the Viking have changed over the past few years.

The three Viking type wells in the study are:

  • AB4D, East Central Alberta, Halkirk area, Horizontal well, Total measured depth 2,150m
  • SK1A, Central Saskatchewan, Dodsland area, Vertical well, Total measured depth 700m
  • SK1C, Central Saskatchewan, Dodsland area, Horizontal well, Total measured depth 1,550m

PSAC Viking Jan17 Chart 1

Source: PSAC Well Cost Study, powered by CanOils. Find out more here.

“While drilling and casing cost cuts have been important, it’s crucial to note the scale of cost cutting that has taken place in the Viking formation when it comes to completing a well, because they make up a larger portion of total costs,” said Karl Norrena, Manager, New Product Development at JWN Energy.

In the SK1C Dodsland horizontal type well, for example, completion costs make up in excess of 63% of its total drilling costs in both 2015 and 2016. The completion costs for this Viking type well dropped 4% between the two drilling seasons.

Completion costs are made up of three sub-categories in the PSAC study data:

  • Completion-related casing and cementing;
  • Completion and testing; and
  • Completion-related contingency and overhead.

Of those cost sub-categories, it was casing and cementing that drove the overall drop in the Dodsland Viking horizontal well completion costs by the largest margin; the costs in this particular category dropped by 19% between 2015 and 2016.

PSAC Viking Jan17 Chart 2

Source: PSAC Well Cost Study, powered by CanOils. Find out more here.

These three sub-categories are comprised of multiple individual cost components. The PSAC study reveals the average cost values for all of them for around 50 type wells across Canada.

Digging even deeper, PSAC’s data demonstrates that this drop in casing and cementing costs for the horizontal Dodsland Viking type well was driven mainly by a 23% drop in production casing costs. These costs now make up a smaller percentage (albeit still the largest) of completion-related casing and cementing costs than they did in winter 2015.

PSAC Viking Jan17 Chart 3

Source: PSAC Well Cost Study, powered by CanOils. Find out more here.

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1) The combined costs to drill, case and complete a well are referred to throughout as “total drilling costs”

2) Total measured depth (m) is the total combined vertical and horizontal length of the wellbore.

PSAC Area Map

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Alberta operators face over $2 billion in environmental LLR liabilities

Service companies are on alert with more than $2 billion in LLR-related costs currently accruing against abandoned wells awaiting reclamation in Alberta, according to the latest CanOils data.

Engaging service companies to reclaim these abandoned wells (i.e. removing the wells’ final LLR-related liabilities – see note 1) would benefit the E&P companies involved by boosting their overall LLR ratings.

As this $2 billion in reclamation liabilities is spread over the entire province, according to CanOils, Alberta’s environmental service companies have a huge market to operate in.

Reclamation LLR Chart

Source: CanOils Assets LLR – Find out more about how LLR data can benefit oil service companies here.

Operators with LLR ratings near to provincial thresholds that can reclaim abandoned wells in order to boost LLR ratings will be of particular interest to specialist reclamation companies. “The environmental benefits of reclaiming the wells reflect positively on operators,” said Karl Norrena, Manager, New Product Development at JWN Energy. “For some, the motivation will be to return to provincial LLR compliance without having to provide a security deposit or seek other financial measures.”

LLR, or Licensee Liability Rating programs, ensure costs to suspend, abandon, remediate or reclaim a well, facility or pipeline are not borne by the public if a licensee becomes defunct. To fulfil LLR regulations, the value of a licensee’s on-going assets must outweigh any liabilities related to abandonment and reclamation costs.

“This dynamic, along with the inherent public relations boost with any environmental program being instigated by any E&P company, represents a huge opportunity to find business for environmentally-focused oil service companies that specialise in reclamation operations,” said Chris Wilson, Managing Director at CanOils.

While all of these wells may not be ideal reclamation candidates (see note 2), the total liability of over $2 billion in Alberta is certainly striking. CanOils Assets LLR data reveals that this is just the tip of the iceberg.

Another $1 billion in LLR liabilities for abandoned wells awaiting reclamation across British Columbia and Saskatchewan, while long-term suspended wells – defined here as wells that have not produced oil or gas in the past 24 months but are yet to be abandoned – account for another $1.6 billion in reclamation liabilities across the three provinces combined.

“CanOils Assets LLR data allows reclamation service companies to not only locate every single one of these wells, but also decide which of them represents the best opportunity for immediate business,” continued Wilson.

To find out more about CanOils LLR and how it helps the Canadian service sector unlock sales targets, download our recent whitepaper here.

Book a Demo:CanOils Assets LLR & Suspended Well Data


1) LLR liabilities for a well include both abandonment and reclamation related costs. For a well that is already abandoned, the only remaining LLR liabilities are reclamation liabilities.

2) A well, despite being abandoned and awaiting reclamation, may be unsuitable for reclamation for a number of reasons. For example, the company in charge of reclaiming the well may not be able to afford to do so just yet, or the well may be in an area where a high number of producing wells continue to exist. Both would preclude any reclamation taking place. It is possible that a well may have already been reclaimed and just be waiting for this change in status to be officially certified by the provincial regulator.

3) All $ amounts refer to Canadian dollars throughout

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Upstream oil and gas M&A in Canada reaches Cdn$1.2 billion in December 2016

The value of December’s announced M&A deals in the Canadian E&P sector totalled just over Cdn$1.2 billion – a sum around $300 million down on the equivalent totals in November and October, but still above the 2016 average of around Cdn$1 billion.

This is according to data available in CanOils latest monthly M&A review, which is available for download now.

M&A Chart Dec 2016

Source: CanOils M&A Review, December 2016.

