Author: Mark Young

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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Notes

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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Marcellus shale sees massive resurgence in M&A activity

There was nearly eight times more invested in asset and corporate acquisitions in the Marcellus shale in 2016 than 2015, according to new analysis in Evaluate Energy’s global M&A review for 2016.

Marcellus assets changed hands for a total of US$7.25 billion in 2016 – a massive increase on the US$920 million total recorded in 2015.

When an increase in M&A activity of this size occurs so quickly, the usual reason is that there were one or two deals with extremely high values skewing the figures. Here, however, this is not the case according to Evaluate Energy data.

Not only were Marcellus shale deal values up in 2016, but the 13 “large” deals with a value of over $100 million was in fact the highest number of large deals seen in the play since its first real M&A boom in 2010. This is indicative of a real, widespread increase in Marcellus M&A activity over the past 12 months.

M&A Annual 2016 Chart

Source: Evaluate Energy Global Upstream M&A Review, 2016

The Marcellus has a core group of significant players, which includes some of the United States’ biggest natural gas producers. Some of these companies – including EQT Corp. (NYSE:EQT) and Antero Resources Corp (NYSE:AR) – were keen this year to take advantage of other companies deciding that their respective Marcellus positions were in fact now non-core assets. A handful of major international players were among the selling parties; Anadarko Petroleum Corp. (NYSE:APC), Statoil ASA (Oslo:STL) and Japan’s Mitsui & Co Ltd. all agreed a sale of Marcellus acreage for over $100 million.

For more on the Marcellus shale deals in 2016, including specific deal values, and how activity here fits with overall U.S., Canadian and global M&A trends, download the Evaluate Energy M&A review of 2016 here.

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68% of Canadian oil & gas companies will spend more in 2017

Following more than a year of cost cutting and spending reductions, early 2017 guidance in the Canadian oil and gas sector suggests that we will see a rebound in activity over the next twelve months.

A far more stable oil price, as well as the past 18-months of adapting to a lower-for-longer pricing environment has increased confidence among Canada’s oil and gas companies, and more robust drilling and completion plans have proliferated as a result.

Guidance data compiled by CanOils shows that 68% of the companies that have reported a 2017 capital spending guidance figure so far this winter are planning for an increase in spending over the next twelve months compared to last year.

The CanOils data, which shows final 2016 and early 2017 guidance for upstream, midstream and oil service companies in Canada, is available for purchase now.  The data will benefit operators seeking to efficiently benchmark future plans against competitors, or oil service companies trying to quickly find out which E&P companies have the biggest or most ambitious development plans in 2017.

The increased spend for these companies will see production also increase across the board. The CanOils data shows that 71% of companies that have so far reported 2017 average production guidance are expecting an increase in volumes over the next twelve months.

The CanOils Guidance Package for 2016-2017 can be purchased now at this link.

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Upstream M&A in Canada exceeds Cdn$1.5 billion in November 2016

The value of November’s announced M&A deals in the Canadian E&P sector totalled just over Cdn$1.5 billion – a sum almost identical to the equivalent total recorded in October. The full CanOils review of November upstream deal activity can be downloaded here.

This month, however, it was more than just one major deal driving the total.

Seven deals were announced in November for Canadian E&P assets with values of over $50 million, while in October, the $1.4 billion deal between Tourmaline Oil Corp. (TSX:TOU) and Shell almost entirely dominated the total alone. This is a significant increase in activity as we approach the end of the year.

The biggest deal this month saw ARC Resources Ltd. (TSX:ARX) agree to sell its entire asset base in Saskatchewan to Spartan Energy Corp. (TSX:SPE) for Cdn$700 million.

ARC Resources Ltd (Blue) and Spartan Energy Corp. (Red) – Active Working interest southeastern SK wells as of September 30, 2016

ARC Spartan Map1

Source: CanOils M&A Review, November 2016

Saskatchewan assets were in high demand this month, with a few significant deals in the province being announced. Aside from ARC’s Cdn$700 million sale, there were Saskatchewan deals involving Tamarack Valley Energy Ltd. (TSX:TVE), Raging River Exploration Inc. (TSX:RRX) and Northern Blizzard Resources Inc. (TSX:NBZ). Over 4,000 boe/d was also put up for sale in new asset listings this month.

For full details and analysis on all of these deals and listings in Canada’s upstream sector, as well as every deal story involving a Canadian oil and gas company this month, download the CanOils M&A review for November 2016 here.

