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.

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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.


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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The Top 10 Private Oil & Gas Companies in Alberta

Analysis using CanOils Assets shows that private companies oversaw around 330,000 boe/d of production in Alberta in July 2016, 74% of which was natural gas. To put this into perspective, this is almost six times the volume produced by private companies operating in B.C. in the same month (see note 1).

Source: CanOils Assets – find out more

Of these companies, Ember Resources Inc. is the single largest private operator with more than 53,000 boe/d in July 2016. Ember is owned by a consortium of investors including Brookfield Asset Management. The company’s assets are mainly located in the PSAC regions of Southeastern Alberta (AB3) and Central Alberta (AB5) and are nearly entirely comprised of natural gas wells. The second largest producer, Jupiter Resources Inc., is also backed by an investment firm, Apollo Global Management, and operated 36,500 boe/d of production in July 2016.

The company with the largest diversification in terms of the location of its operated wells is China-backed Calgary Sinoenergy Investment Corp., which operates around 24,000 boe/d after the completion of its Cdn$770 million acquisition of Long Run Exploration Ltd. in June 2016. The company operates wells in five PSAC regions in Alberta.


Source: CanOils Assets – find out more


1) “Production” in this article refers to operated production, rather than working interest production. CanOils Assets does also include working interest production estimates for every company with an ownership stake in a producing well in Canada, but this article only focuses on production from wells where each company is listed in government data as the operator.

2) All data included in this article is sourced from CanOils Assets. Find out more about CanOils Assets here.

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Why Europe is pivotal to LNG growth

Europe will play a pivotal role in the performance of LNG markets globally amid ongoing concerns over gas over-supply, reduced demand in some quarters and pressure on prices.

The major question remains the extent to which Europe can absorb increased gas volumes as part of goals to de-carbonize economies, promote renewables, ensure pricing remain competitive, safeguard energy security and deliver diversity of supply.

Monika Zsigri, an energy policy officer with the European Commission, confirmed that as EU domestic gas production decreased, net EU gas imports increased by 11% last year. LNG shipments bound for Europe rose 6%, as did LNG’s share of the imported gas mix, to 13%.

Qatar remains the largest supplier of LNG to Europe, with a 56% market share, followed by Algeria and Nigeria. While the direct impact of U.S. LNG has not been significant in Europe, it is putting downward pressure on prices. “There is a lot of gas in the market, and the market is fairly flat in Asia,” Zsigri said at the LNGgc Conference in London this week.

LNG import capacities are set to increase dramatically in several European countries by 2025, notably in the United Kingdom, France, Ukraine, Poland, Greece and Croatia, according to Evaluate Energy data.


Source: Evaluate Energy (see note 1)

Costanza Jacazio, a senior gas analyst at the International Energy Authority, expects demand to stabilize in Europe followed by a gradual recovery due in part to retiring coal and nuclear plants. But she said the global rebalancing of markets would depend on the pace of expansion in China, together with other developing Asian nations.

“Japan and Korea will play a much less important role in absorbing new LNG production coming onto the market [in the next five years],” she said. “This means the rest of the world needs to take this incremental LNG.”

Carmen Lopez-Contreras, a senior analyst on Repsol’s gas and power team, said declining European power production (for example in the United Kingdom and the Netherlands) and the need to retain gas supplies while countries adopt more renewable energy solutions will bolster gas demand.

“We have a lot of new volumes coming on-stream,” she said. “Demand has not coped with our expectations. Traditional buyers [like Japan and Korea] have not demanded as much LNG as we are used to. They have turned to coal, which is cheaper. Right now we are at the very bottom of gas prices, but this is incentivizing demand.”

Pricing, volume and destination flexibility will be high on the agenda for buyers facing greater uncertainty and volatility in demand.

“It is very likely markets will struggle to absorb incremental supplies,” said Armelle Lecarpentier, chief economist, CEDIGAZ, the international association for natural gas.

She believes the United States is on track to take the role of swing supplier, adding that the trajectory of global gas markets, and the pace of any market rebalancing, will rest strongly on demand in China and developing Asian nations. She sees this flexible LNG going to new importers in South East Asia, South Asia, North Africa and Latin America. She feels the rise of renewables and increased energy efficiency will temper additional European demand.


1) Proposed import capacity for end 2025 is calculated assuming that all currently active import terminals remain in operation and all proposed projects, regardless of current status, reach completion at their respectively scheduled onstream dates.

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The Top 10 Private Oil & Gas Companies in British Columbia

Analysis using CanOils Assets shows that production from private operators in British Columbia has increased by 76% within one year, based on July production figures. In July 2016, private companies were the operators of just over 56,000 boe/d, compared to 32,000 boe/d a year earlier.


Source: CanOils Assets – find out more here.

The biggest private producers – based on operated production – are located in the areas of the Montney. This is perhaps unsurprising given the surge in activity over the past few years within the areas of one of Canada’s premier plays.

Canbriam Energy Inc., is British Columbia’s largest private producer, based on operated production as of July 31, 2016. The company operates in the Altares region of the Montney, and its operated wells produce around 22,300 boe/d. Every other private producer that operates volumes of over 1,000 boe/d is also located in the area of the Montney, apart from GS E&R, a South Korea-backed entity with 1,500 boe/d in the Liard Basin.


Source: CanOils Assets – find out more here.

More Montney assets hit market in wake of Seven Generations’ Cdn$1.9bn deal

Two Canadian producers are seeking to capitalize on the enduring pulling power of the Montney play by putting assets up for sale, according to CanOils’ newest report focused on M&A activity in August.

RMP Energy Inc. (TSX:RMP) and Chinook Energy Inc. (TSX:CKE) have healthy balance sheets and a good inventory of development assets. Both have extensive holdings in the Montney shale. They form the bedrock of the total 12,700 boe/d of publicly disclosed Canadian assets put up for sale in August 2016. The listings follow the recent Cdn$1.9 billion acquisition by Seven Generations Energy Ltd.’s (TSX:VII) of predominantly Montney assets from Paramount Resources Ltd (TSX:POU), which showed Montney assets can still attract strong interest for high value deals.

RMP Energy Inc.

The largest Canadian asset listing in August involved RMP Energy initiating a strategic alternatives process, retaining Scotia Waterous and FirstEnergy Capital Corp. The majority of RMP’s production is derived from the Ante Creek and Waskahigan fields. RMP produces 8,425 boe/d (43% liquids) based on Q2 2016 production figures. The company owns 24.6 million boe of 1P reserves (36% liquids).

Active RMP Energy Inc. wells as of July 31, 2016


Source: CanOils Monthly M&A Review, August 2016

Chinook Energy Inc.

Chinook Energy Inc. has also initiated a strategic alternatives review and has retained Peters & Co. as its exclusive financial advisor. Chinook is predominantly Montney-focused with 2,890 boe/d of production during Q2 2016 and 12.9 million boe (16% liquids) of 1P reserves. Chinook said it is open to expanding its core operations via acquisitions or by establishing a new core of operations. They will also entertain a merger, sale or JV with a well-capitalized entity to help develop existing assets.

Also this month…

Away from the Montney, August saw Virginia Hills Oil Corp. (TSX-V:VHO) initiate its own strategic review process, while Grant Thornton, in its role as receiver for RedWater Energy Corp., retained CB Securities to advise in the sale of a portion of RedWater’s assets.

Full details on all of these assets up for sale, as well as a detailed look into all of August’s biggest M&A stories, can be found in CanOils’ latest monthly M&A review of the Canadian E&P industry, which is available for download now.


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