Touchstone Exploration Regulatory News (TXP)

TOUCHSTONE ANNOUNCES SECOND QUARTER AND SIX MONTHS TO JUNE 30, 2018 RESULTS AND INCREASED 2018 CAPITAL PROGRAM

Calgary, Alberta - August 14, 2018 - Touchstone Exploration Inc. ("Touchstone" or the "Company") (TSX / LSE: TXP) announces its financial and operating results for the three and six months ended June 30, 2018. Selected financial and operational information is outlined below and should be read in conjunction with Touchstone's June 30, 2018 unaudited interim consolidated financial statements and the related Management's discussion and analysis, both of which will be available under the Company's profile on SEDAR (www.sedar.com) and the Company's website (www.touchstoneexploration.com). Tabular amounts herein are in thousands of Canadian dollars, and the amounts in text are rounded to thousands of Canadian dollars unless otherwise stated.

Highlights

· Achieved quarterly average crude oil production of 1,717 barrels per day ("bbls/d"), representing increases of 11% and 29% from the first quarter of 2018 and the second quarter of 2017, respectively.

· Continued our 2018 development program with total drilling and development capital expenditures of $4,520,000, drilling three wells and performing four well recompletions.

· Realized $12,508,000 in petroleum sales, a 68% increase from the prior year second quarter.

· Generated an operating netback of $38.19 per barrel, a 92% increase relative to the $19.88 per barrel generated in the prior year comparative quarter.

· Delivered funds flow from operations of $3,258,000 ($0.03 per basic share) compared to $438,000 ($0.01 per basic share) in the second quarter of 2017.

· Recognized a reduced net loss of $692,000 ($0.01 per basic share) compared to a net loss of $1,848,000 ($0.02 per basic share) realized in the equivalent quarter of 2017.

· Extended our $15 million term loan maturity date and initial principal repayments by one year.

· Maintained balance sheet strength with second quarter cash of $10,556,000 and net debt of $11,266,000, representing 1.0 times net debt to first half 2018 annualized funds flow from operations.

· Expanded our 2018 drilling program from ten to fourteen wells.

Financial and Operating Results Summary

Note:

(1) See "Advisories: Non-GAAP Measures".

Operating Results

Our operating results in the second quarter were consistent with our expectations, as we continued with our ten well drilling campaign by successfully drilling three development wells and spudding the sixth well of the program on June 15, 2018. Capital expenditures totaled $4,954,000, of which $4,520,000 related to drilling and development activities. We recompleted four wells in the quarter, with an aggregate nine wells recompleted in the first half of 2018.

Second quarter 2018 crude oil production averaged 1,717 bbls/d, a 29% increase relative to the 1,334 bbls/d produced in the second quarter of 2017 and a 11% increase relative to the 1,543 bbls/d produced in the first quarter of 2018. The five wells drilled to date in 2018 combined to add 183 bbls/d of incremental production in the second quarter. Our four well 2017 program continued to perform above internal expectations, contributing approximately 351 bbls/day of production in the quarter.

Financial Results

Our second quarter operating netback improved 92% to $38.19 per barrel, as compared to $19.88 per barrel in the second quarter of 2017. Realized second quarter 2018 crude oil pricing was $80.04 (US$61.79) per barrel, 31% greater than the $61.26 (US$45.51) per barrel received in the equivalent quarter of 2017. In comparison to the second quarter of 2017, royalty expenses per barrel increased 41% based on the rising scale effect of increased commodity prices to royalty rates. Second quarter 2018 operating costs per barrel decreased 24% from the corresponding quarter of 2017, predominantly from increased production over a fixed operating cost base and increased operating efficiencies.

We generated funds flow from operations of $3,258,000 ($0.03 per basic share) in the second quarter of 2018 versus $438,000 ($0.01 per basic share) in the second quarter of 2017. The increase in funds flow was largely attributed to stronger oil price realizations and operating netbacks. Excluding realized financial derivative gains, our second quarter 2018 funds flow was the highest since the third quarter of 2014. As a result, the Company decreased its net loss by 63% from the prior year second quarter, recording a net loss of $692,000 ($0.01 per basic share) during the three months ended June 30, 2018.

