Source - RNS
RNS Number : 4054X
Serinus Energy PLC
09 August 2018
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Serinus Energy plc

 

Management's Discussion and Analysis

For the three and six months ended June 30, 2018

(US dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

This Management's Discussion and Analysis ("MD&A") for Serinus Energy plc ("Serinus", or the "Company") is a review of the results of operations and the liquidity and capital resources of Serinus Energy plc and its subsidiaries (collectively "Serinus" or the "Company"). The MD&A should be read in conjunction with the unaudited Condensed Consolidated Interim Financial Statements as at and for the three and six months ended June 30, 2018 and the December 31, 2017 audited Consolidated Financial Statements of Serinus and the accompanying notes. Readers should also read the "Forward-Looking Statements" legal advisory contained at the end of this document.

Management is responsible for preparing the MD&A, while the audit committee of the Company's Board of Directors ("the Board") reviews the MD&A and recommends its approval by the Board. This MD&A uses United States dollars ("US Dollars" or "USD") which is the reporting currency of the Company. The accompanying financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") also referred to as GAAP. This document is dated August 9, 2018.

In the Advisory section located at the end of this document, readers can find the definition of certain terms used in the disclosure regarding Oil and Gas Information, Non-IFRS Measures as well as information on "Critical Accounting Estimates". Additional information related to Serinus, is available on Serinus' website at www.serinusenergy.com.

 

 

Highlights

·      On May 3, 2018, the Company redomiciled by means of a continuance to Jersey, Channel Islands. In connection with the Continuance, the Company changed its name from Serinus Energy Inc. to Serinus Energy plc and adopted new charter documents. On May 18, 2018, the Company listed on the Alternative Investment Market ("AIM") market of the London Stock Exchange and closed a placing of 66,666,667 new ordinary shares at 15 pence per share for total proceeds of £10 million. The Company then voluntarily delisted from the Toronto Stock Exchange on May 22, 2018, retaining its listings on the Warsaw Stock Exchange and AIM.

·      During the second quarter of 2018, the Company progressed the construction of the Moftinu gas plant facility in Romania such that pre-commissioning of the plant commenced late June and the plant is currently commissioning. In addition, the Company drilled the Moftinu-1007 well during the second quarter of 2018. This well has been tied into the Moftinu gas plant and is flowing gas as part of the commissioning process for the gas plant. Commercial gas sales are expected to commence in the latter half of August.

·      The Company is currently finalizing a gas sales agreement with an internationally recognized gas trader for the gas production from the Moftinu gas plant.

·      Production was 346 boe/d and 363 boe/d for the three and six months ended June 30, 2018, as compared to 329 boe/d and 513 boe/d, respectively, for the comparable periods in 2017. The increase in production in the second quarter of 2018 as compared to 2017 was attributable to the Sabria field being shut-in from May 22, 2017 until September 2017. The Chouech Es Saida field remains shut in since February 28, 2017. The decrease in production for the six-month periods year over year was attributable to the shut in of the Chouech Es Saida field in Tunisia since February 28, 2017 and lower production from the Sabria field in Tunisia after restarting production in September 2017, following the shut-in period. The Sabria field shut-in was due to social unrest in the southern part of the country, and since restarting production the WIN-12bis well has performed below pre shut-in levels. Oil weighting was 72% in Q2 2018 compared to 74% in Q2 2017.

·      During the three and six months ended June 30, 2018, the Company's revenue was favourably impacted by increasing crude oil prices. The Company's realized oil price averaged $71.74 and $68.73 per bbl for the three and six months ended June 30, 2018, as compared to $47.25 and $49.72 per bbl in the respective periods of 2017, an increase of 52% and 38%. The increase reflected higher Brent prices, with Brent prices averaging $74.50 and $70.65 per bbl, for the three and six months ended June 30, 2018, as compared to $49.67 and $51.68 per bbl for the comparable periods in 2017. The Company realized 97% of the Brent price during the six months ended June 30, 2018, compared to 96% of the Brent price during the six months ended June 30, 2017.

·      Capital expenditures of $5.2 million and $7.4 million were incurred for the three and six months ended June 30, 2018. Capital expenditures in 2018 were focused on the final phase of the construction of the Moftinu gas facility and the drilling of the Moftinu-1007 well.

·      Funds from (used in) operations for the three and six months ended June 30, 2018 were $(0.6) million and $1.9 million, as compared to outflows of $1.5 million and $1.3 million for the comparable periods of 2017. The additional funds from operations in the second quarter of 2018 were primarily attributable to higher revenues net of production expenses in Tunisia. On a year to date basis, funds from operations increased to $1.9 million from an outflow of $1.3 million in 2017, due to a $2.6 million insurance recovery relating to the well incident in December 2017 and higher revenues net of production expenses in Tunisia. This increase was partially offset by $1.3 million of transaction costs incurred related to the Company's continuance to Jersey and AIM listing.

 

 

·      The well incident costs of $4.0 million associated with the emergency operations in December 2017 on the Moftinu-1001 well were fully recognized in 2017. During the first six months of 2018, the Company submitted its first interim insurance coverage claim related to the Moftinu-1001 well incident and has received $2.6 million of insurance proceeds. These proceeds are reported as a recovery in the statement of operations. Subsequent to June 30, 2018, the Company submitted its second interim claim for $1.0 million related to the remaining emergency costs incurred, given this claim was submitted after quarter end the proceeds are not reflected in the June 30, 2018 financial numbers. During the second quarter of 2018, the Company drilled the replacement well, Moftinu-1007, these re-drill costs will form the final part of the Company's insurance claim.

Outlook

The Company is focusing on Romania as the impetus for growth over the next several years. During the second quarter of 2018, the Mofinu-1007 well was drilled to a depth of 1,463 metres, tested and tied into the gas facility. The Moftinu-1000 well has also been tied into the facility and activated for production. Construction of the gas processing facility with 15 Mmcf/d of operational capacity is currently commissioning, without the Low Temperature Separation unit and the Triethylene Glycol unit which are in final assembly, once completed the units will be installed and final commissioning will be undertaken. In the interim, the pre-commissioning and commissioning of the gas plant, less the units, has resulted in the Company flowing gas in late July which was flared. Gas flown through the Gas Plant demonstrated the plant's stability and readiness to operate within designed parameters. Sustained gas production and sales remain dependent upon the connection of the gas plant to the medium-voltage electrical system and final control systems commissioning. The receipt of the electrical permit from the local county authorities was delayed and has resulted in delays for the connection to the medium-voltage line. The Company continues to work with EPC contractor and the Romanian Electrical Company to resolve these issues in a timely manner. It is now expected that sustained gas sales will be in the latter half of August, as the plant commissioning work continues. The Company has informed the EPC contract that late penalties are now being applied against them pursuant to the EPC contract.

