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PetroShale Announces Financial and Operating Results and Reserves for the Year Ended December 31, 2017

CALGARY, Alberta, April 23, 2018 (GLOBE NEWSWIRE) -- PetroShale Inc. ("PetroShale" or the "Company") (TSX-V:PSH) (OTCQX:PSHIF) is pleased to announce its financial and operating results for the three and twelve month periods ended December 31, 2017, along with updated petroleum reserves as of December 31, 2017. 

PetroShale will file its audited consolidated financial statements and the corresponding Management’s Discussion and Analysis (“MD&A”) as at and for the year ended December 31, 2017, as well as its 2017 Annual Information Form including its year end reserves disclosures, on SEDAR at, on the OTCQX website at, and will post the information on our website at  Copies of the materials can also be obtained upon request without charge by contacting the Company directly. 

PetroShale continued to focus on acquiring and developing land in the core of the North Dakota Bakken / Three Forks play, leading to substantial production and reserves increases.  As announced on April 2, 2018, we acquired additional acreage in our core South Berthold area for US$17.8 million and generated significant results from recent operated wells which contributed to average working interest production in March 2018 of approximately 5,300 barrels of oil equivalent per day (“boepd”) compared to 2,121 boepd in the fourth quarter of 2017.  Our continued operational success and the completion of a strategic financing in early Q1 2018 have positioned the Company to further increase production, reserves and our high-quality drilling inventory as we move forward.  


  • Production averaged 2,121 boepd (86% liquids) in the fourth quarter, a 14% increase from the fourth quarter of 2016 and a 12% increase from the third quarter of 2017, largely attributable to the impact of three (0.6 net) non-operated wells which commenced production in November 2017.  
  • Average 2017 production increased by 50% to 2,445 boepd (88% liquids), from 1,631 boepd (83% liquids) in 2016. 
  • Revenue in 2017 was $44.0 million, an increase of 89% over 2016. 
  • EBITDA in 2017 was $21.2 million, an increase of 123% over 2016.  
  • The operating netback in 2017 was $27.46 per boe (Company interest, gross of royalty; $34.65 per boe net of royalty), an increase of 36% over 2016. 
  • The average differential between PetroShale’s realized crude oil price and WTI continued to narrow during 2017 to an average of US$2.46 per Bbl in the fourth quarter, down from US$6.21 per Bbl in the fourth quarter of 2016 and US$5.14 per Bbl in the third quarter of 2017, largely due to increased takeaway capacity on the Dakota Access Pipeline.
  • Capital expenditures during 2017 of $67.1 million were directed to drilling and completion activities plus several acquisitions.  One of these acquisitions included the addition of undeveloped acreage in a core focus area, providing us operatorship of a second drilling spacing unit (“DSU”) (“Horse Camp”).  
  • Drilling of two (1.7 net) wells continued during the fourth quarter of 2017 on PetroShale’s first operated DSU in the Antelope area (“Primus”) and two additional operated wells (100% working interest) in the South Berthold area on our Horse Camp DSU, with all four wells being placed into production at various times during the first quarter of 2018. 
  • Oil and natural gas reserve volumes and related net present value (discounted at 10% - “NPV10”) increased across all categories at year end 2017 compared to the prior year:
    • Total proved plus probable (“P+P”) reserves increased 17% to 36.7 million boe (“Mmboe”), from 31.5 Mmboe.
    • NPV10 of the P+P reserves increased 23% to US$493.0 million, from US$399.5 million, despite continued volatility and uncertainty in forward commodity prices.
  • A common share equity offering that netted $106 million in proceeds closed in April 2017 and significantly improved PetroShale’s financial flexibility.  

Recent Developments

  • PetroShale completed four gross (3.7 net) operated wells, resulting in average production of approximately 5,300 boepd of production in March, an increase of approximately 150% over the fourth quarter of 2017. 
  • PetroShale closed US$17.8 million of undrilled acreage additions in its core South Berthold focus area.
  • A strategic financing with a US-based private equity investor, First Reserve, closed in January 2018 for US$75 million of preferred shares with a 5-year term and a 9% coupon rate.  The preferred shares are fully exchangeable into common shares at $2.40 per share.  Proceeds were used to repay and terminate the Company’s subordinated loan facility and repay amounts drawn under the senior loan.  Brooks Shughart, a Managing Director of First Reserve with significant energy experience, joined PetroShale’s board.
  • The capacity of the Company’s senior loan was increased to US$49.9 million in April 2018 following the recent production increase.   