We maintained strong financial liquidity, exiting the quarter with a cash balance of $10,556,000, a working capital surplus of $3,734,000 and a $15,000,000 principal term loan balance. Our June 30, 2018 net debt of $11,266,000 represented net debt to trailing twelve-month funds flow from operations of 1.4 times and net debt to year to date second quarter 2018 annualized funds flow from operations of 1.0 times. We expect our liquidity position to be stable going forward as the new wells drilled in the quarter are placed onto production and optimized.

On June 13, 2018, we extended the maturity of our $15 million term loan by one year to November 23, 2022, with no mandatory principal payments until January 1, 2020. In addition, the amended agreement removed the minimum $5 million quarterly cash reserves financial covenant. The credit facility is covenant based and does not require annual or semi-annual reviews. We were well within the financial covenants as at June 30, 2018. The one-year deferral of principal payments will allow us to continue our near-term development strategy into 2019.

On June 21, 2018, we entered an agreement to dispose of our 50% operating working interest in our non-core Icacos block to our third-party partner for minimum consideration of US$500,000. Consideration will be paid based on the Company's working interest net revenue it would have received had it retained such interest through December 2021. The property averaged 10 bbls/d of net crude oil production in the second quarter of 2018. The agreement was effective April 1, 2018 and remains subject to local regulatory approvals.

Increase in 2018 Drilling Program

We are increasing our 2018 capital program by US$4.8 million, which will result in four additional wells drilled prior to year-end. The Company expects to drill the four additional wells on our WD-4 and WD-8 properties. The additional fourth quarter capital is expected to add incremental production volumes in early 2019 and further improve the Company's growth plans.

For further information, please contact:

Touchstone Exploration Inc.

Mr. Paul Baay, President and Chief Executive Officer Tel: +1 (403) 750-4487

Mr. Scott Budau, Chief Financial Officer

www.touchstoneexploration.com

Shore Capital (Nominated Advisor and Joint Broker)

Nominated Advisor: Edward Mansfield / Mark Percy / Daniel Bush Tel: +44 (0) 20 7408 4090

Corporate Broking: Jerry Keen

GMP FirstEnergy (Joint Broker)

Jonathan Wright / Hugh Sanderson Tel: +44 (0) 207448 0200

Camarco (Financial PR)

Nick Hennis / Jane Glover / Billy Clegg Tel: +44 (0) 203 757 4980

About Touchstone

Touchstone Exploration Inc. is a Calgary based company engaged in the business of acquiring interests in petroleum and natural gas rights, and the exploration, development, production and sale of petroleum and natural gas. Touchstone is currently active in onshore properties located in the Republic of Trinidad and Tobago. The Company's common shares are traded on the Toronto Stock Exchange and the AIM market of the London Stock Exchange under the symbol "TXP".

Advisories

Non-GAAP Measures

This announcement contains terms commonly used in the oil and natural gas industry, including funds flow from operations per share, operating netback and net debt. These terms do not have a standardized meaning under International Financial Reporting Standards and may not be comparable to similar measures presented by other companies. Shareholders and investors are cautioned that these measures should not be construed as alternatives to cash provided by operating activities, net income, total liabilities, or other measures of financial performance as determined in accordance with Generally Accepted Accounting Principles. Management uses these Non-GAAP measures for its own performance measurement and to provide stakeholders with measures to compare the Company's operations over time.

The Company calculates funds flow from operations per share by dividing funds flow from operations by the weighted average number of common shares outstanding during the applicable period.

The Company uses operating netback as a key performance indicator of field results. Operating netback is presented on a per barrel basis and is calculated by deducting royalties and operating expenses from petroleum sales. If applicable, the Company also discloses operating netback both prior to realized gains or losses on derivatives and after the impacts of derivatives are included. Realized gains or losses represent the portion of risk management contracts that have settled in cash during the period, and disclosing this impact provides Management and investors with transparent measures that reflect how the Company's risk management program can impact netback metrics. The Company considers operating netback to be a key measure as it demonstrates Touchstone's profitability relative to current commodity prices.