The Company is currently finalizing a Gas Sales Agreement with an internationally recognized Gas Trader who will take the Moftinu sales gas and transport through Transgaz's main Abramut-Satu Mare pipeline. The Company is now awaiting for Transgaz to provide the access code to entry in the Transgaz national system. Serinus Energy Romania S.A. has also submitted an application to become a member of the Bucharest Commodity Market.

The Company is also progressing the drilling program to meet work commitments for the extension to October 2019 by drilling two additional development wells, Moftinu-1003 and Moftinu-1004 during 2018. With these wells and the Moftinu-1007 well, the Company will have fulfilled the commitments of the extension (the Company also has the option to conduct 120 Km2 of 3D seismic in substitute for one of the well commitments).  The platform and road construction for the Moftinu-1003 well was completed during July 2018 and the well spud on August 6, 2018.

The Company is planning to drill the Moftinu-1004 well late in the fourth quarter of 2018, subject to rig availability. Combined with the production of the Moftinu-1000 and Moftinu-1007 wells, the Corporation expects the gas plant to be operating at full capacity by early 2019.

In Tunisia, the Company is currently focusing on improving production from Sabria and plans to focus on carrying out low cost incremental work programs to increase production from existing wells. The Company intends to re-enter the Sabria N-2 well and install artificial lift on another existing Sabria well, with the program to be undertaken in the first quarter of 2019. The Corporation views Sabria as a large development opportunity longer term, pending improvement in the social situation in Tunisia.

For the Chouech Es Saida field, the Company does not of yet have a solution for restarting the field, the Company continues to work with the authorities in Tunisia to agree on a solution for restarting the field that will include assurances that the field will not be disrupted due to social issues. The restart of the field will include a capital program to replace the electric submersible pumps for the CS-3 and CS-1 wells.

Operational Overview

Serinus is an international oil and gas exploration and production company with operations in Tunisia and Romania. The Company has its management office in Calgary (Canada) and an investor relations office in Warsaw (Poland).

Included in the MD&A is an analysis of the above operations.

Tunisia

As at June 30, 2018, the Company has the following interests in the concessions in Tunisia:

Concession

Working interest

Expiry date

Chouech Es Saida

100%

December 2027

Ech Chouech

100%

June 2022

Sabria

45%

November 2028

Sanrhar

100%

December 2021

Zinnia

100%

December 2020

The Tunisian state oil and gas company, Enterprise Tunisienne d'Activites Petroliere ("ETAP"), has the right to back into the Chouech Es Saida concession for up to a 50% interest, if and when the cumulative crude oil sales, net of royalties and shrinkage, from the concession exceed 6.5 million barrels. As at June 30, 2018, cumulatively 5.2 million barrels, net of royalties and shrinkage have been sold from the concession. The Company began to generate revenues in Tunisia with its acquisition in September 2013, and since that time has generated $113.5 million of revenue, net of royalties, in aggregate from these assets.

During the three and six months ended June 30, 2018, all production came from the Sabria field. The Chouech Es Saida field had been shut-in since February 28, 2017 originally due to strike notices issued by Tunisia General Trade Union ("UGTT"), which represented the Company's employees at the Chouech Es Saida field. The shut-in was a result of a strike notice and illegal sit-in at the field in response to the Company terminating the employment of 14 of the 52 field employees for economic reasons, even though these terminations were within the right of the Company and strictly followed the appropriate laws, work code and regulations. The terminated employees accepted their termination notices and this sit-in ended early in Q2 2017, but due to social unrest in the south of Tunisia the field remained shut-in. The field was completely shut down during the third quarter of 2017 and all remaining employees terminated.

The Sabria field was shut-in due to social unrest in the southern part of the country from May to September 2017. Production commenced late September 2017 following the end of the protests and having determined that production at its oilfields could be restarted in a safe and secure environment. For the Chouech Es Saida field, the Company is continuing to work with the authorities in Tunisia to agree on a solution for restarting the field that will include assurances that the field will not be disrupted due to social issues.

Romania

Serinus, through its wholly owned subsidiary, Serinus Energy Romania S.A., currently holds a deemed 100% interest in the Satu Mare concession.

Serinus is concentrating on the development of the Moftinu gas discovery, which included building a gas processing facility. The Company entered into an EPCC contract with Confind S.R.L. on May 9, 2017 and the construction of the gas plant with 15 Mmcf/d of operational capacity is currently commissioning, pending delivery of the final units. The Moftinu-1007 well, which was an expedited drill to replace the production initially planned from the Moftinu-1001 well, has been completed in Q2, 2018, tied in and is flowing gas for the purposes of commissioning the plant. Gas sales are expected to commence mid-August. The Company is progressing the drilling program to meet work commitments required for the three-year extension to October 28, 2019 on the concession agreement. The platform and road construction for the Moftinu-1003 well were completed in July and the well spud on August 6, 2018.

The Company is also proceeding to refine and expand the exploration inventory within the concession. Based on older vintage 2D seismic data and existing wells, management has identified over 25 leads and prospects. The exploration program may include acquiring more seismic.

The defaulted partner, who held a 40% interest in the Satu Mare concession declined to participate in future exploration or development phases under the concession and as such has not contributed their share of expenditures to the joint venture. The Company therefore issued a notice of default to the partner in December 2016 under the terms of the joint operating agreement ("JOA"). The partner did not have the necessary means or intention to remedy the situation and as such the partner is not entitled to participate in joint venture operations and has no right to transfer their interest to a third party. The partner is currently in a tax dispute with the government of Romania, the results of which is that the Romanian fiscal authorities have placed a protective seizure order on an account of the partner relating to their past activities on the Satu Mare concession. The primary goal of this seizure order is to prevent the unauthorized flight of capital by the partner out of Romania whilst the tax dispute is adjudicated. The seizure order also has the effect of preventing the transfer of the partner's 40% interest in the Satu Mare concession without the approval of the Romanian fiscal authorities. Serinus is not involved in any manner with this tax dispute and the dispute only relates to the partner. However, the dispute means that any transfer of the partner's interest to the Company necessarily involves conversations with the Romanian fiscal authorities. In August 2017, the Company provided the partner with a Notice of Deemed Transfer pursuant to the JOA. This Notice of Deemed Transfer states that Serinus has claimed this interest without any obligation to the partner going forward and that the partner must without delay, do any act required to render the transfer of the participating interest legally valid, including obtaining all governmental consents and approvals, and shall execute any document and take such other actions as may be necessary in order to affect a prompt and valid transfer of the interest in the Satu Mare Concession. Serinus fully expects the Partner to fulfil this obligation to transfer its interest in the Satu Mare Concession to Serinus in an expedited manner, subject to the approval of the Romanian Fiscal Authorities.

