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.


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.

CTA guidance 2017 find out more.jpg

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.


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.


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.


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.


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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Analysis of LLR impact in Canada’s largest 2016 M&A deal

A new case study has been created that analyzes changes to Licensee Liability Ratings following Canada’s biggest oil and gas M&A deal of 2016.

LLR programs ensure costs to suspend, abandon, remediate or reclaim a well, facility or pipelines are not borne by the public if a licensee becomes defunct. To fulfill LLR regulations, the value of an operator’s ongoing assets must outweigh any abandonment/reclamation costs.

LLR also impacts M&A deals. Before permitting the completion of a deal, provincial regulators must be satisfied that a deal will not take the acquirer or seller below the specified provincial LLR thresholds. Using LLR data, which is now a standard feature in every CanOils Assets subscription on a well-by-well basis, can help you make sure your M&A deal is safe from this happening.

This new case study provides an analysis of Seven Generation Energy Ltd.’s acquisition of Montney lands and wells from Paramount Resources Ltd. for Cdn$1.9 billion. It estimates the impact this deal had on both companies’ LLR positions, and offers useful insight for potential buyers and sellers of assets.


Click here to download free the 4-page case study.

Book a Demo:CanOils Assets LLR & Suspended Well Data

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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.

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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


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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How we’re using LLR well data to assess Canadian oil and gas producers


New tools have been developed to help Canadian oil and gas producers measure more easily the impact of LLR regulations on well operations and potential asset deals.

Recent changes in Alberta to how the Licensee Liability Rating is applied bring into focus the importance of these regulations in an economy where assets may be under threat.

You’re likely aware that LLR programs ensure costs to suspend, abandon, remediate or reclaim a well, facility or pipelines are not borne by the public if a licensee becomes defunct. To fulfill LLR regulations, the value of an operator’s ongoing assets must outweigh any abandonment/reclamation costs.

We’re using a new tool that allows us to quickly calculate the LLR for individual and clusters of wells. The CanOils Assets LLR data, a new standard addition to every CanOils Assets subscription, also allows us to easily measure how a potential asset purchase or sale could alter a company’s LLR position.

Book a Demo:CanOils Assets LLR & Suspended Well Data

CanOils Assets LLR data includes deemed assets and liability estimates for wells in Alberta, Saskatchewan and British Columbia. This degree of data transparency is excellent for business development and the service and supply sector. We’ve been using the data for pro-forma analysis of M&A transactions and to identify companies in need of abandonment or reclamation services.

For a more detailed look at how the CanOils Assets LLR data can benefit business development, click here for a short case study, which includes pre- and post-transaction LLR estimates for Canada’s biggest deal of 2016.

We’ve also been reviewing the CanOils Corporate LMR Summary module. This module delivers the LMR ratio for all companies as reported by each provincial regulator (AB, SK, BC). For SK, this includes the value of any security deposits provided. Importantly from a business development perspective, the tool can help us find companies whose LMR ratios may be problematic. We’ve found this data especially useful in conjunction with our regular financial reporting. To learn more, click here.

Related links:

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.


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.


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.


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.


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.



  • 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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Upstream M&A in Canada reaches Cdn$165 million in September 2016

Analysis in CanOils’ latest monthly M&A review suggests that the pressure on Canada’s E&P sector to raise external financing to meet capital commitments would appear to be alleviating somewhat, based upon much lower M&A activity levels in September.

A more secure footing for oil prices, coupled with asset portfolios that are now generally better equipped to see out the price downturn, are the main factors we think contributed to this reduced deal flow.

This month, the value of announced M&A deals in the Canadian E&P sector totalled Cdn$165 million, according to our latest CanOils monthly report, which can be downloaded here. This value stands significantly below the Cdn$1.1 billion monthly average in 2016 to date, and considerably below the Cdn$2.2 billion monthly deal value in Canada since the price downturn.