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Win oilfield service contracts with new DUC data

Oilfield service companies seeking customers can benefit from new data on every “drilled but uncompleted well” (DUC) in Alberta and Saskatchewan – wells that, if left untouched for more than one year after drilling, will incur millions of dollars in LLR-related liabilities.

For each DUC, the relevant data for service companies includes the location, operator, current operating status and historical production of surrounding wells. The data identifies which operators are at greatest risk of contravening LLR regulations if they don’t act on the DUCs. It also identifies other parties that could be indirectly affected by non-compliance.

This new data is part of CanOils Assets module.

Click to download a free report on LLR liabilities, DUCs and benefits to services and supply companies.

Based on LLR regulations in Alberta and Saskatchewan, currently by November 2017 a total of Cdn$330 million of abandonment and reclamation liabilities, covering more than 3,600 licenses, will impact Canada’s E&P players’ LLR positions.

Why? Because LLR liabilities attached to new wells come into effect a year after drilling (see note 1). This is true for all wells – whether they are producing, suspended or uncompleted.

LLR data service co 1.jpg

Source: CanOils Assets (see notes 2 and 3)

One way to offset this LLR risk for Canadian E&P players is to act upon DUCs – by either completing or abandoning/reclaiming them. This opens up a potential multi-million dollar market for oilfield service companies.

The number of DUCs in Canada multiplied during the price downturn, because companies have been reluctant to waste the most prolific production period of any well – the first few months – on low margins. They have been waiting for an increase in price. In some cases, keeping higher numbers of DUCs, and therefore larger values of proven non-producing reserves on the books, may have been deemed necessary to boost attractiveness to potential investors or acquirers.

But DUCs that remain uncompleted one year on from drilling obviously bring no production to the table and have a negative influence on an operator’s LLR position. For more on how service companies can identify opportunities using LLR-related data, click here.

Alberta currently has Cdn$21 million of LLR liabilities attached to DUC wells that will hit the 12-month threshold before the end of March 2017. If an operator has a sufficient quantity of these DUCs to take its LLR rating below 1.0 and does not act upon them, it would need to provide a security deposit or face greater scrutiny from the AER on far more aspects of day-to-day operations. Also, companies in Alberta would be unable to complete any M&A acquisition with a rating below 2.0.

LLR data service co 2.jpg

Source: CanOils Assets (see notes 2 and 3)

The good news for oilfield service companies is that operators can complete and tie-in DUCs to boost overall production and in turn boost LLR ratings, or indeed reduce their LLR liability by abandoning and reclaiming DUCs. The sheer volume of liabilities involved in leaving wells untouched indicates a huge opportunity within the oil services sector.

Click here for more details on how LLR data can unlock more qualified sales targets for service and supply companies in Canada.

Notes:

1) Year-long well exemptions are only applied in Alberta and Saskatchewan, not in British Columbia. CanOils Assets has LLR-related data for every single well in all three provinces. For Alberta wells, the year-long exemption begins at final drilling date. For Saskatchewan, it begins at the spud date.

2) For the purpose of this article, every well without any production in its lifetime that is over a year old or approaching a year old in the given time parameters has been included as a DUC. CanOils Assets has the data and granularity to support far more detailed DUC analysis across the Alberta and Saskatchewan oil and gas markets.

3) The data includes all wells apart from certain well types, which are always exempt from LLR evaluations. In Alberta, this list of well types includes oilsands evaluation wells. For more information on well type exclusions in Alberta, visit the AER.

LLR/LMR terms:

In Alberta, the LLR program is part of the overall LMR (liability management rating) program, which also includes the OWL (oilfield waste liability) and LFP (large facility program). CanOils focuses only on LLR calculations by individual well, but also has the overall corporate LMR/LLR ratings by province. In British Columbia, the program is also only referred to as the LMR program. The LLR rating system takes into account liabilities related to wells, facilities and pipelines. CanOils Assets is focused ONLY on the well component of the calculation.

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Encana cuts debt by largest amount for E&P TSX companies in past year

Debt reduction has been a hot topic in past year in Canada, as companies adapted to a lower-for-longer price environment.

Out of 70 domestic and international producers listed on the TSX, Q3 2016 data available in CanOils reveals that Encana Corp. (TSX:ECA) has cut debt by the largest monetary value over the past year. The company has removed just under Cdn$2.6 billion of debt from its balance sheet between Q3 2015 and Q3 2016 (see note 1), a reduction of around 30%.