Net debt is calculated by summing the Company's working capital and the principal (undiscounted) amount of long-term debt. Working capital is calculated as current assets less current liabilities as they appear on the statements of financial position. The Company uses this information to assess its true debt and liquidity position and to manage capital and liquidity risk.

Forward-Looking Statements

Certain information provided in this announcement may constitute forward-looking statements within the meaning of applicable securities laws. Forward-looking information in this announcement may include, but is not limited to, statements relating to the Company's future liquidity position, the potential undertaking, timing, locations and costs of future well drilling and recompletion activities and the sufficiency of resources to fund future well drilling and recompletion operations. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. Certain of these risks are set out in more detail in the Company's December 31, 2017 Annual Information Form dated March 26, 2018 which has been filed on SEDAR and can be accessed at www.sedar.com. The forward-looking statements contained in this announcement are made as of the date hereof, and except as may be required by applicable securities laws, the Company assumes no obligation to update publicly or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.

Interim Consolidated Statements of Financial Position

(Unaudited, thousands of Canadian dollars)

Commitments (note 14)

See accompanying notes to these unaudited interim consolidated financial statements.

Interim Consolidated Statements of Comprehensive Income (Loss)

For the three and six months ended 30 June, 2018 and 2017

(Unaudited, thousands of Canadian dollars, except per share amounts)

See accompanying notes to these unaudited interim consolidated financial statements.

Interim Consolidated Statements of Changes in Shareholders' Equity

(Unaudited, thousands of Canadian dollars)

See accompanying notes to these unaudited interim consolidated financial statements.

Interim Consolidated Statements of Cash Flows

For the three and six months ended June 30, 2018 and 2017

(Unaudited, thousands of Canadian dollars)

See accompanying notes to these unaudited interim consolidated financial statements.

Notes to the Interim Consolidated Financial Statements (unaudited)

As at June 30, 2018 and for the three and six months ended June 30, 2018 and 2017

1. Reporting Entity

Touchstone Exploration Inc. (the "Company") is incorporated under the laws of Alberta, Canada with its head office located in Calgary, Alberta. The Company is an oil and gas exploration and production company active in the Republic of Trinidad and Tobago ("Trinidad"). The Company's common shares are listed on the Toronto Stock Exchange ("TSX") and on the AIM market of the London Stock Exchange ("AIM") under the symbol "TXP".

The principal address of the Company is 4100, 350 7th Avenue SW, Calgary, Alberta, T2P 3N9.

2. Basis of Preparation and Statement of Compliance

These unaudited interim consolidated financial statements (the "financial statements") have been prepared in accordance with International Accounting Standard ("IAS") 34 Interim Financial Reporting using accounting policies consistent with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"). These financial statements are condensed as they do not include all the information required by IFRS for annual financial statements and should be read in conjunction with the Company's audited consolidated financial statements for the year ended December 31, 2017. Unless otherwise stated, amounts presented in these financial statements are rounded to thousands of Canadian dollars, and tabular amounts are stated in thousands of Canadian dollars. Certain reclassification adjustments have been made to these financial statements to conform to the current presentation.

These financial statements have been prepared on a historical cost basis, except as detailed in the accounting policies disclosed in Note 3 "Summary of Significant Accounting Policies" of the Company's audited consolidated financial statements for the year ended December 31, 2017. All accounting policies and methods of computation followed in the preparation of these financial statements are consistent with those of the previous financial year, except as noted in Note 3 "Changes to Accounting Policies". There have been no significant changes to the use of estimates or judgments since December 31, 2017.

These financial statements were authorized for issue by the Board of Directors on August 13, 2018.

3. Changes to Accounting Policies

(a) Adoption of IFRS 9 Financial Instruments

Effective January 1, 2018, the Company adopted IFRS 9 Financial Instruments ("IFRS 9"), which replaced IAS 39 Financial Instruments: Recognition and Measurement. The adoption of IFRS 9 did not result in any adjustments to the measurement of financial instruments, and no adjustment to retained earnings was required.