Under the terms of the JOA and pursuant to the notice of default and notice of deemed transfer, Serinus has commercially assumed 100% of the joint venture. The Company has notified the National Agency for Mineral Resources ("NAMR") of the default of the partner and has provided the requisite guarantees to NAMR for 100% of the project. The Company has also communicated the position to the fiscal authorities in Romania. The Company continues to pursue the Partner's adherence to its obligation to transfer the interest, and should this not be forthcoming, pursue any and all legal remedies that would formally see the rightful transfer of the defaulting 40% working interest to Serinus. The Company maintains its right to 100% of the obligations and benefits of commercial activities conducted within the Satu Mare concession.

Given the defaulted partners legal dispute with fiscal authorities in Romania, it is as yet unclear whether the Partner has the ability to transfer its interest in the Satu Mare Concession to Serinus. There is a risk with respect to the timing of the transfer as it is dependent on the Partner in resolving its legal dispute with the fiscal authorities.

The Satu Mare concession is on the border with Hungary and Ukraine within the Pannonian Basin and the term of the concession agreement expires in September 2034.

Other

Serinus has interests in a minor property at Sturgeon Lake in Alberta, Canada. This asset is not currently producing and has a future abandonment liability associated with it of US$1.1 million (CAD$1.4 million). No abandonment work was undertaken during the six months ended June 30, 2018 (six months ended June 30, 2017: $nil).

FINANCIAL OVERVIEW

Funds from Operations

The Company uses funds from operations as a key performance indicator to measure the ability of the Company to generate cash from operations to fund future exploration and development activities.

The following table is a reconciliation of funds from operations to cash flow from operating activities:

 

Three months ended June 30

Six months ended June 30

($000)

2018

2017

2018

2017

Cash flow from operations

$          (2,906)

$             (832)

$          (3,851)

$          (1,387)

Changes in non-cash working capital

2,322

(631)

5,772

90

Funds from (used in) operations

$             (584)

$          (1,463)

$           1,921

$          (1,297)

Funds from (used in) operations per share

$                   -

$            (0.01)

$             0.01

$            (0.01)

Funds used in operations for the three months ended June 30, 2018 was $(0.6) million as compared to $(1.5) million for the three months ended June 30, 2017, a decrease of $0.9 million. The additional funds from operations in the second quarter of 2018 was primarily attributable to higher revenues net of production expenses from Tunisia.

On a year to date basis, funds from operations increased to $1.9 million from an outflow of $1.3 million in 2017. The additional funds from operations in 2018 were primarily attributable to $2.6 million of insurance proceeds recognized related to the one-time well incident in December 2017 and higher revenues net of production expenses from Tunisia, partially offset by higher transaction costs related to the continuance to Jersey and AIM listing.

 

 

Net earnings (loss) and Funds from Operations

The Company uses funds from operations as a key performance indicator to measure the ability of the Company to generate cash from operations to fund future activities. The following table presents a reconciliation of funds from operations to cash flow from operations and segmented net loss:

($000)

Romania

Tunisia

Corporate

Total

For the three months ended June 30

2018

2017

2018

2017

2018

2017

2018

2017

Net earnings (loss)

266

89

40

(771)

(2,925)

713

(2,619)

31

Adjustments for:

 

 

 

 

 

 

 

 

Depletion and depreciation

2

2

378

381

53

34

433

417

Gain on disposition

-

-

-

-

-

(2,179)

-

(2,179)

Accretion expense

7

1

241

170

-

-

248

171

Share-based compensation

-

-

-

-

117

170

117

170

Shares issued as compensation

-

-

-

-

-

7

-

7

Unrealized gain (loss) on investments

-

-

-

-

-

(4)

-

(4)

Unrealized foreign exchange (gain) loss

187

-

(60)

38

(249)

(8)

(122)

30

Deferred income tax expense (recovery)

-

-

548

(781)

-

-

548

(781)

Interest and other income

-

(19)

-

-

-

3

-

(16)

Interest expense

-

-

-

-

811

691

811

691

Decommissioning costs

-

-

-

-

-

-

-

-

Funds from (used in) operations

462

73

1,147

(963)

(2,193)

(573)

(584)

(1,463)

Changes in non-cash working capital

(39)

-

(1,482)

856

(801)

(225)

(2,322)

631

Cashflows from (used in) operations

423

73

(335)

(107)

(2,994)

(798)

(2,906)

(832)

 

($000)

Romania

Tunisia

Corporate

Total

For the six months ended June 30

2018

2017

2018

2017

2018

2017

2018

2017

Net earnings (loss)

3,064

74

222

(1,168)

(4,903)

(974)

(1,617)

(2,068)

Adjustments for:

 

 

 

 

 

 

 

 

Depletion and depreciation

3

3

792

1,155

93

72

888

1,230

Gain on disposition

-

-

-

-

-

(2,179)

-

(2,179)

Accretion expense

26

2

482

340

-

-

508

342

Share-based compensation

-

-

-

-

246

216

246

216

Shares issued as compensation

-

-

-

-

-

7

-

7

Unrealized gain (loss) on investments

-

-

-

-

-

13

-

13

Unrealized foreign exchange (gain) loss

131

-

(25)

33

(642)

95

(536)

128

Deferred income tax expense (recovery)

-

-

869

(378)

-

-

869

(378)

Interest and other income

-

(19)

-

-

-

-

-

(19)

Interest expense

-

-

-

-

1,587

1,411

1,587

1,411

Decommissioning costs

(24)

-

-

-

-

-

(24)

-

Funds from (used in) operations

3,200

60

2,340

(18)

(3,619)

(1,339)

1,921

(1,297)

Changes in non-cash working capital

(2,941)

-

(2,301)

403

(530)

(493)

(5,772)

(90)

Cashflows from (used in) operations

259

60

39

385

(4,149)

(1,832)

(3,851)

(1,387)

 

 

 

Production

 

Three months ended June 30

Six months ended June 30

 

2018

2017

2018

2017

Crude oil (bbl/d)

248

244

262

384

Natural gas (Mcf/d)

585

509

605

771

Total (boe/d)

346

329

363

513

% oil weighting

72%

74%

72%

75%

% gas weighting

28%

26%

28%

25%

Production to June 30, 2018 was exclusively from the Tunisian assets. During the six months ended June 30, 2018, production was only from the Sabria field whereas production was from both the Sabria and Chouech Es Saida fields during the six months ended June 30, 2017.

Production volumes increased by 5% in the second quarter of 2018 to 346 boe/d as compared to 329 boe/d in the second quarter of 2017. The increase in production in the second quarter of 2018 was attributable to the shut-in of the Sabria field from May 22, 2017, with production resuming in September 2017. The Chouech Es Saida field has been shut-in since February 28, 2017, impacting both the second quarter of 2017 and 2018.

On a year to date basis, production volumes of 363 boe/d were less than 513 boe/d in the comparable period of 2017, a decrease of 29%. The decrease in production was due to the shut-in of the Chouech Es Saida field since February 28, 2017 and lower volumes from the Sabria field since resuming production in September 2017 following being shut-in.