Debt TSX 2016 1

Source: CanOils

The TSX-listed company that has shaved the most debt off its previous year’s balance sheet proportionately is Touchstone Exploration Inc. (TSX:TXP). By cutting its debt by Cdn$6.6 million, Touchstone’s debt levels are 93% lower in Q3 2016 than in Q3 2015.

In terms of domestic producers, Paramount Resources Ltd. (TSX:POU) cut its debt by the largest percentage (84%) over the same timeframe, using funds generated in an asset sale that was the largest E&P deal of the year in Canada.

Debt TSX 2016 2

Source: CanOils

Subsequent to Q3 2016 – and therefore not in these figures – RMP Energy Inc. (TSX:RMP) closed a deal with Enerplus Corp. (TSX:ERF) to sell its assets at Ante Creek for Cdn$114.3 million. The sale proceeds allowed RMP to eliminate its bank debt.

Not all companies reduced debt. Suncor Energy Inc., (TSX:SU) the TSX’s largest current producer, saw the largest debt increase in terms of actual value between Q3 2015 and Q3 2016. Suncor’s debt rose by Cdn$2.9 billion after a busy year of acquisitions. Painted Pony Petroleum Ltd. (TSX:PPY), Oilweek’s producer of the year for 2016, saw debt increase by the largest proportion over the 12 month period, more than ten-fold, to Cdn$537 million. This was mainly due to a new finance lease being accounted for upon the start-up of operations at a gas processing facility and pipeline.

Overall, despite some companies’ increases in debt, these 70 oil and gas companies of the TSX have around 6% less debt impacting their balance sheets in Q3 2016 compared with Q3 2015 (Cdn$92.4 billion vs. Cdn$98.5 billion).

For those domestic operators that have reduced debt by significant margins, focus can switch to other pressing problems relating to the downturn, such as Licensee Liability Ratings (LLR).

This article focuses on the headline debt figures for 70 TSX E&P companies only. More complicated debt analysis for all TSX and TSX-V listed E&P companies, including credit facility usage, liquidity ratios and changes in company capital structures over time, for example, can be carried out with CanOils financial and operating data. Find out more by downloading our brochure here.

Notes

1) Encana is one of a handful of TSX-listed companies in this article that report financial statements in US$. The exchange rate used for all data is US$1 = CDn$1.30919. This was the period end rate for Q3 2016.

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The 10 largest upstream impairments recorded in U.S. oil & gas in 2016

Impairments and write-downs in the U.S. oil and gas industry were brought right back into focus by ExxonMobil’s admission in October 2016 that it might have to write-down the value of some of its E&P assets around the world.

ExxonMobil, in what would be a significant change in accounting policy, may soon officially concede that 3.6 billion barrels of oil-sand reserves in Canada and one billion barrels of other North American reserves are currently not profitable to produce, according to the NY Times.

This would probably be the largest E&P impairment across the entire U.S. industry in 2016, but ExxonMobil would by no means be alone in declaring asset write-downs.

Over the year so far, looking at the most recent year-to-date nine monthly results for U.S.-listed companies in Evaluate Energy, Devon Energy Corp. (NYSE:DVN) has recorded the largest single upstream impairment charge in its income statement at $4.9 billion.

US-Impairments-2016-01.jpg

Source: Evaluate Energy (see note 1)

As for the three month Q3 period alone, the largest upstream impairment was Chesapeake Energy Corp.’s (NYSE:CKE) $1.2 billion charge on oil and gas properties and other fixed assets, which represented around 38% of its total 2016 impairment charges of $3.1 billion.

US-Impairments-2016-02.jpg

Source: Evaluate Energy

While it did not have the largest actual figure relating to impairments, the largest impact of 9M 2016 impairments was felt by Halcon Resources Corp. (NYSE:HK). The company’s $1.2 billion impairment charge over the 9 month period – either side of bankruptcy proceedings – made up the biggest proportion (47%) of pre-impairment total assets at period end across the entire U.S. E&P space.

US-Impairments-2016-03.jpg

Source: Evaluate Energy (see note 2)

Evaluate Energy covers the entire U.S. oil and gas space, with historical financial and operating performance coverage for every single U.S. listed oil and gas company with E&P or refinery interests. To find out more, please download our brochure.