As a result of the adoption of IFRS 9, the Company has revised the description of its financial instrument accounting policies to reflect the new classification approach as follows:

Financial instruments

Financial assets and financial liabilities are measured at fair value on initial recognition. Measurement in subsequent periods depends on the financial instrument's classification, as described below.

· Fair value through profit or loss: Financial instruments designated at fair value through profit or loss are initially recognized and subsequently measured at fair value with changes in those fair values charged immediately to net earnings. Financial instruments under this classification include derivative assets and liabilities.

· Amortized costs: Financial instruments designated as amortized costs are initially recognized at fair value, net of directly attributable transaction costs, and are subsequently measured at amortized cost using the effective interest method. Financial instruments under this classification include cash, restricted cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, income taxes payable and term loan and associated liabilities.

· Fair value through other comprehensive income: Financial instruments designated as fair value through other comprehensive income are initially recognized at fair value, net of directly attributable transaction costs, and are subsequently measured at fair value with changes in fair value recognized in other comprehensive income, net of tax.

Derivatives may be used by the Company to manage exposure to market risk relating to commodity prices, foreign exchange rates and interest rates. The Company does not designate its financial derivatives contracts as hedges. As a result, all financial derivative contracts are classified as fair value through profit or loss and are recorded and carried on the consolidated statement of financial position at fair value with actual amounts received or paid on the settlement of the financial derivative instrument recorded in net earnings. Forward crude oil derivative contracts are recorded at their estimated fair value based on the difference between the contracted price and the period end forward price, using quoted market prices.

Impairment of financial assets

The Company recognizes loss allowances for expected credit losses on its financial assets measured at amortized cost. Expected credit losses exist if one or more loss events occur after initial recognition of the financial asset which has an impact on the estimated future cash flows of the financial asset and that impact can be reliably measured. The Company uses a combination of historical and forward-looking information to determine the appropriate expected credit loss. The carrying amount of the asset is reduced through the use of an allowance account, and the loss is recognized in general and administrative expenses.

(b) Adoption of IFRS 15 Revenue Recognition

Effective January 1, 2018, the Company adopted IFRS 15 Revenue from Contracts with Customers ("IFRS 15"). IFRS 15 established a comprehensive framework for determining whether, how much, and when revenue from contracts with customers is recognized.

The Company's revenue relates to the sale of crude oil solely to the Petroleum Company of Trinidad and Tobago Limited ("Petrotrin") at various sales batteries at specified prices referenced to benchmark pricing. The Company's sales batteries are tied into Petrotrin sales pipelines. The Company considers its performance obligations to be satisfied and control to be transferred when crude oil is delivered to the Petrotrin pipeline, as all risks and rewards of ownership have been transferred and the Company has the present right to payment.

The Company adopted IFRS 15 using the modified retrospective approach. Under this transitional provision, the cumulative effect of initially applying IFRS 15 is recognized on the date of initial application as an adjustment to retained earnings. The adoption of IFRS 15 did not impact the timing or measurement of revenue, and no adjustment to retained earnings was required.

As a result of the adoption of IFRS 15, the Company has revised the description of its accounting policy for revenue recognition as follows:

Revenue associated with the sale of crude oil is measured based on the consideration specified in contracts with customers. Revenue from contracts with customers is recognized when or as the Company satisfies a performance obligation by transferring a promised good or service to a customer. A good or service is transferred when the customer obtains control of that good or service. The transfer of control of crude oil coincides with title passing to the customer and the customer taking physical possession.

(c) Standards issued but not yet adopted

IFRS 16 Leases

IFRS 16 Leases replaces IAS 17 Leases and requires entities to recognize lease assets and lease obligations on the statement of financial position. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than 12 months) and leases of low-value assets are exempt from the requirements and may continue to be treated as operating leases. Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue, and what assets would be recorded. The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption permitted if the entity is also applying IFRS 15. The standard may be applied retrospectively or using a modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect as an adjustment to opening retained earnings and applies the standard prospectively.

The Company plans to apply IFRS 16 on January 1, 2019 and is currently evaluating the impact of the standard on its financial statements. Although the transition approach on adoption has not yet been determined, it is anticipated that the adoption of IFRS 16 will have a material impact on the Company's consolidated statements of financial position.

