ShaMaran 2019 Year-End Financial and Operating Results

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VANCOUVER, MARCH 3, 2020 /CNW/ - ShaMaran Petroleum Corp. ("ShaMaran" or the "Company") (TSX VENTURE: SNM) (OMX: SNM) today released its financial and operating results and related management discussion and analysis for the three months and year ended December 31, 2019. All currency amounts indicated as “$” in this news release are expressed in United States dollars. 

“The Atrush Block delivered significant production growth as planned and ahead of schedule. In 2019, Atrush reached another production milestone, commissioned a new production facility and met production targets,” said ShaMaran President and CEO Dr. Adel Chaouch. “With significant gains in production and a larger working interest in Atrush, up from 20.1% at end of last year to 27.6% at end of current year, the Company has created greater cash flow and future growth. Based on continued operational success, the Company believes Atrush provides a strong and stable foundation to fund organic growth and act on potential accretive opportunities.



Achieved significant milestone: Total oil exported from the Atrush field since commissioning in 2017 reached 25 million barrels in February 2020.

Strong production performance: Atrush produced 46% more oil in 2019 compared to 2018 production (32,393 barrels of oil per day (“bopd”) vs. 22,157 bopd) and was within production guidance range of 30,000 to 35,000 bopd. Production trended up throughout the year and in Q4.2019 was 52% more than in Q4.2018 production (41,648 bopd vs. 27,426 bopd). Since the CK-15 well came online in December, Atrush average daily production was over 47,450 bopd and, during this period, intermittently reached the upper range of our exit rate guidance of 50,000 bopd.

Increased capacity throughout the year: Atrush well capacity was in excess of the newly deployed processing capacity by end of 2019, mainly due to a drilling campaign which delivered four production wells ahead of schedule and under budget resulting in an increase by 24,000 bopd. Of the total increase, 8,000 bopd came online in Q4.2019 through the completion of the CK-15 well. Atrush production capacity increased to over 50,000 bopd by end of 2019, up by more than 20,000 bopd over last year end due to upgrades and debottlenecking of the Atrush Permanent Production Facilities (“PF-1”) and the addition of an Early Production Facility (“EPF”).

Strengthened operational cash flows: Operational cash flows, calculated on a normalized basis, increased by $3.5 million (up 14%) from $25.3 million in 2018 to $28.8 million in 2019 due to higher Atrush production and the Company’s increased Atrush working interest. Normalized operational cash flows rose by $9.3 million (up 138%) from $6.7 million in Q4.2018 to $16 million in Q4.2019. The increased cash flows were achieved despite oil sales at average oil prices that were lower by 11% and 9%, between the comparable years and quarters, respectively.  

Decreasing lifting costs: The average lifting cost per barrel of oil produced from Atrush was $7.33 per barrel, down from $7.41 per barrel in the year 2018. The trend in decreasing average lifting costs continued as the year progressed with $5.32 per barrel in Q4.2019 (Q4.2018: $7.84 per barrel). The decrease relates mainly to spreading lifting costs over larger volumes of oil production.

Reserves and Resources

Increased reserves and resources: Total field proven plus probable (“2P”) reserves on a Company gross basis for Atrush increased from 21.3 million barrels reported as of December 31, 2018, to 29.9 million barrels as of December 31, 2019, a 40% increase. Total field unrisked best estimate contingent oil resources (“2C”)(1) on a Company gross basis for Atrush increased from the 2018 estimate of 53.9 million barrels to 67.2 million barrels as of December 31, 2019.

Financial and Corporate

Increased ownership interest in Atrush by 37.3%: The acquisition of an additional 7.5% participating interest in the Atrush Block production sharing contract (“PSC”) was completed during the year, bringing ShaMaran's total interest in Atrush up from 20.1% to 27.6%, giving our shareholders greater exposure to a high-quality, producing asset. 

Continued self-funding of Atrush development: During the year the Company received $55.8 million for its entitlement share of Atrush PSC profit oil and cost oil for deliveries made from October 2018 to July 2019, and collected a further $5.7 million relating to the Atrush Exploration Costs receivable(2). The Company also collected $15.9 million in payments of principal plus interest on the Atrush Development Cost Loan and the Atrush Feeder Pipeline Cost loans. Both loans were fully repaid in October 2019.

(1) This estimate of remaining recoverable resources (unrisked) includes contingent resources that have not been adjusted for risk based on the chance of development. It is not an estimate of volumes that may be recovered.

