Author: Mark Young

Statoil joins Shell and other foreign companies in exiting Canadian projects

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

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

M&A Jan 2017 CTA

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

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

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

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

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

Rig Locator Chart Q4 2016

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

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

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

Click here for more information on a rig locator membership.

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

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

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

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

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

The three Viking type wells in the study are:

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

PSAC Viking Jan17 Chart 1

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

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

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

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

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

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

PSAC Viking Jan17 Chart 2

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

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

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

PSAC Viking Jan17 Chart 3

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

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Notes

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

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

PSAC Area Map

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Alberta operators face over $2 billion in environmental LLR liabilities

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

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

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

Reclamation LLR Chart

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

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

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

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

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

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

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

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

Book a Demo:CanOils Assets LLR & Suspended Well Data

Notes

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

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

3) All $ amounts refer to Canadian dollars throughout

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

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

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

M&A Chart Dec 2016

Source: CanOils M&A Review, December 2016.

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

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

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

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

M&A Cover Dec 2016

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Why horizontal Cardium wells cost less to drill in 2017

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

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

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

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

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

PSAC Cardium Chart 1

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

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

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

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

PSAC Cardium Chart 2

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

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

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

Click here to access the PSAC Study and sample data.

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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.

CTA HZ Annual 2016 M&A

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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.

M&A nov 2016 HZ cta.jpg

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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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