4. Exploration Assets

Exploration assets consist of the Company's projects in the exploration and evaluation stage which are pending determination of technical and commercial feasibility. The following table is a continuity schedule of the Company's exploration assets at the end of the respective periods:

During the three and six months ended June 30, 2018, $23,000 and $31,000 of general and administrative expenses were capitalized to exploration assets, respectively (2017 - $11,000 and $31,000).

During the three and six months ended June 30, 2018, the Company incurred $119,000 and $236,000 in lease expenses and letter of credit holding costs relating to its East Brighton property, respectively (2017 - $391,000 and $477,000). These costs were impaired given the property's estimated recoverable value was $nil.

5. Property and Equipment

The following table is a continuity schedule of the Company's property and equipment at the end of the respective periods:

As at June 30, 2018, $82,036,000 in future development costs were included in petroleum asset cost bases for depletion calculation purposes (December 31, 2017 - $85,287,000). During the three and six months ended June 30, 2018, $292,000 and $551,000 in general and administrative expenses were capitalized to property and equipment, respectively (2017 - $207,000 and $403,000). During the three and six months ended June 30, 2018, $5,000 and $10,000 in share-based compensation expenses were capitalized to property and equipment, respectively (2017 - $9,000 and $18,000).

At June 30, 2018, the Company evaluated its petroleum assets for indicators of any potential impairment or related reversal. As a result of this assessment, no indicators were identified, and no impairment or related reversal was recorded except as disclosed below.

(a) Property disposition

On June 21, 2018 the Company entered an agreement to dispose of its 50% operating working interest in the Icacos property to the current third-party partner for minimum consideration of US$500,000. The consideration will be paid based on the Company's working interest net revenue it would have received had it retained such interest through December 2021. Should these cumulative payments not exceed the minimum consideration, the Company will receive the difference prior to the end of February 2021. The Company shall retain all cumulative payments should such payments exceed the US$500,000 minimum consideration through December 31, 2021. The agreement was effective April 1, 2018 and remains subject to local regulatory approvals.

The Company reclassified the $187,000 net carrying value of the related assets from property and equipment to assets held for sale. In addition, $82,000 of associated decommissioning obligations were classified as liabilities held for sale as at June 30, 2018.

(b) Exploration and production licences

The Company's Fyzabad and Palo Seco exploration and production agreements with the Trinidad and Tobago Minister of Energy and Energy Industries ("MEEI") expired on August 19, 2013. The Company is currently negotiating licence renewals and has permission from the MEEI to operate in the interim period. The Company has no indication that the two licences will not be renewed. During the three and six months ended June 30, 2018, production volumes produced under expired MEEI production licences represented 3.6% and 3.6% of total production, respectively (2017 - 4.6% and 5.0%). As at June 30, 2018, the estimated net book value of the properties operating under expired MEEI production licences was approximately $1,891,000, representing 2.6% of the Company's property and equipment balance (December 31, 2017 - $1,866,000 and 3.0%).

(c) Private lease agreements

The Company is operating under a number of private lease agreements which have expired and are currently being renewed. Based on legal opinions received, the Company is continuing to recognize revenue on the producing properties because the Company is the operator, is paying all associated royalties and taxes, and no title to the revenue has been disputed. The Company currently has no indication that any of the producing expired leases will not be renewed. The continuation of production from expired private leases during the renegotiation process is common in Trinidad. During the three and six months ended June 30, 2018, production volumes produced under expired private lease agreements represented 2.4% and 2.5% of total production, respectively (2017 - 3.2% and 3.0%). 

6. Term Loan and Associated Liabilities

On November 23, 2016, the Company completed an arrangement for a $15,000,000, five-year term credit facility from a Canadian investment fund. The term loan bears a fixed interest rate of 8% per annum, compounded and payable quarterly.