  Three months ended  Twelve months ended 

 December 31,
  December 31,
  December 31,
  December 31,
Sales volumes    
  Crude Oil (Bbl/d) 1,554  1,325  1,878  1,221 
  Natural gas and NGLs (Mcf/d) 3,398  3,218  3,401  2,458 
Barrel of oil equivalent (Boe/d) 2,121  1,861  2,445  1,631 
Operating Netbacks ($/Boe) (1)    
  Revenue$  54.18 $  44.67 $  49.27 $  38.95 
  Royalties (11.03) (9.39) (10.19) (7.99)
  Operating costs (8.01) (7.63) (7.97) (7.86)
  Production taxes (3.97) (3.30) (3.65) (2.96)
Operating netback(2)$  31.17 $  24.35 $  27.46 $  20.14 
Operating netback, on a net of royalty basis(2)$  39.11 $  30.86 $  34.65 $  25.34 

(1) See "Oil and Gas Advisories".
(2) See “Non-GAAP Measures”.


The reserves data in this press release is based upon an evaluation by Netherland, Sewell & Associates, Inc. (“NSAI”) with an effective date of December 31, 2017.  The reserves data summarizes PetroShale’s crude oil and natural gas reserves and the net present value of future net revenue for these reserves using forecast prices and costs. All references to reserves are to gross Company reserves, meaning PetroShale’s working interest reserves before consideration of royalty interests. The reserve report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in National Instrument 51‑101 (“NI 51-101”) and CSA Staff Notice 51‑324.  No attempt was made to evaluate possible reserves.  

2017 Reserves Highlights

  • Total proved (“TP”) reserves increased by 22% to 30.6 Mmboe (US$427.0 million PV10) and P+P reserves increased by 17% to 36.7 Mmboe (US$493.0 million PV10) from 2016;
  • P+P finding, development and acquisition costs (“FD&A”) were $20.30 per boe for 2017 (year ended December 31, 2016 - $9.17 per boe) (including changes in future development capital) and total proved FD&A was $20.08 per boe for 2017 (year ended December 31, 2016 - $10.89 per boe);
  • The three year average P+P FD&A and finding and development costs (“F&D”) costs were $11.87 per boe and $16.89 per boe, respectively;
  • Based on the Company’s fourth quarter of 2017 operating netback of $31.17 per boe, FD&A recycle ratios for P+P and TP were 1.5 and 1.6 times, respectively.   The three year average FD&A recycle ratio was 2.6 and 2.5 times for P+P and TP, respectively;
  • P+P Reserve Life Index (“RLI”) totaled 47.5 years, reflecting annualized fourth quarter of 2017 average production of 2,121 boepd.  Using the Company’s estimated March 2018 production, the P+P RLI would be approximately 19 years; and
  • Our P+P F&D costs for 2017 were higher than the three year average due to a combination of factors, including larger fracs than initially planned on the Horse Camp wells and extreme winter weather in North Dakota that led to higher frac water heating costs, increased downtime and overall higher costs for our new operated wells as well as the costs associated with the workover of the Primus “8H” well. Each of our operated wells also bore 100% of the cost of new roads, pads and facilities and are expected to result in lower construction costs for future wells that will be drilled from these pads. On the positive side, all of the new wells are performing at or above our internal type curves and estimates that are reflected in the NSAI reserve evaluation.

Gross Company Interest Reserves

 Tight OilShale Gas (2)BOE
Reserves Category(Mbbl)(Mbbl)(Mmcf)(Mmcf)(Mboe)(Mboe)
 Developed Producing4,324.33,445.37,202.55,706.35,524.74,396.4
 Developed Non-Producing0.
TOTAL PROVED25,588.620,485.630,083.124,001.530,602.524,485.8
TOTAL PROVED PLUS PROBABLE30,768.824,601.135,809.228,547.036,737.029,358.8

(1) Columns may not add due to rounding.
(2) All of our shale gas reserves represent solution gas associated with our tight oil reserves.

Net Present Value of Future Net Revenue ($ US)

  Before Income Taxes Discounted at (%/year)
 0% 5% 10% 15% 20% 
Reserves Category ($US 000s)  ($US 000s)  ($US 000s)  ($US 000s)  ($US 000s) 
 Developed Producing172,209.8 120,064.1 92,538.8 75,947.0 64,947.3 
 Developed Non-Producing(4.4)(3.9)(3.6)(3.3)(3.0)
 Undeveloped782,755.4 487,142.5 334,467.5 244,155.3 185,430.9 
TOTAL PROVED954,960.8 607,202.7 427,002.8 320,099.1 250,375.2 
PROBABLE169,594.1 101,903.1 65,986.8 44,771.3 31,237.4 
TOTAL PROVED PLUS PROBABLE1,124,555.0 709,105.8 492,989.6 364,870.4 281,612.6 

(1) Columns may not add due to rounding

As a reporting issuer in Canada, PetroShale is required to report its reserves and NPV10 using forecast pricing and costs, as stipulated under NI 51-101.  The forecast prices reflected in the NPV10 is included in our 2017 Annual Information Form, expected to be filed on SEDAR before the end of April, 2018.