Notes:

1) Chevron’s impairment figure may include costs related to tax adjustments & environmental remediation provisions and severance accruals, as no breakdown of “Impairments and other charges – E&P” is reported.

2) The percentage fall in total assets for 9M 2016 is calculated by comparing 9M 2016 impairments with the total assets figure for 9M 2016 (pre-impairment charge). This gives an estimate of how big an impact the 9M 2016 impairments had on a company’s total assets at the end of the period, i.e. if it wasn’t for the impairments, Halcon’s total assets figure would have been around 47% higher.

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Top 10 upstream M&A deals in Canada in 2016 so far

Up to the end of October 2016, there has been Cdn$10.1 billion spent in Canada on upstream assets in newly announced deals in 2016. It is now over a year since Suncor Energy Inc. (TSX:SU) began its Cdn$6.6 billion takeover approach for Canadian Oil Sands Ltd., which stands out as by far the biggest deal Canada has seen since the price downturn, but 2016’s activity has also been significant. Deals in the Montney areas of Alberta and British Columbia have made huge headlines, Saskatchewan assets have frequently changed hands for large sums and Suncor was not quite finished with the oilsands sector or the Syncrude project in particular after closing the Canadian Oil Sands deal.

The top 10 deals announced in 2016 so far, up to and including deals announced on November 17, 2016, are listed below.

October M&A HZ CTA

 

Canada’s Top 10 upstream deals of 2016 so far

1) Cdn$1.9 billion – Seven Generations Energy acquires Montney assets from Paramount Resources

The biggest deal of 2016 so far saw Seven Generations Energy Ltd. (TSX:VII) acquire Montney production and lands from Paramount Resources Ltd. (TSX:POU) for Cdn$1.9 billion. The consideration will be made up of Cdn$475 million in cash, 33.5 million Seven Generations shares and the assumption of around Cdn$584 million of Paramount debt. By acquiring these assets, Seven Generations is boosting its portfolio with a further 199 million boe of 1P reserves, 30,000 boe/d of production in the company’s core Kakwa River area and 155 net sections of Montney land.

Full report – July 2016 and August 2016

CanOils Assets map of the Kakwa River area as of June 30, 2016

VIIPOU_Map

Source: CanOils Assets

2) Cdn$1.4 billion – Tourmaline Oil Corp. acquires British Columbia Montney and Alberta Deep Basin assets from Shell Canada

The second biggest deal of 2016 so far was announced in October and sees Tourmaline Oil Corp. (TSX:TOU) acquire assets from Shell Canada for just under Cdn$1.4 billion. The assets are located in the BC Montney and the Alberta Deep Basin. The consideration is made up of Cdn$1 billion cash and the remainder in Tourmaline stock. The cash portion of the transaction will be funded through the company’s existing credit facilities and Cdn$739.4 million that will be raised in two equity financings; Tourmaline will look to raise Cdn$100 million via a prospectus offering and a further Cdn$639.4 million via a private placement.

Full report – October 2016

CanOils Assets map of operated Tourmaline (blue) and Shell (red) wells in the Alberta Deep Basin as of September 30, 2016

deep basin

Source: CanOils Assets

3) Cdn$975 million – Teine Energy acquires Penn West Petroleum’s Saskatchewan assets

Teine Energy Ltd., with funds from its own existing credit facilities and significant financial backing from the Canada Pension Plan Investment Board, acquired Penn West Petroleum Ltd.’s (TSX:PWT) Dodsland Viking assets in Saskatchewan for C$975 million. This is the biggest deal outside of Alberta and British Columbia so far this year.

Since Q4 2014, when the price downturn really began, Penn West has sold assets in deals worth a total of C$2.5 billion, all aimed at reducing total debt. This single C$975 million asset sale resulted in a markedly improved capital structure; Penn West now says that the company is in the top tier of its peers in terms of all significant debt metrics.

Full report – June 2016

4) Cdn$937 million – Suncor Energy buys Murphy Oil out of Syncrude

Suncor Energy Inc. (TSX:SU), following the C$6.6 billion deal to acquire Canadian Oil Sands Ltd. at the start of 2016, increased its stake in Syncrude by a further 5% in June when it completed its C$937 million deal with Murphy Oil Corp. (NYSE:MUR). This now means that Suncor’s stake in the Syncrude project is 53.74%. Murphy Oil had been a participant in the Syncrude project for over 22 years.