Production resumed in Sabria in early September 2017 after being shut-in since May 2017. All wells returned to pre-shut in production levels except for the Win-12bis well which initially decreased by 60% from pre-shut in levels. The Win-12bis well has a history of producing at high water cuts after being shut-in and had continued to improve steadily through 2017, but has stabilized in 2018 at a rate of approximately 145 boe/d, net. The Company performed a slickline operation in Q2, 2018 to investigate the Win-12bis well and may perform a well intervention to improve performance in the future.

Oil and Gas Revenue

 

Three months ended June 30

Six months ended June 30

($000)

2018

2017

2018

2017

Oil revenue (1)

$           1,619

$           1,049

$           3,257

$           3,453

Gas revenue

863

293

1,436

839

Total revenue

$           2,482

$           1,342

$           4,693

$           4,292

Oil revenue (%)

65%

78%

69%

80%

Gas revenue (%)

35%

22%

31%

20%

 

 

 

 

 

Oil ($/bbl)

$           71.74

$           47.25

$           68.73

$           49.72

Gas ($/Mcf)

16.22

6.32

13.11

6.01

Average realized price ($/boe)

$           78.95

$           44.85

$           71.49

$           46.29

(1) 2017 comparatives include "change in oil inventory"

Revenue is currently generated exclusively from Tunisia. The Company is required to sell 20% of its annual crude oil production from the Sabria concession into the local market, which is sold at an approximate 10% discount to the price obtained on its other crude sales. The remaining crude oil production is sold to the international market, through which the Company has a marketing agreement with Shell International Trading and Shipping Company Limited ("Shell agreement").

Oil and gas revenues totaled $2.5 million for the three months ended June 30, 2018, as compared to $1.3 million in the comparable period of 2017. The increase of 85% is attributable to a 5% increase in production and a 76% increase in the average realized price. Crude oil realized prices increased by 52% to $71.74 per bbl which reflects the increase in Brent price over the same periods from $49.67 per bbl to $74.50/bbl. The Company realized 96% of the Brent price during Q2 2018 as compared to 95% in Q2 2017. The average realized price for natural gas increased to $16.22 per mcf as compared to $6.32 per mcf in 2017. The increase was due to an increase in the reference price used to determine the sales price but also a change in the reference price basis, which resulted in an adjustment to prior periods being received in the current period. Natural gas prices are nationally regulated and were tied to the nine-month trailing average of low sulphur heating oil (benchmarked to Brent) prior to 2018. This changed in 2018 to reference the current month average of high sulphur heating oil (benchmarked to Brent), which nets approximately 10% higher pricing. Gas revenues in the three months ended June 30, 2018 include a $0.3 million adjustment relating to October 2017 volumes on this price change. Excluding this one-time adjustment, the realized gas price would have been $10.20 per mcf, 61% higher than the realized gas price in the second quarter of 2017 of $6.32 per mcf due to increased Brent price and the improved gas price calculation.

Similar trends are noted on a year to date basis. Revenues increased by 9% to $4.7 million in 2018 due to a 54% increase in average realized prices offset by a 29% decrease in production. Realized prices increased for similar reasons as noted during the quarter, with Brent increasing to $70.65 per bbl compared to $51.68 per bbl in 2017. The Company realized 97% of Brent on a year to date basis as compared to 96% in the comparable period of 2017. Natural gas revenues include a $0.5 million adjustment relating to Q4 2017 volumes on this reference price change. Excluding this one-time adjustment, the realized gas price would have been $8.40 per mcf, 40% higher than the realized gas price for the six months ended June 30, 2017 of $6.01 per mcf

Prior to 2018, as the crude oil accumulates, the Company recorded commodity inventory at its net realizable value and the change in inventory was recorded in the income statement as "change in oil inventory". The cash that is received monthly from Shell was presented on the balance sheet as "advances for crude oil sales". Once the crude oil was physically lifted onto tankers and title passes, the inventory and advances were reversed and an accounts receivable was set up for the remaining amount due from Shell, and the change in oil inventory in the income statement was reclassified as revenue. Effective January 1, 2018, on adoption of IFRS 15, revenue is recognized once volumes are delivered for lifting at the loading terminal rather than the prior requirement to recognize upon lifting. Thus, the change in oil inventory is now recognized as petroleum and natural gas revenues. This change in revenue recognition under IFRS 15 has no impact on net earnings. On the statement of financial position, commodity inventory, net of advances is recorded as accounts receivable.

Royalties

 

Three months ended June 30

Six months ended June 30

($000)

2018

2017

2018

2017

Royalties

$              242

$               137

$              455

$               445

Royalties ($/boe)

$             7.70

$              4.58

$             6.93

$              4.80

Royalties (% of revenue)

9.8%

10.2%

9.7%

10.4%

Tunisian royalties are based on individual concession agreements. In two concessions, Sabria and Zinnia, the royalty rate varies depending on a calculation of cumulative revenues, net of taxes, as compared to cumulative investment in the concession, known as the "R factor". As the R factor increases, so does the royalty percentage to a maximum rate of 15%. During 2018, the royalty rate in the Sabria concession was 10% for oil and 8% for gas. In the Chouech Es Saida concession, royalty rates are flat at 15%.

Royalties increased to $0.2 million for the quarter ended June 30, 2018 from $0.1 million for the comparable period of 2017, due to an increase in revenue. The effective royalty rate decreased from 10.2% in the second quarter of 2017 to 9.8% in the second quarter of 2018, primarily due to a slightly higher gas weighting in 2018 which has a lower royalty rate than oil in Sabria.

On a year to date basis, royalties are consistent year over year at $0.5 million, reflecting an increase in revenue and a decrease in royalty rates year over year. The average royalty rate for the six months ended June 30, 2018 was 9.7% as compared to 10.4% in the comparable period. In 2017, production from the Chouech Es Saida field, prior to its shut -in in February, was at a higher royalty rate than the production from Sabria, resulting in a higher average rate in 2017. In addition, proportionally more oil production at Sabria in 2017 relative to 2018 resulted in a slightly higher average royalty rate for the Sabria concession in 2017.

The increase in the per boe metrics for the three and six months ended June 30, 2018 is attributable to higher commodity prices as compared to the three and six months ended June 30, 2017.

 

 

Production Expenses

 

Three months ended June 30

Six months ended June 30

($000)

2018

2017

2018

2017

Production expense - Tunisia

$              549

$           1,145

$           1,277

$           2,865

Production expense - Canada

30

15

41

28

Production expense - Total

$              579

$           1,160

$           1,318

$           2,893

Tunisia production expense ($/boe)

$           17.46

$           38.27

$           19.45

$           30.90

Production expenses for the second quarter of 2018 decreased by 50% to $0.6 million as compared to $1.2 million in the comparable period of 2017. The decrease in 2018 was due to the shut-down of the Chouech Es Saida field in the third quarter of 2017, including the termination of all operating personnel in the field, resulting in lower operating costs and a decrease in Tunisian office costs, partially offset by an increase in Sabria production.