Effective June 15, 2018, the Company and the lender entered into a Second Amending Agreement to the Credit Agreement (the "Amendment"). The Amendment extended the term loan maturity date to November 23, 2022 and extended all principal payments by one year. The Company is required to repay $810,000 per quarter commencing on January 1, 2020 through October 1, 2022, and the then outstanding principal balance is repayable on the maturity date. In addition, the Amendment removed the minimum $5,000,000 quarterly cash reserves financial covenant. As consideration for the Amendment, the Company paid the lender a financing fee of $150,000.

In connection with the term loan, the Company has granted the lender a production payment equal to 1% of total petroleum sales from then current Company land holdings in Trinidad. In addition to the Amendment, the Company and the lender extended the production payment agreement to mature on October 31, 2022 regardless of any repayment or prepayment of the term loan. The Company may prepay any principal portion of the term loan after May 23, 2018 and has the option to negotiate a buyout of the future production payment obligations if the term loan balance is prepaid in full. The term loan and the Company's obligations in respect of the production payment are principally secured by fixed and floating security interests over all present and after acquired assets of the Company and its subsidiaries.

The debt instrument is comprised of two components: the term loan and the production payment obligation.

At inception the term loan was measured at fair value, net of all transaction fees, using a discount rate of 12%. The term loan balance less transaction costs is unwound using the effective interest rate method to the principal value at maturity with a corresponding non-cash accretion charge to net earnings. The term loan was revalued based on the Amendment, resulting in a revaluation gain of $283,000 recognized during the three and six months ended June 30, 2018 (2017 - $nil and $nil).

The production payment obligation was initially measured at fair value, based on internally estimated future production and pricing at the inception of the loan and a discount rate of 15%. The obligation is revalued at each reporting period based on updated future production estimates and forward crude oil pricing. As a result of the Amendment and changes in future production and forward crude pricing estimates, revaluation losses of $250,000 and $409,000 were recognized during the three and six months ended June 30, 2018, respectively (2017 - $nil and $nil).

The following is a continuity schedule of the term loan and associated liabilities balance at the end of the respective periods:

The term loan arrangement contains industry standard representations and warranties, positive and negative covenants and events of default. The financial covenants and the Company's estimated position as at June 30, 2018 were as follows:

Notes:

(1) Estimated position subject to final approval by the lender.

(2) Net funded debt is defined as interest-bearing debt less cash balances. Equity is defined as book value of shareholders' equity less accumulated other comprehensive income (loss).

(3) Means the ratio of net funded debt to EBITDA for the trailing twelve-month period. EBITDA is defined as net earnings before interest, income taxes and non-cash items.

7. Decommissioning Obligations and Abandonment Fund

The Company's decommissioning obligations relate to future site restoration and abandonment costs including the costs of production equipment removal and land reclamation based on current environmental regulations. The total decommissioning obligation is estimated by Management based on the Company's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon these wells and facilities, and the estimated timing of the costs to be incurred in future periods.

Pursuant to certain production and exploration licences, the Company is obligated to remit payments into an abandonment fund based on production. The Company remits US$0.25 per barrel of crude oil sold, and the funds will be used for the future abandonment of wells in the related licensed area. As at June 30, 2018, the Company classified $1,192,000 of accrued or paid fund contributions as long-term abandonment fund assets (December 31, 2017 - $1,049,000).

The Company estimated the net present value of the cash flows required to settle its decommissioning obligations to be $12,733,000 at June 30, 2018 based on an inflation adjusted future liability of $41,097,000 (December 31, 2017 - $11,853,000 and $39,193,000). At June 30, 2018 and December 31, 2017, decommissioning obligations were valued using a long-term risk-free rate of 6.1% and a long-term inflation rate of 3.3%. During the three and six months ended June 30, 2018, the Company abandoned two wells resulting in a loss on decommissioning of $11,000 (2017 - $nil).