Full report – April 2016 and June 2016

5) Cdn$700 million – Spartan Energy Corp. acquires ARC Resources’ Saskatchewan assets

November 2016 has so far seen two significant deals with values of over Cdn$100 million in Saskatchewan. The larger of the two sees ARC Resources Ltd. (TSX:ARX) exit Saskatchewan entirely. Spartan Energy Corp. (TSX:SPE) is the acquirer of the assets, which are located in the southeast of the province and produce 7,500 boe/d (98% liquids).

Full report coming soon – sign up to our mailing list here

CanOils Assets map of working interest ARC (blue) and Spartan (red) wells in southeast Saskatchewan as of September 30, 2016

ARC Spartan Map1

Source: CanOils Assets

6) Cdn$625 million – Birchcliff Energy acquires Encana’s Gordondale assets in Alberta

Encana Corp. (TSX:ECA), after making two asset sales of over C$1 billion in the United States in the latter half of 2015, has now completed a significant asset sale in Canada. Birchcliff Energy Ltd. (TSX:BIR) is the acquirer, in a Cdn$625 million deal for Encana’s wells and leases in the Gordondale area of Alberta. The assets (65% gas weighted) are located in the Peace River Arch region and the target formations are the Montney and Doig resource plays.

Full report – July 2016

7) Cdn$595 million – Whitecap Resources acquires southwest Saskatchewan assets from Husky Energy

In Saskatchewan’s second biggest deal of 2016 so far, Whitecap Resources Inc. (TSX:WCP) acquired assets in southwest Saskatchewan from Husky Energy Inc. (TSX:HSE) for C$595 million. The deal increased Whitecap’s production by 11,600 boe/d and also increased the company’s oil weighting by 3% to 79%, as the assets being acquired produce 98% oil and NGLs.

Full report – May 2016 and June 2016

8) Cdn$486 million – Murphy Oil and Athabasca Oil Corp form Canadian shale joint venture

A few months before it agreed to leave the Syncrude project behind in a deal with Suncor, Murphy Oil Corp. (NYSE:MUR) agreed a joint venture in the Montney and Duvernay shale plays with Athabasca Oil Corp. (TSX:ATH). The deal, worth Cdn$486 million in Murphy stock, cash and cost carries, sees the two companies join forces in the Greater Kaybob and Greater Placid areas. In the Greater Kaybob area, Murphy will take a 70% stake and operatorship to target the Duvernay shale play. In the Greater Placid area, Murphy will assume a 30% non-operated interest and the target is the Montney shale play.

Map of Leases Included in the Athabasca/Murphy JV Agreement Athabasca Oil Corp. Holdings in Greater Kaybob and Greater Placid Areas

Canada Top 10 Deals MUR ATH

Source: CanOils Assets

Full report – January 2016 and May 2016

9) Cdn$388 million – Tamarack Valley acquires Spur Resources

November’s other significant deal with a value of over $100 million in Saskatchewan involved Tamarack Valley Energy Ltd. (TSX:TVE) acquiring all the issued and outstanding stock of Spur Resources Ltd., a privately-held Viking oil focused company. The deal, worth Cdn$388 million including debt assumption, adds 6,250 boe/d (52% liquids) of low cost production to Tamarack Valley’s portfolio and an extensive drilling inventory of 695 net identified low-risk drilling locations with an average liquids weighting of approximately 70%.

Full report coming soon – sign up to our mailing list here

10) Cdn$268 million – Boulder Energy Ltd. goes private 

2016 has seen a series of TSX-listed companies taken off the stock exchange via corporate acquisitions and become privately-held entities. The biggest acquisition involving purely Canadian assets to be announced during 2016 saw ARC Financial Corp. acquire Boulder Energy Ltd. for around Cdn$268 million including debt assumption. Boulder was only formed as an independent entity in May 2015, having been one of the two resultant companies in the reorganisation of Deethree Energy Ltd. While Granite Oil Corp. (TSX:GXO) was formed with Deethree’s South Alberta Bakken wells and gas injection EOR project, Boulder assumed Deethree’s dominant land position in the Pembina-Brazeau Belly River area of Alberta. Granite has far outperformed Boulder and, as of April 2016, is the only independent entity left from the Deethree reorganisation.

Full report – February 2016 and April 2016

For our full report history, click here.