Similar trends are noted on a year to date basis.

The production expense on a per boe basis for the six months ended June 30, 2018 decreased to $19.45 per boe as compared to $30.90 per boe in the comparable period of 2017. The decrease on a per boe basis of 37% was not a direct correlation with the 29% decline in production volumes due to the fixed nature of certain operating expenses.

Canadian production expenses relate to the Sturgeon Lake assets and totaled $41 thousand for the six months ended June 30, 2018 ($28 thousand for the six months ended June 30, 2017). The asset is not producing and is incurring minimal operating costs to maintain the property.

Operating Netback

Serinus uses operating netback as a key performance indicator to assist management in understanding Serinus' profitability relative to current market conditions and as an analytical tool to benchmark changes in operational performance against prior periods. Operating netback consists of petroleum and natural gas revenues less direct costs consisting of royalties and production expenses. Netback is not a standard measure under IFRS and therefore may not be comparable to similar measures reported by other entities. See section titled "Non-IFRS Financial Measures" for advisory over the use of non-IFRS financial measures.

The following table shows the reconciliation of netback to its most closely related IFRS measure revenue:

 

Three months ended June 30, 2018

Three months ended June 30, 2017

($000)

Oil (bbl)

Gas (Mcf)

Total (boe)

Oil (bbl)

Gas (Mcf)

Total (boe)

Production volume

248

585

346

244

509

329

Realized price

$       71.74

$       16.22

$        78.95

$        47.25

$          6.32

$        44.85

Royalties

(7.44)

(1.39)

(7.70)

(5.13)

(0.50)

(4.58)

Production expense

(15.38)

(3.80)

(17.46)

(38.69)

(6.17)

(38.27)

Operating netback

$       48.92

$       11.03

$        53.79

$          3.43

$         (0.35)

$          2.00

 

 

Six months ended June 30, 2018

Six months ended June 30, 2017

($000)

Oil (bbl)

Gas (Mcf)

Total (boe)

Oil (bbl)

Gas (Mcf)

Total (boe)

Production volume

262

605

363

384

771

513

Realized price

$       68.73

$       13.11

$        71.49

$       49.72

$         6.01

$        46.29

Royalties

(7.07)

(1.10)

(6.93)

(5.49)

(0.46)

(4.80)

Production expense

(18.70)

(3.57)

(19.45)

(30.95)

(5.13)

(30.90)

Operating netback

$       42.96

$         8.44

$        45.11

$       13.28

$         0.42

$        10.59

The operating netback of $53.79 per boe in Q2 2018 was $51.79 per boe higher than the netback of $2.00 per boe in the comparative period of 2017. The increase in realized prices, combined with lower production expense per boe contributed to majority of the increase on a per boe basis.

Similar trends are noted on a year to date basis.

General and Administrative Expense

 

Three months ended June 30

Six months ended June 30

($000)

2018

2017

2018

2017

G&A expense

$              711

$               746

$           1,409

$           1,520

G&A expense ($/boe)

$           22.62

$            24.93

$           21.46

$           16.39

General and administrative ("G&A") costs incurred by the Company are expensed, with certain costs directly related to exploration and development assets being capitalized or reported as production costs. The G&A costs reported are on a net basis, representing gross G&A costs incurred less recoveries.

General and administrative ("G&A") costs were comparable for the second quarters of 2018 and 2017 at $0.7 million. G&A per boe decreased reflecting a 5% increase in production in the second quarter of 2018 as compared to the comparable period of 2017.

For the six months ended June 30, 2018, G&A decreased from $1.5 million in 2017 to $1.4 million in 2018. The decrease is primarily attributable to a lower personnel count in 2018. Due to the 29% decrease in production from 2017 to 2018, G&A per boe increased to $21.46 per bbl from $16.39 per bbl in 2017.

Well Incident Recovery

On December 18, 2017, the Company suffered a well incident whereby during routine operations, to prepare the Moftinu 1001 well for future production, an unexpected gas release occurred and subsequently ignited. The well was subsequently brought back under control on January 6, 2018. Immediately following the capping operation, the Company performed a flow-kill operation and following a period of evaluation determined that the casing bowl assembly had been exposed to sufficient heat that its integrity was questionable. As such the Company has plugged and abandoned the Moftinu-1001 well. The costs associated with the above emergency operations have been provided in the year end 2017 financial statements in an amount of $4.0 million. During the first quarter of 2018, the Company incurred a further $0.1 million related to abandoning the Moftinu-1001 well and the remediation of the well site and access roads damaged as part of the emergency operations.

The Company submitted its first interim insurance claim and has received proceeds of $2.6 million, which are reported as a recovery in the statement of operations, during the six months ended June 30, 2018. Subsequent to June 30, 2018, the Company submitted its second interim claim for $1.0 million relating to the remaining emergency costs. The Company has also completed the drilling of the replacement well, Moftinu-1007, located approximately 300 metres from the Moftinu-1001 well site. The re-drill will form the Company's final insurance claim. The European Bank for Reconstruction and Development ("EBRD") is the loss payee under the relevant insurance policy.

Transaction Costs

Transaction costs of $1.3 million in the six months ended June 30, 2018 relate to the continuance of the Company from Alberta, Canada to Jersey, Channel Islands and the listing on AIM which occurred on May 18, 2018. As the transaction was initiated in Q3 2017, there were no transaction costs in the first six months of 2017.

Stock-Based Compensation

 

Three months ended June 30

Six months ended June 30

($000)

2018

2017

2018

2017

Stock-based compensation

$              117

$               170

$              246

$               216

Stock-based compensation ($/boe)

$             3.72

$              5.68

$             3.75

$              2.33

Stock-based compensation was $117 thousand and $246 thousand for the three and six months ended June 30, 2018 compared to $170 thousand and $216 thousand for the comparable periods of 2017, a decrease of 31% and an increase of 14%. The increase in the expense recognized in 2018 as compared to 2017 reflects the issuance of 6,680,000 options in May 2017.

Depletion, Depreciation and Impairment

 

Three months ended June 30

Six months ended June 30

($000)

2018

2017

2018

2017

Depletion and depreciation - Tunisia

$              378

$               381

$              792

$           1,155

Depletion and depreciation - Romania

2

-

3

 

Depletion and depreciation - Canada

53

36

93

75

 

$              433

$               417

$              888

$           1,230

Tunisia depletion and depreciation ($/boe)

$           12.02

$            12.73

$           12.06

$           12.44

Depletion and depreciation expense is computed on a concession by concession basis considering the net book value of the concession, future development costs associated with the reserves as well as the proved and probable reserves of the concession.