Reserves Reconciliation

 Total (Mboe)
 Total Proved Probable Total Proved Plus
December 31, 201625,134.0 6,316.3 31,450.3 
  Discoveries  -    -    -  
  Extensions and Improved Recovery  -    -    -  
  Technical Revisions (1)435.0 45.5 480.4 
  Acquisitions (2)5,688.9 - 5,688.9 
  Dispositions- - - 
  Economic Factors237.1 (227.2)9.9 
  Production (3)(892.5)- (892.5)
December 31, 201730,602.5 6,134.6 36,737.0 

(1) Technical revisions include additional well locations assigned proved undeveloped and probable reserves as well as increased proved and probable reserve assignments to well locations included in the December 31, 2016 reserve report.   These revisions are based on additional technical information gathered in 2017 from analogous wells drilled and completed near our lands and increases in the number of wells planned by operators on our lands. 
(2) The acquisitions amount is the estimate of reserves at December 31, 2017. 
(3) Columns may not add due to rounding.

2017 Capital Program Efficiency

 Finding, Development & Acquisition (“FD&A”)(1)Finding & Development (“F&D”)(1)
 Total ProvedProved plus
Total ProvedProved
plus Probable
Capital Costs ($000s):    
  Acquisitions 15,897 15,897  
  Dispositions - -  
  Capital expenditures   51,121 51,121 51,121  51,121 
  Change in future development capital 60,697 58,393 (17,992) (17,992)
Total FD&A / F&D Costs 127,715 125,411 33,129  33,129 
Reserves additions (Mboe)    
  Net change in reserve volumes 5,469 5,287 5,469  5,287 
  Add back production 893 893 893  893 
  Reserves associated with acquisitions - - (5,689) (5,689)
  Reserves associated with dispositions - -   -  - 
Total additions 6,361 6,179 672  490 
FD&A and F&D Costs ($/boe)$ 20.08 $ 20.30$49.27 $67.60 
Three Year FD&A and F&D Costs ($/boe) (3)$12.62$11.87$17.71 $16.89 
Recycle Ratio (2) 1.6 1.5 0.6  0.5 
Three Year Recycle Ratio (4) 2.5 2.6 1.8  1.8 

(1) The calculation of F&D and FD&A costs incorporates the change in future development capital (“FDC”) required to bring proved undeveloped and probable reserves into production.  In all cases, the F&D or FD&A number is calculated by dividing the identified capital expenditures, after changes in FDC, by the applicable reserves additions.  We have disclosed both finding and development costs and finding, development and acquisition costs because acquisition costs have been a significant component of our total capital expenditures and strategy, and also due to the difficulty in allocating changes in future development costs between reserve additions from drilling, technical revisions and acquisitions.  For purposes of calculating finding and development costs, we have chosen to reflect the change in future development costs associated with drilling activity during the period and exclude the increase in future development costs associated with acquisitions during the year. 
(2) Recycle ratio is defined as operating netback, for the fourth quarter of 2017, divided by F&D or FD&A costs, as applicable, on a per boe basis.  Operating netback is calculated as revenue (including realized hedging gains and losses) minus royalties, operating costs and production taxes.  PetroShale’s operating netback in the fourth quarter of 2017 averaged $31.17 per boe.  
(3) The calculation of the three year FD&A and F&D costs reflect the sum of the capital costs and net reserve additions for the years ended 2015 through 2017. 
(4) The calculation of the three year recycle ratio reflects the operating netback for the fourth quarter of 2017, divided by the three year F&D or FD&A costs, as applicable, on a per boe basis.  

Net Asset Value (“NAV”) per Share as at December 31, 2017  
($ thousands, except share and per share amounts)  
 Proved Plus Probable Reserve Value (NPV10 Before Tax)$ 618,702 
 Undeveloped Land Value 6,802 
 Net Debt (including Decommissioning Obligation)(2) (95,617)
 Total Net Assets  $ 529,887 
 Common Shares Outstanding   157,137,767 
 Estimated Net Asset Value per Basic Common Share(1)$ 3.37 

(1) Net asset value is calculated as at a particular date and is, by its nature, historical, and may not be reflective of PetroShale's future performance.  The NAV Reflects the NPV10 of the Company’s reserves at an exchange rate of US$1.00 = Cdn$1.26.
(2) See “Non-GAAP Measures”.