October M&A HZ CTA

 

Baytex deal reveal

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4 new charts tell us how far the Permian is outstripping rival U.S. oil producing regions

New data illustrates exactly how far the Permian basin is outstripping its rivals in terms of investor interest and deal flow.

The stark reality is that M&A activity focused on the Permian has hit a total of almost $23 billion over the past 21 months – around $16 billion more than its nearest rival, according to our new Evaluate Energy data. This trend of high spends in the Permian basin is also highlighted in our latest Q3 M&A report – 33% of all upstream deals worldwide in Q3 focused upon the Permian basin alone. Find out more.

Permian-Confidence-Chart-01

Source: Evaluate Energy M&A Database

And this is not because of one mega-deal skewing our data. On the contrary, there were 37 deals over the 21 month period with individual values of over $100million, demonstrating higher levels of confidence in the Permian as a long-term investment option over other U.S. onshore producing regions.

Permian-Confidence-Chart-02

Source: Evaluate Energy M&A DatabaseTo download our latest quarterly review of global M&A deals, which includes a detailed look at Q3 activity in the Permian basin, click here.

This confidence in the Permian compared to other oil-heavy regions – and the Bakken in particular – is not only illustrated in M&A activity but also in how much companies are currently willing to invest in their own future.

In Q2 2016, the internal financing gap – that is, the difference between capex and operating cash flow – was far greater for the Permian than all other oil-producing U.S. regions we examined in our latest study. Permian companies recorded an average financing gap per boe of $17/boe in Q2 2016, the highest regional average in the United States. This used to be how we’d describe the Bakken, but that picture has changed dramatically since commodity prices crashed; in Q2 2016, Bakken companies recorded a financing gap per boe of only $5/boe.

Permian-Confidence-Chart-03

Source: Evaluate Energy U.S. Cash Flow Study 2016. See notes for details on calculations and company selection.

The large financing gap in the Permian is driven primarily by extremely robust capex spends. For, while total spending has fallen in the Permian over time, it has done so at a dramatically slower rate than other U.S. oil producing areas. This tells us how confident the operators must be feeling.

To reinforce this narrative, in our latest U.S. cash flow study, we used current financing gaps to calculate what oil producers across the country needed the benchmark WTI price to be in order to cover the entirety of their capex spends using only operating cash flow.

In the case of the Permian, the companies would need a $71 WTI price to do this in Q2 2016. For the Bakken, that price is only $52. In Q2 2016, WTI only averaged $44.86. Our latest cash flow study delves into this calculation in far greater detail.

This figure should not be considered a break-even number, not least because capex spending is optional, for the most part. Rather, it’s a barometer of operators’ confidence in their own long-term prospects.

Permian-Confidence-Chart-04

Source: Evaluate Energy U.S. Cash Flow Study 2016, see notes for more details on calculations and company selection

Clearly, capex plans are lower and less bullish than a year before, as low prices continued to bite. But Permian operators are undoubtedly still displaying a greater level of confidence in being able to fund robust capex spends than their rivals.

CTA-US-Cash-Flow-2016

Notes

  • Company selection – In the U.S. Cash Flow Study referred to throughout this piece, we took 68 representative U.S. oil and gas producers for analysis. They were divided up into peer groups, depending on the size of their production and how much oil each company produced compared to natural gas. A handful of the 68 companies were also taken as representative of a specific region’s cash flow trends, because all or the overwhelming majority of the company’s operations was located in one particular area. Ten such companies were identified for the Permian Basin and six for the Bakken. The peer group named “All majority oil producers” included both of these regional groups, as well as every other company in the overall group of 68 that produced more oil than it did gas (i.e. over 50%) in Q2 2016.
  • Calculations:
  1. The financing gap was calculated by subtracting operating cash flow (including the non-cash effect of changes in working capital) from total capital expenditures.
  2. Financing gap per boe was calculated by taking this figure for all relevant companies and dividing it by the total volume of oil and gas produced over the requisite timeframe, to aid comparability across different regions, regardless of overall production size.
  3. The figures are all calculated on a rolling 12 month basis, i.e. each quarterly figure is the average financing gap per boe over the previous 12 months. This method of calculation diminishes the likelihood of anomalous quarters for individual companies within a peer group skewing the data set.
  4. The WTI price required for operating cash flow to cover the entirety of capex spending was calculated assuming that the only changing variable was the WTI price itself, i.e. all items such as spending, costs, gas prices etc. remained constant.

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