For the second quarters of 2018 and 2017, Tunisia depletion and depreciation expense was comparable at $0.4 million, a lower depletion rate per boe in 2017 was offset by 5% higher production between the two periods.

On a year to date basis depletion decreased by 31% to $0.8 million from $1.2 million, due to lower production of 29% in 2018 as compared to 2017 and a slightly lower depletion rate per boe. On a per boe basis, the depletion rate was $12.06 per boe for the six months ended June 30, 2018, compared to $12.44 per boe in the comparative period of 2017.

Interest and Accretion Expense

 

Three months ended June 30

Six months ended June 30

($000)

2018

2017

2018

2017

Interest expense

$              811

$               675

$           1,587

$           1,392

Accretion expense on ARO

248

171

508

342

 

$           1,059

$               846

$           2,095

$           1,734

Interest expense for the second quarter of 2018 increased by 20% compared to $0.7 million in the comparable period in 2017 due to higher debt balances and higher interest rates on the loans in 2018. The average debt balance included in the interest expense calculation for the second quarter of 2018 was $30.5 million compared to $29.2 million in 2017, therefore interest expense was slightly higher in the second quarter of 2018.

Interest expense for the six months ended June 30, 2018 was $1.6 million compared to $1.4 million in 2017, an increase of $0.2 million for similar reasons as noted above.

Accretion represents the increase in the asset retirement obligation ("ARO") from the previous year end to reflect the passage of time. Accretion expense in 2018 was higher than 2017 as the ARO was increased at December 31, 2017 due to increased future inflation rates in Tunisia as well as an increased provision for the Romania gas facility and Moftinu-1007 well.

Foreign Exchange

Fluctuations in foreign currency exchange rates are an economic factor that affects the Company's cash flow required for operations and for investments. The financial statements are presented in US dollars, which is the reporting currency of the Company.

The foreign currency gain was $0.1 million for the six months ended June 30, 2018 compared to $24 thousand for the six months ended June 30, 2017, due to fluctuations in various currencies against the U.S. dollar.

The Company is exposed to risks arising from fluctuations in currency exchange rates between the Canadian dollar, Polish zloty, Romanian leu, Tunisian dinar, the Euro and the United States dollar. At June 30, 2018, the Company's primary currency exposure related to Canadian dollar ("CAD"), Romanian leu ("LEU"), and Tunisian dinar ("TND") balances. The following table summarizes the Company's foreign currency exchange risk for each of the currencies indicated:

As at June 30, 2018

($000)

CAD

LEU

TND

Cash and cash equivalents

$                   18

$                 700

$                 695

Accounts receivable

14

11,820

3,628

Income tax receivable

-

3

3,932

Restricted cash

1,387

-

-

Prepaid expense

10

823

875

Accounts payable and accrued liabilities

(122)

(3,657)

(3,074)

Net foreign exchange exposure

$              1,307

$              9,689

$              6,056

Translation to USD

0.7601

0.2498

0.3788

USD equivalent at period end exchange rate

$                 993

$              2,420

$              2,294

Based on the net foreign exchange exposure at the end of the period, if these currencies had strengthened or weakened by 10% compared to the U.S. dollar and all other variables were held constant, the after tax net earnings would have decreased or increased by approximately the following amounts:

Impact on net earnings (loss)

($000)

 

 

June 30, 2018

December 31, 2017

Canadian dollar (CAD)

 

 

$                 99

$               437

Romanian leu (LEU)

 

 

242

(72)

Tunisian dinar (TND)

 

 

229

(43)

 

 

 

$               570

$               322

Capital Expenditures

 

For the three months ended June 30, 2018

($000)

Tunisia

Romania

Corporate

Total

Property, plant and equipment

$              (28)

$          5,254

$                   -

$           5,226

Exploration and evaluation

-

-

-

-

Total exploration and development

$              (28)

$          5,254

$                   -

$           5,226

 

 

 

 

 

 

For the three months ended June 30, 2017

($000)

Tunisia

Romania

Corporate

Total

Property, plant and equipment

$                91

$                   -

$                   -

$                 91

Exploration and evaluation

-

1,362

-

1,362

Total exploration and development

$                91

$          1,362

$                   -

$            1,453

 

 

For the six months ended June 30, 2018

($000)

Tunisia

Romania

Corporate

Total

Property, plant and equipment

$             (16)

$          7,306

$                84

$           7,374

Exploration and evaluation

-

-

-

-

Total exploration and development

$             (16)

$          8,024

$                84

$           7,374

 

 

 

 

 

 

For the six months ended June 30, 2017

($000)

Tunisia

Romania

Corporate

Total

Property, plant and equipment

$             404

$                   -

$                   -

$               404

Exploration and evaluation

-

1,907

-

1,907

Total exploration and development

$             404

$          1,907

$                   -

$            2,311

In Romania, the Company incurred capital expenditures of $7.3 million for the six months ended June 30, 2018. The expenditures mainly consisted of the construction of the Moftinu gas facilities in the period of $3.1 million, the drilling of the Moftinu 1007 well of $3.2 million and costs associated with the Bucharest office of $0.6 million.

Liquidity, Debt and Capital Resources

 

Three months ended June 30

Six months ended June 30

($000)

2018

2017

2018

2017

Operating

$          (2,906)

$             (832)

$         (3,851)

$          (1,387)

Financing

12,665

14

12,475

16,127

Investing

(7,264)

(2,281)

(10,305)

(2,894)

Effect of exchange rate changes on cash

230

(24)

624

(124)

Change in cash

$            2,725

$          (3,123)

$         (1,057)

$          11,722

For the three months ended June 30, 2018, the net change in cash was an inflow of $2.7 million, as compared to an outflow of $3.1 million in the three months ended June 30, 2017. For the six months ended June 30, 2018, the net change in cash was an outflow of $1.1 million, as compared to an inflow of $11.7 million in the comparable period of 2017.

Cashflow from operating activities for the six months ended June 30, 2018 was an outflow of $3.8 million, as compared to an outflow of $1.4 million in the comparative period. Funds from operations improved year over year at $1.9 million in 2018 as compared to an outflow of $1.3 million in the same period in 2017. Cash flow from operating activities decreased year over year due to the settlement of well incident costs, net of insurance proceeds received, and the settlement of transaction costs associated with the continuance to Jersey and listing on AIM.

Cash flow from financing activities for the six months ended June 30, 2018 were $12.5 million which consisted of net proceeds from the equity raise concurrent with the listing on AIM in May. No principal repayments on long-term debt were paid in 2018 in accordance with the amended terms under the restructured Senior Loan and Convertible Loan agreements. Cash flows from financing activities in the prior period of $16.1 million were primarily driven by the equity offering in February 2017 of $18.0 million, which was partially offset by a scheduled debt repayment of $1.7 million and interest payments of $0.2 million.