This month, much in the same way that 2016 began, it was oilsands assets making the biggest domestic M&A headlines. Norway’s Statoil ASA (Oslo:STL) has decided to withdraw from the Kai Kos Denseh project and has agreed a deal with Athabasca Oil Corp. (TSX:ATH), while PrairieSky Royalty Ltd. (TSX:PSK) has acquired a 4% gross overriding royalty at a Pengrowth Energy Corp. (TSX:PGF) SAGD project.

At the start of the year, it was Suncor Energy Inc. (TSX:SU) and its takeover of Canadian Oil Sands Ltd. making all the headlines, along with other oilsands acquisitions from Murphy Oil Corp. (NYSE:MUR) and France’s Total (Paris:FP).

Statoil’s sale is one of multiple deals agreed in 2016 that saw a non-Canadian company sell Canadian assets. Details on the other major asset sales involving foreign investors are also included in the report.

Click here for the full report, including a rundown of every M&A story affecting a Canadian oil and gas company in Canada and around the world in December 2016, as well as detailed metrics for the most significant deals.

M&A Cover Dec 2016

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Why horizontal Cardium wells cost less to drill in 2017

The cost to drill, case and complete a horizontal well in Alberta’s prolific Cardium formation dropped significantly this year compared to the prior winter drilling season.

That assessment is based on new well-cost data researched for PSAC’s Well Cost Study for Winter 2016. Click here to access the latest study, comparative history and sample data. It includes cost estimates for multiple well types across several Canadian regions and formations.

Cost estimates specific to the Cardium formation, for example, can be seen through three typical horizontal wells in two different PSAC regions (see map below):

  • AB2E – Foothills Front; West Pembina area; total measured depth1 3,200m
  • AB2F – Foothills Front; Garrington area; total measured depth 3,600m
  • AB5F – Central Alberta; Pembina area; total measured depth 2,600m

All three type wells, AB2E, AB2F and AB5F, have seen total drilling, casing and completion costs drop by 6% this winter compared to last. The largest cut in costs, on a per metre basis, was at the well in the Garrington area, the deepest(1) of the three Cardium type wells in the study.

PSAC Cardium Chart 1

Source: PSAC Well Cost Study, powered by CanOils – find out more.

Reduced costs for drilling/casing are the primary cause of lower, overall Cardium well costs. For example, in the AB5F Cardium type well in the Central Alberta PSAC region, drilling and casing costs fell by 7%, while completion costs only dropped by 2%.

Drilling and casing costs are comprised of multiple items and the price estimate of each component is accessible within the PSAC Study.

Looking closely at the AB5F type well cost estimates, we attribute the 7% fall to lower casing and cementing costs, which fell by 22%, and rentals, which fell by 29%. Two components that make up the PSAC drilling and casing cost estimate actually increased this year for this AB5F Cardium well, namely construction and rig contract costs.

PSAC Cardium Chart 2

Source: PSAC Well Cost Study, powered by CanOils  – find out more.

All components of drilling, casing and completion costs for 50 type wells across Canada are provided in the PSAC Study.

“The data includes multiple well types and completion strategies, allowing quick comparison of the prices involved for all well cost services,” said Bemal Mehta, senior VP Business Intelligence at JWN Energy Group. “As well as detailed wellbore graphics for every representative well, data on more than 100 drilling and completion cost components is available.”

Click here to access the PSAC Study and sample data.

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1) Total measured depth (m) is the total combined vertical and horizontal length of the wellbore.

PSAC Region Map, AB2 and AB5:

PSAC Region Map - AB2 and AB5

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Who pays the highest drilling rig rates in Western Canada?

Drillers of horizontal wells in Northern British Columbia face, by some distance, the highest average day rates for rigs in Western Canada, according to new data.

PSAC’s new Well Cost Study for Winter 2016 reveals that rig day rates in Northern B.C. can average up to 60% more expensive for horizontal drilling than the equivalent costs in other Western Canadian PSAC regions.

Rig day rates are among more than 100 drilling and completion cost components for around 50 type wells across Canada included in the PSAC study. Combined, they deliver a comprehensive insight into drilling and completion costs faced by operators today. Click here to access the PSAC Well Cost Study.

“PSAC’s winter drilling and completion data reveals important insights on the challenges faced by horizontal drillers in Northern B.C. compared to counterparts in Alberta. The day rates show a significant disparity in costs to develop assets,” said Reservoir Development expert Karl Norrena, Manager, New Product Development, at JWN Energy Group.

Each of the four type horizontal wells in Northern B.C. (see “BC2” on the chart below) face daily rig costs that are typically 60% higher than the two cheapest regions in the PSAC study – East Central Alberta (AB3) and Manitoba – where costs are more in line with a vertical well.

PSAC Rig Rate Chart

Source: PSAC Well Cost Study, Winter 2016 – powered by CanOils. Find out more here and access sample data. Note: Not all PSAC regions are included on this chart as they either only had vertical type wells included in the study, or they did not have a type well included in the study at all.

The four typical wells in Northern B.C. also face among the highest overall rig costs, i.e. the day rate multiplied by the number of days for which the rig is required. They are among wells with the greatest overall measured depth, which means they take longer on average to drill, and therefore require a rig for more days. The total measured depth is the combined length of both the vertical and horizontal portions of the wellbore.

The top 10 type wells included in the PSAC Study ranked in terms of overall rig costs are listed below.

PSAC Rig Rate Table

Source: PSAC Well Cost Study, Winter 2016 – powered by CanOils. Note: The rig day rate percentages take the lowest cost rig rate for horizontal drilling in Western Canada (see map below) as the base rate (0%).

The actual rig costs involved, as well as the total measured depth and the number of days the rig is required are all provided in the PSAC Well Cost Study. The PSAC Well Cost Study is available for purchase now. Click here to learn more and access sample data.

psac map 2

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