Source: CanOils M&A Review, September 2016

Despite the low activity, interesting trends continue to stand out, most notably activity related to Canada’s private oil and gas companies. InPlay Oil Corp. was the headline maker this month, agreeing two deals with TSX-listed companies aimed at creating a Pembina-Cardium focused producer in west central Alberta. These deals are featured heavily in this month’s report, along with the completed deals to take both Bankers Petroleum Ltd. and Yoho Resources Inc. into private hands.

The report also provides insight into Alberta’s privately-held junior producers, namely companies that produce between 1,000 and 10,000 boe/d. At the end of August 2016, there were 44 privately-held companies that operated this level of production in Alberta.

For more on these private junior companies, as well as analysis on every deal story impacting the Canadian E&P sector in September, download the report here.


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Share issuances in vogue for U.S. oil & gas companies in 2016

The amount of cash raised by 68 U.S. oil and gas companies via a net issuance in new shares soared to a three-year high of $19.4 billion in Q2 2016, according to Evaluate Energy’s new study focused on U.S. oil and gas company cash flow, which can be downloaded here.

In response to changing attitudes to debt and fewer asset sales, companies have been more inclined to issue shares to source external cash in recent periods (see notes). This trend started in Q1 2015, as the commodity price downturn began to impact cash flow, and has become more pronounced ever since.


Source:  Evaluate Energy Study – Cash Flow in U.S. Oil & Gas (Appendix)

Cash sourced via net share issuances made up 43% of all external cash raised in Q2 2016. This stands in stark contrast to periods before the downturn; in Q3 2014, only 16% of external cash raised came from net share issuances.

This finding is among several key conclusions of the new study that unpacks the altered relationship between cash flow and capital expenditure in the U.S. oil and gas space. For more information on the study, click here.

Of course, the value of the individual shares being sold will be much lower than in 2013 or 2014, but U.S. oil companies have clearly had success selling shares in recent periods, despite the challenging climate, perhaps looking to benefit from bargain hunting investors looking to enter the oil market at a low price.

The movement towards share issuance in part reflects the oil price drop and a major reduction in the ability to secure debt financing, given continued market uncertainty. Since Q3 2014, the amount of cash raised by U.S. oil and gas companies via a net increase in debt dropped by almost two-thirds to US$14.2 billion. The study discovered that, in fact, the 68 U.S. companies raised the least amount of cash in Q2 2016 through net debt increases than in any other quarter over the entire three year period.

Cash raised via net asset or business unit sales also dropped in 2016 compared to periods before the downturn. The 68 companies raised 69% less cash from net asset or business unit divestitures in Q2 2016 compared to Q3 2014, the final period before the price downturn began.

This raising of external finance, and the movement towards issuing shares, has been necessary for U.S. oil and gas companies because their operating cash flow is not covering their capital expenditure needs. While this internal financing gap between operating cash flow and cap-ex was at its tightest in Q2 2016 compared to any other period over the last three years, external cash in some form was still required.


Source:  Evaluate Energy Study – Cash Flow in U.S. Oil & Gas

Of course, cap-ex is not the only cash outflow that oil and gas companies have seen piling up in recent times. However, it is encouraging that the majority of the 68 companies, despite their varying financing gaps, were actually able to cover all cash outgoings in Q2 2016 with a combination of operating cash flow and external cash sources – and many of the companies have a successful share issuance to thank.



  • External cash in this report and the Evaluate Energy study is all cash raised excluding operating cash flow. This includes net increases in debt, net issuances of shares and net sales of assets or business units.
  • For all items above described as “net”, such as net increase in debt for example, the cash out-flows related to debt was subtracted from the cash in-flows related to debt in each period, and only the resultant positive net item was included as a cash in-flow. For net share issuances, the calculation was carried out by combining cash inflow from the sale of new stock and cash outflow from stock repurchases. For net sales of assets or business units, any cash inflow from the sales of assets or businesses was combined with cash outflows from asset or corporate acquisitions.