(2) The Exploration Costs Receivable is related to the repayment of certain development costs that ShaMaran paid on behalf of the KRG which, for purposes of repayment, are governed under the Atrush PSC and the related Facilitation Agreement and are deemed to be Exploration Costs 


The following table includes selected operating and financial information of the Company for the periods indicated. A further discussion of the Company’s operating and financial information for these periods are included in the audited consolidated financial statements for the three months and year ended December 31, 2019 and the related Management’s Discussion and Analysis report. These documents are available on the Company’s website at or on SEDAR at 

Three months ended  Year ended 
December 31  December 31 
2019 2018 2019  2018
Production information
   Atrush average daily oil production - gross 100% field (Mbopd) 41.7  27.4 32.4  22.2
   ShaMaran’s entitlement in Atrush oil sales:
       •  Mbbls related to initial 20.1% interest (full year) 370  276 1,173  871
       •  Mbbls related to additional 7.5% interest (Jun - Dec 2019) 138  - 277  -
       •  Mbbls related to priority cost oil allocation (2018 only)          -           -         -     406
       Total entitlement (Mbbls) 508  276 1,450  1,277
Financial information 
   Revenue 24,345  14,531 70,291  69,600 
   Gross margin / (loss) on oil sales 10,274  (1,438)  20,032  27,528 
   Profit / (loss) from operating activities 7,048  (3,352) 10,553  22,956
   Net finance cost 5,436  6,447 24,599  21,023
   Income / (loss) for the period 1,586  (9,824) (13,397)  1,869
   Cash flow from operations (reported) 1,882  6,722 14,629  47,407
   Cash flow from operations (normalized) 16,030  6,722 28,777  25,279
   Cash in bank 15,530  92,470
   Positive working capital 36,445  112,884
   Total liabilities 226,879  265,577

Atrush production for the year was up 46% over last year and by 52% more in Q4.2019 compared to Q4.2018 mainly due to:

•    Additional production from new wells CK-6, CK-7, CK-10, CK-11, CK-12, CK-13 and CK-15.
•    Installation and operations of the EPF at the Chamanke-E drilling location.
•    Resolution of processing constraints associated with salt production.
•    Debottlenecking of PF-1.

Revenues between 2019 and 2018 appear relatively flat. However, considering the main variances between the two years, when one excludes from 2018 revenues the $22 million of once-off revenue related to the 406Mbbls of entitlement oil under the priority cost oil sharing arrangement(3), there is a $31 million (66.5%) revenue increase. This is attributed to a 46% increase in Atrush production and a 7.5% additional working interest share in Atrush for the last seven months of the year. Performance for 2019 was offset by lower average annual oil prices by $6.04 which had a negative effect of $9 million between the two years. The increase in revenues was more dramatic between 2019.Q4 and 2018.Q4 with a nearly $10 million (67.5%) jump. Despite a $2.4 million negative impact due to selling our oil at lower average quarterly oil prices by $4.66, we benefited from increases of $12 million (84%) due to the much higher Atrush production and our larger working interest piece of Atrush.

Gross Margin was down in 2019 by $7.5 million mainly because the higher production and additional 7.5% working interest share added $9.5 million to lifting costs while revenues remained flat, as explained above. Lower 2019 depletion by $2.5 million offset the increase in lifting costs while higher other costs of production by $1 million, related mostly to the heavy oil extended well test, are also attributable to the variance between the two years. A key determinant to the variance between 2018 and 2019 is there were no incremental lifting costs related to the $22 million of once-off priority cost oil revenues from 2018. The Company’s gross margin of $10.3 million in Q4.2019 was $11.7 million (81%) higher than gross margin in Q4.2018 despite being impacted negatively by $2.4 million due to sales at lower average prices by $4.66. The upward drivers in the Q4 variance were $10.5 million due to the 52% higher production and an additional 7.5% working interest as well as $3.5 million in combined lower depletion and other costs of production. We believe the Q4.2019 gross margin is a good indicator of what Atrush can generate under current production, oil price and lifting cost assumptions.

(3) The Company’s entitlement share in the first two quarters of 2018 included an adjustment for the exploration cost sharing arrangement between TAQA and GEP. TAQA and GEP had under the Atrush JOA agreed a priority arrangement for sharing their combined initial $49.9 million share of exploration cost oil revenues such that TAQA received the initial $10.8 million and GEP received the next $39.1 million. Thereafter cost oil revenues for these two parties has been determined by their relative participating interests in the Atrush PSC. In 2018 the Company completed the recovery of its priority allocation of cost oil with resulted in the receipt of $22 million of cost oil revenues in addition to the Company’s working interest share of cost oil.  