Payments to settle the obligations occur over the operating lives of the underlying assets, estimated to be from four to 45 years, with the majority of the costs to be incurred subsequent to 2042. The obligations are expected to be funded from the abandonment fund and the Company's internal resources available at the time of settlement. The following table summarizes the Company's decommissioning obligation provision at the end of the respective periods:

8. Shareholders' Capital

(a) Issued and outstanding common shares

The Company has authorized an unlimited number of voting common shares without nominal or par value. The following table is a continuity schedule of the Company's common shares outstanding and shareholders' capital:

(b) Share options and incentive share options

The Company has a share option plan pursuant to which options to purchase common shares of the Company may be granted by the Board of Directors to directors, officers, employees and consultants of the Company. The exercise price of each option may not be less than the closing price of the common shares prior to the date of grant. Compensation expense is recognized as the options vest. Unless otherwise determined by the Board of Directors, vesting typically occurs one third on each of the next three anniversaries of the date of the grant as recipients render continuous service to the Company, and the share options typically expire five years from the date of the grant. The maximum number of common shares issuable on the exercise of outstanding share options and incentive share options at any time is limited to 10% of the issued and outstanding common shares. The following table summarizes the share options outstanding at the end of the respective periods:

During the three and six months ended June 30, 2018, the Company granted 1,688,800 share options to directors, officers and employees (year ended December 31, 2017 - 1,558,800). The weighted average fair value of options granted during the three and six months ended June 30, 2018 was $0.13 per option as estimated on the date of each grant using the Black-Scholes option pricing model (year ended December 31, 2017 - $0.08 per option).

The Company has an incentive share option plan which provides for the grant of incentive share options to purchase common shares of the Company at a $0.05 exercise price. A maximum of one million common shares have been approved for issuance under this plan. Unless otherwise determined by the Board of Directors, vesting typically occurs one third on each of the next three anniversaries of the date of the grant, and the incentive share options typically expire five years from the date of the grant. The following table summarizes the incentive share options outstanding at the end of the respective periods:

During the three and six months ended June 30, 2018, the Company recorded share-based compensation expenses of $40,000 and $74,000, respectively (2017 - $44,000 and $100,000).

9. Other Income

During the six months ended June 30, 2018, the Company sold a licensed copy of 3D seismic data to a third-party broker for proceeds of $484,000 (2017 - $nil).

10. Net Finance Expenses

The following table summarizes net finance expenses recorded during the three and six months ended June 30, 2018 and 2017:

11. Net Loss per Common Share

There was no dilutive impact to the weighted average number of common shares for the three and six months ended June 30, 2018, as all share options and incentive share options were excluded from the weighted average dilutive share calculation because their effect would be anti-dilutive.

12. Risk Management

(a) Credit risk

Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. The Company's crude oil production is sold, as determined by market based prices adjusted for quality differentials, to Petrotrin. Typically, the Company's maximum credit exposure to Petrotrin is revenue for one month's petroleum sales, of which $3,167,000 was included in accounts receivable as at June 30, 2018 (December 31, 2017 - $2,196,000). The Company's carrying values of accounts receivable represented the Company's maximum credit exposure. The aging of accounts receivable as at June 30, 2018 and December 31, 2017 were as follows:

As at June 30, 2018, the Company determined that the average expected credit loss on the Company's accounts receivables was nil. The Company believes that the accounts receivable balances that are past due are ultimately collectible, as the majority are due from Trinidad government agencies.

(b) Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. The Company's approach to managing liquidity is to ensure that it will have sufficient liquidity to meet liabilities when due, under both normal and unusual conditions without incurring unacceptable losses or jeopardizing the Company's business objectives. The Company manages this risk by preparing cash flow forecasts to assess whether additional funds are required. The Company's liquidity is dependent on the Company's expected business growth and changes in its business environment.

To manage its capital structure in a period of low commodity prices, the Company may further reduce its fixed cost structure, adjust capital spending, issue new equity or seek additional sources of debt financing. The Company will continue to manage its expenditures to reflect current financial resources in the interest of sustaining long-term viability. Undiscounted cash outflows relating to financial liabilities as at June 30, 2018 were as follows:

(c) Commodity price risk

The Company is exposed to commodity price movements as part of its operations, particularly in relation to prices received for its oil production. Commodity prices for oil are impacted by the world and continental/regional economy and other events that dictate the levels of supply and demand. Consequently, these changes could also affect the value of the Company's properties, the level of spending for exploration and development and the ability to meet obligations as they come due.