Cash outflows from investing activities during the six months ended June 30, 2018 of $10.3 million were driven by capital expenditures of $7.3 million in Romania associated with the Moftinu gas plant and drilling of the Moftinu-1007 well and the net payment of payables of $2.9 million. In the comparable period of 2017, capital expenditures totaled $2.3 million and net payments of payables amounted to $0.7 million.

Cash flow generation in Tunisia remains challenging given the current production level, though with stability of production and cost cutting measures, Tunisia was a positive cash flow generating business unit for the quarter and year to date.

At September 30, 2018 the Company will once again to be subject to covenants with the EBRD. Future compliance with the covenants will be dependent on the performance of the gas facility and wells in Romania, the ability to enhance production in Tunisia, by re-opening the Chouech Es Saida field and/or undertaking planned capital work in the Sabria field in a timely manner, and commodity prices. The performance of Romanian wells is dependent on the commissioning process at the plant and the downtime required once the units are delivered.

Internally prepared forecast models indicate probable non-compliance with covenants in future quarters given the impact of delays in operating cash flows from Romania and Tunisia.

At June 30, 2018, given the probable breach of covenants, the debt may become payable on demand which causes a material uncertainty that may cast significant doubt with respect to the ability of the Company to continue as a going concern. The Company's ability to continue as a going concern is dependent on its ability to generate future cash flows from operations to meet its upcoming covenant requirements.

To ensure security and the preservation of capital, the Company's investment policy for cash that is surplus to immediate requirements is to invest such funds in instruments issued by major banks that are rated "triple A", or its equivalent by independent rating agencies.

Working capital

Serinus uses working capital as a key performance indicator to measure the Company's current assets less current liabilities to assist management in understanding Serinus' liquidity relative to current market conditions and as an analytical tool to benchmark changes against prior periods. Working capital is not a standard measure under IFRS and therefore may not be comparable to similar measures reported by other entities. See section titled "Non-IFRS Financial Measures" for advisory over the use of non-IFRS financial measures. The following table shows the reconciliation of working capital to its most closely related IFRS measure current assets and liabilities:

($000)

 

 

June 30, 2018

December 31, 2017

Current assets

 

 

$         15,384

$         15,393

Current liabilities

 

 

(17,210)

(21,960)

Working capital (deficit)

 

 

$          (1,826)

$          (6,567)

At June 30, 2018, the working capital deficit was $1.8 million, as compared to $6.6 million at December 31, 2017. At June 30, 2018, current liabilities of $17.2 million decreased by $4.8 million compared to $22.0 million at December 31, 2017. The improvement in the working capital is due to a decrease in accounts payable of $6.0 million and a decrease in tax payable of $1.1 million, partially offset by the reclass of $2.8 million of debt to current as is due to be repaid in March 2019.

The current liabilities of $17.2 million at June 30, 2018 includes $2.8 million of debt, accounts payable of $11.4 million and asset retirement obligations of $2.8 million. Included in accounts payable was $8.3 million relating to Brunei at June 30, 2018 and December 31, 2017. Of this amount, $2.3 million relates to a dispute with a drilling company dating back to 2013 on Block L. The remaining $6.0 million relates to work commitments on the Brunei Block M production sharing agreement which expired August 2012. Current liabilities also includes $2.8 million relating to asset retirement obligations in Brunei and Canada. The obligations in Canada are offset by cash held on deposit as restricted cash of $1.1 million in current assets.

Current assets remained consistent from December 31, 2017.

EBRD-Tunisia Loan Facility

The Company has two loans with the EBRD, a Senior Loan and a Convertible Loan. Both loans were amended pursuant to a debt renegotiation in October 2017.

As at June 30, 2018, the principal outstanding under the Senior Loan was $5.4 million (December 31, 2017 - $5.4 million). No principal repayment is due until 2019, with the remaining principal to be repaid in two equal amounts of $2.7 million each on March 31, 2019 and December 31, 2019.

The Convertible Loan in the amount of $20 million has a maturity of June 2023, with accrued interest accumulation until June 2020. In June 2020, the total outstanding principal plus accumulated accrued interest will be determined and this amount will constitute the new balance to be equally amortized over the four annual payments to be made each month of June for the years 2020 to 2023. At June 30, 2018, the total amount outstanding was $27.6 million.

Under the terms of the loan agreements EBRD has the right on change of control of the Company to demand repayment of the debt. Given the AIM listing and equity raise, EBRD waived its right to require prepayment provided that, as a result of the equity raise, Kulczyk Investments S.A. shareholding did not drop below 30% and there was no single investor who will held more than 24.99% of the Company's share capital.

The Senior Loan agreement contains a prepayment clause whereby EBRD has the option to request prepayment in the event that the annual reserves coverage ratio for Tunisian reserves is less than 1.5, in an amount to bring the ratio back on side. With respect to December 31, 2017 reserves, EBRD has waived its right to require prepayment.

Covenants

Covenants

Senior loan

Convertible loan

Corporate level-DSCR

1.3x

N/A

Corporate level-Debt-EBITDA

Max 10.0x Sept & Dec 2018;

Max 2.5x 2019+

Max 10.0x Sept & Dec 2018;

Max 2.5x 2019+

Both loan agreements as part of the EBRD-Tunisia Loan Facility contain a number of affirmative covenants, including maintaining the specified security, environmental and social compliance, and maintenance of specified financial ratios. The covenants use non-GAAP financial measures which are not standard measures under IFRS and may not be comparable to similar measures reported by other entities.

The restructured agreements provide relief from financial covenants until September 2018. The covenants, which are to be calculated at the consolidated level and are as follows:

·      The financial debt to EBITDA ratio must be a maximum of 10.0 times at September 2018 and December 2018 and then to 2.5 times thereafter. The debt to EBITDA ratio is applicable to both the Senior Loan and the Convertible Loan.

·      The debt service coverage ratio, which is effective as at December 31, 2018, is set at a minimum of 1.3 times and is only applicable to the Senior Loan.

The definitions of the covenants remained the same on the restructured loan agreement and are as follows:

·      Financial debt is defined as the principal amount of the loan and other borrowings and obligations identified in the Loan Agreements.

·      EBITDA is calculated based on the terms and definitions as set out in the Loan Agreement, which adjusts earnings for interest expense, income tax, and non-cash transactions (including depletion, depreciation, exploration and evaluation expenses, impairment losses or provisions, unrealized gains and losses from foreign exchange, and share-based compensation) and is calculated based on a trailing twelve-month basis.

·      The debt service coverage ratio is calculated as the ratio of (i) cash flows arising from operating activities for the trailing twelve months as per the statement of cash flows, minus the sum of those cashflows used for acquiring long-term assets or other capital expenditures, excluding those capital expenditures funded by equity, referred by Serinus as "adjusted cashflows, to (ii) the sum of scheduled principal repayments and interest payments on the financial debt  on a trailing twelve-month basis.