Net loss in 2019 of $13.4 million is attributable to a number of key drivers, several of which are no longer relevant in 2020 and beyond. Oil sales at a lower average annual oil price tightened the gross margin as did the additional other costs of production due to the heavy oil extended well tests which were completed earlier in 2019. Slightly lower depletion costs helped offset these negatives. We are optimistic our 2020 margin will improve on production as 2019 margins were driven by average production of 32.4Mbopd, 45% lower than the midpoint of our 2020 production guidance of 47Mbopd. Several key value-added initiatives to streamline and strengthen the Company’s core business technical capacity, corporate structure and business development function drove 2019 general and administrative expenses higher, though we expect the added costs will be phased out over time. Borrowing costs increased in 2019 mainly due to a one-time adjustment to revalue bonds at the time the bonds were amended In February 2019 and the ratio of borrowing costs expensed to capitalized increased relative to the amount in the prior year. Through a reduction in bond principal in 2019 the Company reduced its annual bond interest expense from $25 million in 2018 to $23 million. We plan to pay down an additional $15 million of bonds around mid-year 2020 which will further reduce our bond interest expense to $21.9 million this year, and the Company continues to investigate options to reduce the significant borrowing costs.

Cash flow from operations (normalized) of $28.8 million is calculated for comparative purposes by adding back the exceptional $14 million relating to a two-month delay at year end in collecting cash for oil sales to the reported cash flow from operations of $14.6 million. We expect in 2020 to return to the regular oil sales collection cycle, having in January 2020 already collected cash for oil sales to reduce the receivables balance by $7 million. Normalized cash flow of $25.3 million for 2018 equates to reported operational cash inflows of $47 million, less the $22 million of cash flows relating to the priority cost oil recovered during the year. The addition of $3.5 million in normalized operational cash flows between the two years is a 14% increase. For Q4.2019, the $16 million of normalized operational cash flow is determined by adding reported operational cash flows of $2 million to the $14 million of receivables which is attributable to the lengthened collection cycle. This compares with reported operational cash flow for Q4.2018 of $6.7 million, which we consider normalized without any adjustment. The $9.3 million increase in normalized operational cash flow between the final quarters of 2019 and 2018 represents a 138% increase.


The Company also reports that it has granted an aggregate of 61,556,665 incentive stock options, restricted share units (“RSUs”) and deferred share units (“DSUs”) to certain senior officers, directors and other eligible persons of the Company. The options are exercisable, subject to vesting provisions, over a period of five years at a price of CAD 0.06 per share. The RSUs are redeemable in shares of the Company or equivalent cash value, subject to vesting provisions, over a period of five years. The DSUs, issued to the Company’s non-executive directors, may not be redeemed until a minimum period of three months has passed following the end of service as a director of the Company. 


This information is information that ShaMaran Petroleum Corp is obliged to make public pursuant to the EU Market Abuse Regulation. The information was submitted for publication, through the agency of the contact persons set out below, at 9:00 Eastern Time on March 3, 2020. 

The Company plans to publish on May 8, 2020 its financial statements for the three months ended March 31, 2020.


This news release contains statements and information about expected or anticipated future events and financial results that are forward-looking in nature and, as a result, are subject to certain risks and uncertainties, such as legal and political risk, civil unrest, general economic, market and business conditions, the regulatory process and actions, technical issues, new legislation, competitive and general economic factors and conditions, the uncertainties resulting from potential delays or changes in plans, the occurrence of unexpected events and management’s capacity to execute and implement its future plans. Any statements that are contained in this news release that are not statements of historical fact may be deemed to be forward-looking information. Forward-looking information typically contains statements with words such as "may", "will", "should", "expect", "intend", "plan", "anticipate", "believe", "estimate", "projects", "potential", "scheduled", "forecast", "outlook", "budget" or the negative of those terms or similar words suggesting future outcomes. The Company cautions readers regarding the reliance placed by them on forward‐looking information as by its nature, it is based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Company.  

Actual results may differ materially from those projected by management. Further, any forward-looking information is made only as of a certain date and the Company undertakes no obligation to update any forward-looking information or statements to reflect events or circumstances after the date on which such statement is made or reflect the occurrence of unanticipated events, except as may be required by applicable securities laws. New factors emerge from time to time, and it is not possible for management of the Company to predict all factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking information. 

Reserves and resources: ShaMaran Petroleum Corp.'s reserve and contingent resource estimates are as at December 31, 2018 and have been prepared and audited in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). Unless otherwise stated, all reserves estimates contained herein are the aggregate of "proved reserves" and "probable reserves", together also known as "2P reserves". Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. 

Contingent resources: Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. There is no certainty that it will be commercially viable for the Company to produce any portion of the contingent resources. 

BOEs: BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf per 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 

News release dated March 3, 2020


ShaMaran Petroleum Corp., Investor Relations  

Sophia Shane
Investor Relations, Canada
+1 604 689 7842

Robert Eriksson
Investor Relations, Sweden
+46 701 112615


ShaMaran is a Canadian oil and gas company with Kurdistan-focus holding, through its wholly-owned subsidiary General Exploration Partners. Inc., a 27.6% interest in the Atrush oil block

ShaMaran is listed on the TSX Venture Exchange and the NASDAQ First North Growth Market (Stockholm) under the symbol "SNM". 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. Pareto Securities AB is the Company’s Certified Advisor on NASDAQ First North Growth Market, +46 8 402 5000, .