In January 2018, the Company entered into the following crude oil financial derivative contracts to mitigate its future exposure to fluctuations in commodity prices:

The put options were purchased from a financial institution for an upfront cash premium of US$153,000 ($190,000). The options may be settled monthly during the option exercise period.

The Company has recognized the premium for the put options as a derivative financial asset. The derivatives are subsequently recorded at their estimated fair value based on the difference between the contracted price and the period-end forward price using quoted market prices. The Company recognized a financial derivative asset of $13,000 as at June 30, 2018 (December 31, 2017 - $nil) and unrealized derivative losses of $111,000 and $185,000 during the three and six months ended June 30, 2018 related to the put options (2017 - $nil and $nil).

(d) Foreign currency risk

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of the Company's financial assets or liabilities. As the Company primarily operates in Trinidad, fluctuations in the exchange rate between the Canadian dollar and the TT$ can have a significant effect on reported results. Given that the TT$ is loosely pegged to the US$, the underlying risk is based on movements between the Canadian dollar and the US$.

The Company's revenues are subject to foreign exchange exposure as the sales prices of crude oil are determined by reference to US$ denominated benchmark prices. An increase in the value of the Canadian dollar compared with the US$ has a negative impact on the Company's reported results. Likewise, as the Canadian dollar weakens, the Company's reported results are higher. The Company's foreign exchange gain or losses primarily include unrealized gains or losses on the translation of the Company's US$ and UK pounds sterling denominated working capital balances. The Company's foreign currency policy is to monitor foreign currency risk exposure in its areas of operations and mitigate that risk where possible by matching foreign currency denominated expenses with revenues denominated in foreign currencies. The Company attempts to limit its exposure to foreign currency through collecting and paying foreign currency denominated balances in a timely fashion. The Company had no contracts in place to manage foreign currency risk as at or during the three and six months ended June 30, 2018.

13. Capital Management

The basis for the Company's capital structure is dependent on the Company's expected business growth and any changes in the business and commodity price environment. Stewardship of the Company's capital structure is managed through its financial and operating forecast process. The forecast of the Company's future cash flows is based on estimates of production, crude oil prices, royalty expenses, operating expenses, general and administrative expenses, capital expenditures and other investing and financing activities. The forecast is regularly updated based on changes in commodity prices, production expectations and other factors that in the Company's view would impact cash flow.

The Company's objective is to maintain net debt to trailing twelve-month funds flow from operations at or below a level of 3.0 to 1. While the Company may exceed this ratio from time to time, efforts are made after a period of variation to bring the measure back in line. Net debt is a Non-IFRS measure calculated by summing working capital and the principal (undiscounted) amount of long-term debt. Working capital is a Non-IFRS measure calculated as current assets less current liabilities as they appear on the consolidated statements of financial position. Net debt is used by management as a key measure to assess the Company's liquidity.

The Company also monitors its capital management through the net debt to net debt plus equity ratio. The Company's strategy is to utilize more equity than debt, thereby targeting net debt to net debt plus shareholders' equity at a ratio of less than 0.4 to 1.

14. Commitments

The Company has minimum work obligations under various operating agreements with Petrotrin, exploration commitments under exploration licence and production agreements with the MEEI and various lease commitments for office space and equipment.

As at June 30, 2018, the Company's estimated contractual capital requirements over the next three years and thereafter were as follows:

Under the terms of its operating agreements, the Company must fulfill minimum work obligations on an annual basis over the specific licence term. In aggregate, the Company is obligated to drill 12 wells and perform 18 well recompletions prior to the end of 2021. As of June 30, 2018, nine wells and 13 well recompletions were completed with respect to these obligations.

The Company has provided US$299,000 ($393,000) in cash collateralized guarantees to Petrotrin to support its operating agreement work commitments which was classified as long-term restricted cash and cash equivalents at June 30, 2018 (December 31, 2017 - US$299,000 and $376,000).

Under the terms of its exploration licences, the Company must drill five wells prior to the end of December 31, 2020; none of which have been completed as of June 30, 2018. The Company has provided a US$2,150,000 letter of credit to the MEEI to support exploration work commitments on its East Brighton offshore concession. This letter of credit has been secured by a facility with Export Development Canada.