PSAC launches 2017 Well Cost Study in new digital format

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Today, the Petroleum Services Association of Canada (PSAC) and JWN announce the launch of the 2017 PSAC Well Cost Study in a new digitized format, offering users a fully customizable database to compare well costs in more than 150 categories.

The Study provides financial, geological and technical data, plus detailed wellbore graphics for each well, allowing users to quickly review detailed estimates for Canadian drilling and completion costs.

PSAC President and CEO Mark Salkeld said: “The Study is an essential tool for producers, development planners, drilling/completions engineers and petroleum service companies. Well costs are assembled by independent drilling experts and include approximately 50 typical wells drilled across Canada, detailed wellbore graphics for every representative well, plus data on more than 100 drilling and completion cost components.”

Bemal Mehta, Senior Vice-President Energy Intelligence at JWN, said: “The PSAC Well Cost Study is a dream come true for engineers and other professionals who spend hours manually putting together Authorizations for Expenditures (AFEs) for drilling and completions programs. Now they have access to digital data that is fully searchable, comparable and customizable and we guarantee the PSAC Well Cost Study will provide you with the most accurate drilling and completions estimates in the business – it’s data for professionals prepared by professionals.”

Among the key benefits of the new digital format:

  • Customizable cost comparisons on typical well costs
  • Quickly build cost estimates for development planning
  • Anonymously acquire drilling and completion costs
  • Benchmark by PSAC region, formation of interest, well type, completion style
  • Download data to Excel in a familiar Approval for Expenditure (AFE) format

Since it was first published in 1981, PSAC’s Well Cost Study has been released twice a year in order to recognize changing costs between summer and winter drilling activity and related expenses. Previously the data was available in PDF format only. By partnering with JWN, the data is now organized in a fully searchable database containing current and historical costs in each category.

“Going digital will significantly increase the Study’s value,” added Salkeld, “as it will continue to capture seasonal changes in costs and enable users to customize reports across different formations, at different times of the year, for much more effective reporting results. PSAC works hard to provide the most current ‘typical’ well costs and this tool will keep this significant report on the leading edge for years to come.”

The new study is powered by Canoils, a leading provider of financial and asset-level oil and gas data for the Canadian market. The PSAC data neatly complements the existing information found within Canoils’ database. Prices for the 2017 PSAC Well Cost Study data start at $3,500. Discounts are available for PSAC members. For more information, click here.

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About JWN

For more than 75 years, JWN has provided trusted energy intelligence. Our energy professionals provide the information, insight and analysis organizations need to stay informed and understand what’s happening in the energy industry. JWN provides a range of products and services to help companies gain the insights they need to stay competitive including industry and company benchmarking, custom data sets, market intelligence, custom intelligence and outlook reports, integrated marketing solutions, and events and conferences. JWN’s flagship products include the Daily Oil Bulletin (DOB), Oilweek and the Comprehensive Oilfield Service and Supply Directory (COSSD).

About Petroleum Services Association of Canada (PSAC)

The Petroleum Services Association of Canada is the national trade association representing the service, supply and manufacturing sectors within the upstream petroleum industry. PSAC is Working Energy and as the voice of this sector, advocates for its members to enable the continued innovation, technological advancement and in-the-field experience they supply to Canada’s energy explorers and producers, helping to increase efficiency, improve safety and protect the environment.

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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.

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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.

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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.

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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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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.

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

Book a Demo:CanOils Assets LLR & Suspended Well Data

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