2017 was a year in which PetroShale established itself as an operator within the core of the prolific North Dakota Bakken / Three Forks play.  In 2017, we increased our acreage position through a number of acquisitions totalling $15.9 million and participated in 94 gross (7.0 net) operated and non-operated wells.  The Company’s activity contributed to average annual production volumes of 2,445 boe/d, an increase of 50% over the prior year.    

Subsequent to year end, we announced the results of four (3.7 net) operated wells on our Primus and Horse Camp DSUs that were brought on line during the first quarter of 2018.    These wells had a material impact with net production increasing to an estimated 5,300 boe/d in March of 2018.  At the end of the second quarter we also anticipate production from four (1.6 net) new non‐operated wells on the “Packineau” DSU. In addition, by the end of the second quarter, all of our new operated wells will have been tied-in to natural gas gathering pipelines which will also positively impact our production volumes going forward. 

Although crude oil prices have remained volatile, both WTI benchmark prices and differentials improved during the fourth quarter.  The commencement of operations of the Dakota Access Pipeline, which significantly enhances takeaway capacity from the Bakken to the Gulf Coast and other markets, contributed to stronger realized pricing and helped to slightly offset a lower US$ / CAD$ exchange rate.  Realized natural gas yields have increased relative to 2016 as a larger percentage of our gas production is processed into natural gas liquids (“NGLs”), the pricing of which has improved in lock-step with crude oil.  

Our year end 2017 reserves evaluation reflects the impact of acquisition activity as well as our robust drilling and completions program.  We successfully recorded reserves volume and value increases across all categories.  Our P+P reserves increased 17% to 36.7 Mmboe, from 31.5 Mmboe at December 31, 2016, while our P+P NPV10 increased 23% to US$493.0 million.  On a TP basis, reserves increased 22% to 30.6 Mmboe with a 28% increase in NPV10 to $427.0 million.  We achieved this growth responsibly, with P+P FD&A costs averaging $20.30 per boe (including changes in future development capital), generating a P+P recycle ratio of 1.5 times. 

Maintaining ample liquidity and access to capital has remained a priority for PetroShale as we continue to grow and increase our number of operated DSUs.  In the second quarter of 2017, we successfully closed a $110 million equity offering and increased our borrowing capacity to US$39.9 million under our senior credit facility, all of which gave us substantial undrawn credit capacity.  Early in 2018, we further enhanced our financial position through a strategic US$75 million placement of preferred shares with First Reserve, a US-based energy-focused private equity firm.  This transaction enabled us to repay all amounts owing under the subordinated credit facility and senior credit facility.  With this transaction, PetroShale can pursue future potential land acquisitions and fund our attractive drilling opportunities. 

The quality of PetroShale’s asset base and our ability to generate compelling economics during a period of continued oil price recovery was demonstrated by stronger performance in 2017 relative to 2016.  With a 2017 operating netback of $27.46 per boe ($34.65 per boe on a net of royalty basis) and higher production volumes, we grew EBITDA by 123% over 2016 to $21.2 million.  We anticipate that improving oil prices and lower fixed operating costs per BOE, following recent increases in production, will contribute to further netback improvements in 2018. 

PetroShale’s ongoing evolution and growth have set the stage to generate per share growth in production, reserves and EBITDA.  We continue to seek opportunities to enhance our high-quality asset base within or adjacent to our core areas and look forward to further results as we continue to develop our lands.  In 2018, we plan to drill approximately 7 to 8 net wells of which 5 to 6 net wells will be operated.   It is anticipated that the drilling program will commence in the third quarter of 2018 and continue into the first quarter of 2019 with completion and tie-in operations.

I would like to thank all of PetroShale’s employees, directors and shareholders for your continued support of our strategy and our Company, and we look forward to updating you on our progress and achievements through the balance of 2018.


Mike Wood
President & CEO

About PetroShale

PetroShale is an oil company engaged in the acquisition, development and consolidation of interests in the North Dakota Bakken / Three Forks.   