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Global upstream oil and gas M&A hits $24.1 billion in Q3 2016

Spending broadly keeps pace with previous quarter

In Q3 2016, there was $24.1 billion of new upstream oil and gas M&A deals, according to Evaluate Energy’s most recent quarterly review of upstream M&A activity. The report, which delves into every major deal around the world in Q3 2016, is available for download now.

This quarter’s total deal value falls just short of the $26.5 billion spend in Q2 2016, but marks an increase compared with the $17.7 billion spend in Q3 2015, according to Evaluate Energy’s report.

The backdrop for the quarter was of a WTI oil price that averaged $44.74, marginally down on the average of $45.58 during Q2 2016 but with much less volatility; the oil price never breached $50 and only once closed a day lower than $40 in the entire three month period.


Source: Evaluate Energy Upstream M&A Review, Q3 2016

In the main, deals were targeted in areas with the best short to medium term reward:

  • The Permian basin, economically one of the best in the United States due to its multi-stacked pay zones, attracted 34% of the total spend during the quarter, with 10 of the deals in the basin this quarter being agreed for over $100 million.
  • The Marcellus play, which is proving to be amongst the most economic gas plays in the United States, attracted the largest deal of the quarter when Rice Energy Inc. acquired Vantage Energy LLC for $2.8 billion.

As usual, the United States saw the bulk of the deal value, but the biggest Canadian deal of 2016 also took place in Q3 2016, while Statoil ASA agreed a significant deal in Brazil with Petrobras over the Carcara pre-salt oil discovery.

Top 5 upstream deals around the world in Q3 2016


Source: Evaluate Energy Upstream M&A Review, Q3 2016


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U.S. oil and gas production growth stalls as companies cut cap-ex by 57% since 2014

Dramatic shifts have taken place in the way U.S. oil and gas operators view cash flow, capital expenditure (cap-ex) and market risk – with companies closer today to being able to fund cap-ex plans with only their operating cash flow than at any point since the price downturn began.

U.S. oil and gas companies spent 57% less in cap-ex in Q2 2016 compared to the end of 2014 on a rolling 12 month basis – and this is finally having a material impact on production. That is one of the key findings of a far-reaching study of cash flow trends for 68 U.S. oil and gas companies by Evaluate Energy.

The study examines the size of the financing gap that exists between a company’s operating cash flow and its cap-ex spending. This gap varies very significantly, depending on the size of company and location of its production, and this large cut in cap-ex is undoubtedly a key driver of falling financing gaps in more recent periods.

Click here to read the full report.


Source: Evaluate Energy Study – Cash flow in U.S. Oil & Gas

The size of the internal financing gap is crucial, not least because it determines how far each company is able to fund cap-ex via after-tax profits and conversely its level of reliance upon external cash to fund development plans. It also provides a gauge of company confidence – and, crucially, it points to how far benchmark prices would need to rise to ensure a company could entirely fund cap-ex using just operating cash flow.

The sharp cut off in cap-ex over the past two years is finally starting to bite on production. Cap-ex has been cut across the board since the end of 2014. While production trended upward from 2013 for a few quarters into 2015, we are now starting to see the rate of growth decline. While Q2 2016 production is around 40% higher than Q1 2013, it is similar to Q1 2016.


Source: Evaluate Energy Study – Cash flow in U.S. Oil & Gas

“This production plateau does not bode well for near-term cash flow growth, assuming there is no sudden and significant recovery in commodity prices,” said Mark Young, senior analyst at Evaluate Energy. “Cash from operations will fall if production begins to drop, and this could lead to further cap-ex cuts.”

The Evaluate Energy study provides analysis on pricing per region based on an analysis of 68 representative U.S. oil and gas companies within its coverage of all U.S. stock exchange-listed operators.

“U.S. oil and gas companies are moving closer to being able to fund cap-ex plans with only operating cash flow than at any point during the past three years,” said Young. “But relatively smaller producers have a much greater reliance on externally sourced cash with greater financing gaps than larger producers.”

Click here to read the full report, which also studies the varying financing gaps between Bakken, Marcellus and Permian Basin producers.


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