At June 30, 2018, the Company was not subject to any financial covenants.

Share Data

The Company is authorized to issue an unlimited number of common shares, of which 217,318,805 common shares and 67,000 options, with a USD exercise price, and 8,915,000 options, with a Canadian Dollar ("CAD") exercise price, to purchase common shares, were outstanding as at June 30, 2018. The Company is in the process of converting its outstanding options from a TSX option plan to an AIM plan and changing the denomination of outstanding options to be in pounds sterling ("GBP").

During Q2 2018, 66,666,667 common shares were issued at £0.15 per common share for equity proceeds before costs of £10 million. Proceeds, net of costs, as reported, are $12.7 million.

At the date of issuing this report, the following are the options outstanding and changes to directors, executives and officers shares owned since June 30, 2018, up to the date of this report:

Name of Director/Executive Officer/Key Person

Options held at August 9, 2018

Shares held at Jun 30, 2018

Change in ownership

Shares held at August 9, 2018

Evgenij Iorich (a)

100,000

3,415

-

3,415

Jeffrey Auld

4,500,000

22,197

-

22,197

Lukasz Redziniak

-

-

-

-

Dominik Libicki

-

-

-

-

Eleanor Barker

100,000

100,000

-

100,000

Tracy Heck

2,750,000

-

-

-

Calvin Brackman

750,000

-

-

-

Jim Causgrove

100,000

-

-

-

Dawid Jakubowicz

-

-

-

-

 

8,300,000

125,612

-

125,612

(a) Mr. Iorich holds a position with Pala Investments, which is related to Pala Assets Holdings Limited ("Pala"). Pala owned 11,266,084 Shares as at June 30, 2018. By virtue of his position with Pala Investments, Mr. Iorich is deemed to have direction over such Shares in addition to those Shares that are shown above.

As of the date of issuing this report, management is aware of the following shareholders holding more than 5% of the common shares of the Company, as reported by the shareholders to the Company: Kulczyk Investments S.A. holds 38.77%, Marlborough Fund Managers holds 7.67%, James Caird Investments Ltd holds 6.19%, City Financial Investment Company Limited holds 6.03%, Pala Assets Holdings Limited holds 5.18% and Quercus Towarzystwo Funduszy Investycyjych SA holds 5.25% of the common shares issued.

 

 

Non-IFRS Measures

The financial information presented in this MD&A has been prepared in accordance with IFRS except for the terms "netback" and "working capital" which are not recognized measures under IFRS and do not have standardized meanings prescribed by IFRS. These non-IFRS measures are presented for information purposes only and should not be considered an alternative to, or more meaningful than information presented in accordance with IFRS. Management believes netback and working capital may be useful supplemental measures as they are used by the Company to measure operating performance and to evaluate the timing and amount of capital required to fund future operations. The Company's method of calculating these measures may differ from those of other companies and, accordingly, they may not be comparable to measures used by other companies.

Serinus calculates "netback" and "working capital" as presented earlier in this document.

Forward-Looking Statements

This MD&A contains forward-looking statements. These statements relate to future events or future performance of the Company. When used in this MD&A, the words "may", "would", "could", "will", "intend", "plan", "anticipate", "believe", "estimate", "predict", "seek", "propose", "expect", "potential", "continue", and similar expressions, are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties, and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Such statements reflect the Company's current views with respect to certain events, and are subject to certain risks, uncertainties and assumptions. Many factors could cause the Company's actual results, performance, or achievements to vary from those described in this MD&A. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those described in this MD&A as intended, planned, anticipated, believed, estimated, or expected.

Specific forward-looking statements in this MD&A, among others, include statements pertaining to the following:

·      factors upon which the Company will decide whether or not to undertake a specific course of action;

·      world-wide supply and demand for petroleum products;

·      expectations regarding the Company's ability to raise capital;

·      treatment under governmental regulatory regimes; and

·      commodity prices.

With respect to forward-looking statements in this MD&A, the Company has made assumptions, regarding, among other things: 

·      the impact of increasing competition;

·      the ability of partners to satisfy their obligations;

·      the Company's ability to obtain additional financing on satisfactory terms; and

·      the Company's ability to attract and retain qualified personnel.

The Company's actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this MD&A:

·      general economic conditions;

·      volatility in global market prices for oil and natural gas;

·      competition;

·      liabilities and risks, including environmental liability and risks, inherent in oil and gas operations;

·      the availability of capital;

·      geopolitical volatility in the countries of operations; and

·      alternatives to and changing demand for petroleum products.

Furthermore, statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitable in the future.

The forward-looking statements contained in this MD&A are expressly qualified in their entirety by this cautionary statement. These statements speak only as of the date of this MD&A.

Abbreviations

The following abbreviations may be used throughout this MD&A document:

bbl

Barrel(s)

bbl/d

Barrels per day

boe

Barrels of Oil Equivalent

boe/d

Barrels of Oil Equivalent per day

mcf

Thousand Cubic Feet

mcf/d

Thousand Cubic Feet per day

mmcf

Million Cubic Feet

mmcf/d

Million Cubic Feet per day

mcfe

Thousand Cubic Feet Equivalent

mcfe/d

Thousand Cubic Feet Equivalent per day

mmcfe

Million Cubic Feet Equivalent

mmcfe/d

Million Cubic Feet Equivalent per day

mboe

Thousand boe

Bcf

Billion Cubic Feet

mmboe

Million boe

mcm

Thousand Cubic Metres

CAD

Canadian Dollar

USD

U.S. Dollar

$M

Thousands of Dollars

UAH

Ukrainian Hryvnia

$MM

Millions of Dollars

TND

Tunisian Dinar

Measurement Conversions

Certain crude oil and natural gas liquids volumes have been converted to mcfe or mmcfe on the basis of one bbl to six mcf. Also, certain natural gas volumes have been converted to boe or mboe on the same basis. Any figure presented in mcfe, mmcfe, boe or mboe may be misleading, particularly if used in isolation. A conversion ratio of one bbl of crude oil or natural gas liquids to six mcf of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not necessarily represent value equivalency at the wellhead.

Investor Information

Additional information regarding Serinus and its business and operations is available at www.sedar.com. Information is also accessible on the Company's website at www.serinusenergy.com.

We welcome questions from interested parties. Contact should be directed to the Calgary office of Serinus via address: Suite 1500, 700 - 4th Avenue S.W., Calgary, Alberta T2P 3J4 Canada, phone: +1 403 264-8877 or e-mail: [email protected].


This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact [email protected] or visit www.rns.com.
 
END
 
 
IR LFFSLTDIAIIT

Related Charts

Serinus Energy Ord Npv (SENX)

0.00p (0.00%)
delayed 16:57PM