For more information, please contact: 

PetroShale Inc.
Attention: President and CEO
Phone:  +1.303.297.1407


Cindy Gray
5 Quarters Investor Relations, Inc.
403.828.0146  or 

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

Note Regarding Forward-Looking Statements and Other Advisories

This press release contains forward-looking statements and forward-looking information (collectively "forward-looking information") within the meaning of applicable securities laws relating to, among other things, available aspects of management focus, objectives, strategies and business opportunities. More particularly and without limitation, this press release contains forward-looking information concerning: the opportunity to use available and undrawn amounts under the Company's credit facilities to fund drilling and acquisitions, PetroShale's position to achieve future growth in production, reserves and revenue; PetroShale's intention to seek out land acquisition opportunities; the sufficiency of the Company's financial flexibility and capital requirements; the Company's growth and development plans, including anticipated new well production; the anticipated  benefits to the Company from certain infrastructure investments on its properties; the Company's participation in drilling opportunities and the future prospects for new wells (including with respect to the Company’s planned 2018 drilling program); anticipated connection of new wells to gas gathering infrastructure; the impact of recent pipeline development on future oil price differentials; anticipated production increases and associated netback increases; and the general outlook of the Company. PetroShale provided such forward-looking statements in reliance on certain expectations and  assumptions that it believes are reasonable at the time, including expectations and assumptions concerning prevailing commodity prices, liquidity, exchange rates, interest rates, applicable royalty rates and tax laws; future production rates and estimates of operating costs; performance of existing and future wells; reserve volumes; business prospects and opportunities; the availability and cost of financing, labor and services; the impact of increasing competition; ability to market oil and natural gas successfully; and the Company's ability to access capital.

Statements relating to "reserves" are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

Although the Company believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because the Company can give no assurance that they will prove to be correct. Forward-looking information addresses future events and conditions, which by their very nature involve inherent risks and uncertainties. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits the Company will derive therefrom. Management has included the above summary of assumptions and risks related to forward-looking information provided in this press release in order to provide security holders with a more complete perspective on the Company's future operations and such information may not be appropriate for other purposes.

Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website ( These forward-looking statements are made as of the date of this press release and the Company disclaims any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

Non-GAAP Measures:

Within this press release, references are made to “NAV”, “operating netback”, “operating netback on a net of royalty basis”, “net debt” and “EBITDA”, which are not recognized measures under IFRS and therefore may not be comparable to performance measures presented by others.  EBITDA means net income (loss) before taxes, depletion and depreciation expense, exploration and evaluation expense, any impairments, finance expense, any gain or loss on property dispositions, foreign exchange gain or loss, share-based compensation expense and unrealized gain or loss on financial derivatives.   Operating netback means revenue less royalties, production taxes and operating costs and has been presented on a per Boe basis.  Operating netback on a net of royalty basis represents operating netback divided by production, net of royalty interests.  Net debt represents total liabilities less current assets.  NAV means net asset value, which is the NPV10 before tax of the Company’s proved plus probable reserves, less net debt.  Management believes that in addition to net income (loss) and cash flow from (used in) operating activities, EBITDA and operating netback are useful supplemental measures as they assist a reader in the determination of the Company's operating performance, leverage and liquidity. Management believes NAV or net asset value is a useful measure as it assists the reader in determining the Company’s value per share.  Readers are cautioned, however, that these measures should not be construed as an alternative to net income (loss) or cash flow from (used in) operating activities and consolidated assets as determined in accordance with IFRS as an indication of our performance or value.

Oil and Gas Advisories:

This press release contains certain oil and gas metrics such as "finding and development costs" (or F&D), "finding development and acquisition costs" (or FD&A), "Recycle Ratio", and "Reserve Life Index", which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons.  Such metrics have been included in this document to provide readers with additional measures to evaluate the performance of our oil and gas activities however, such measures are not reliable indicators of our future performance and future performance may not compare to our performance in previous periods and therefore such metrics should not be unduly relied upon.  We have disclosed both finding and development costs and finding, development and acquisition costs as measures in this press release because acquisition costs have been a significant component of our total capital expenditures and strategy, and also due to the difficulty in allocating changes in future development costs between reserve additions from drilling, technical revisions and acquisitions.    We believe both measures are useful measures for readers to determine the efficiency of our acquisition and development program.  Recycle Ratio is defined as operating netback divided by F&D or FD&A costs, as applicable, on a per boe basis. Management uses this measure as an indicator of profitability of its oil and gas activities. Reserves Life Index is calculated as total company share reserves divided by annualized current production. Management uses this measure to determine how long the booked reserves will last at current production rates if no further reserves were added.

Where amounts are expressed on a barrel of oil equivalent (“Boe”) basis, natural gas volumes have been converted to Boe using a ratio of 6,000 cubic feet of natural gas to one barrel of oil (6 Mcf: 1 Bbl).  This Boe conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf: 1 Bbl, utilizing a conversion ratio at 6 Mcf: 1 Bbl may be misleading as an indication of value.  In this release, mboe refers to thousands of barrels of oil equivalent, while mbbls refers to thousands of barrels of oil, and mmcf refers to millions of cubic feet of natural gas. 

All dollar figures included herein are presented in Canadian dollars, unless otherwise noted. 

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