Trillion Energy International Inc. - Quarter Report: 2019 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended March 31, 2019

For the transition period from ___________ to ___________

Commission File Number: 000-55539

TRILLION ENERGY INTERNATIONAL INC.

(formerly known as Park Place Energy, Inc.)

(Exact name of small business issuer as specified in its charter)

(778) 819-8503

Registrant’s telephone number, including area code

N/A

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [  ] No [X]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [  ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [  ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [  ] No [X]

State the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date: The registrant had 83,623,466 shares of common stock outstanding as of June 17, 2019.

TRILLION ENERGY INTERNATIONAL INC.

Formerly known as Park Place Energy, Inc.

Form 10-Q

Table of Contents

PART I

Item 1. Financial Statements

TRILLION ENERGY INTERNATIONAL INC.

Formerly known as Park Place Energy, Inc.

Consolidated Balance Sheets

(Expressed in U.S. dollars)

See accompanying condensed notes to these interim consolidated financial statements.

TRILLION ENERGY INTERNATIONAL INC.

Formerly known as Park Place Energy, Inc.

Consolidated Statements of Operations and Comprehensive Loss

(Expressed in U.S. dollars)

(unaudited)

See accompanying condensed notes to these interim consolidated financial statements.

TRILLION ENERGY INTERNATIONAL INC.

Formerly known as Park Place Energy, Inc.

Consolidated Statements of Stockholders’ Equity

(Expressed in U.S. dollars)

(unaudited)

See accompanying notes to interim consolidated financial statements

TRILLION ENERGY INTERNATIONAL INC.

Formerly known as Park Place Energy, Inc.

Consolidated Statements of Cash Flows

(Expressed in U.S. dollars)

(unaudited)

See accompanying condensed notes to these interim consolidated financial statements.

TRILLION ENERGY INTERNATIONAL INC.

Formerly known as Park Place Energy, Inc.

Notes to the Condensed Interim Consolidated Financial Statements

(unaudited)

Trillion Energy International Inc. and its consolidated subsidiaries, (“Trillion Energy”, the “Company” and formerly known as Park Place Energy, Inc.) is a U.S. based oil and natural gas exploration and production company. Our corporate headquarters are located at Suite 700, 838 West Hastings Street, Vancouver, B.C., Canada. The Company also has registered offices in Turkey and Bulgaria. The Company was incorporated in Delaware in 2015.

On January 11, 2019, the Company filed a preliminary non-offering prospectus with the British Columbia Securities Commission (“BCSC”). The prospectus is being filed in accordance with the provisions of Canadian National Instrument 41-101 – General Prospectus Requirements to qualify the distribution of the Company’s common shares in Canada. No new securities are being registered for offer. Concurrently with the filing, the Corporation is making an application to list the Corporation’s common shares on the Canadian Securities Exchange. The listing is subject to a number of conditions, including the filing of, and acceptance by, a final non-offering prospectus with the BCSC, and acceptance and approval by the Canadian Securities Exchange.

Effective April 1, 2019, the Company changed its name from Park Place Energy Inc. (OTC: PKPL) to Trillion Energy International Inc. (OTC: TCFF). The Company’s new CUSIP is 89621V103.

The accompanying unaudited condensed consolidated financial statements of the Company have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three month period ended March 31, 2019 are not necessarily indicative of the results that may be expected for the year ended December 31, 2019.

The consolidated balance sheet at December 31, 2018, has been derived from the audited consolidated financial statements at that date but does not include all the information and footnotes required by generally accepted accounting principles for complete financial statements.

For further information, refer to the consolidated financial statements and footnotes thereto included in Trillion Energy’s annual report on Form 10-K for the year ended December 31, 2018.

The Company has suffered recurring losses from operations and the Company has a significant working capital deficiency. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. The Company will need to raise funds through either the sale of its securities, issuance of corporate bonds, joint venture agreements and/or bank financing to accomplish its goals. If additional financing is not available when needed, the Company may need to cease operations. The Company may not be successful in raising the capital needed to drill and/or rework existing oil wells. Any additional wells that the Company may drill may be non-productive. Management believes that actions presently being taken to secure additional funding for the reworking of its existing infrastructure will provide the opportunity for the Company to continue as a going concern. Since the Company has an oil producing asset, its goal is to increase the production rate by optimizing its current infrastructure. The accompanying financial statements have been prepared assuming the Company will continue as a going concern; no adjustments to the financial statements have been made to account for this uncertainty.

The preparation of consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company regularly evaluates estimates and assumptions related to the estimated useful lives and recoverability of long-lived assets, impairment of oil and gas properties, fair value of stock-based compensation, and deferred income tax asset valuation allowances. The Company bases its estimates and assumptions on current facts, historical experience, and various other factors that it believes to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities and the accrual of costs and expenses that are not readily apparent from other sources. The actual results experienced by the Company may differ materially and adversely from the Company’s estimates. To the extent there are material differences between the estimates and the actual results, future results of operations will be affected.

The Company considers all highly liquid instruments with maturity of three months or less at the time of issuance to be cash equivalents.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The Company adopted this standard on a modified retroactive basis on January 1, 2018. No financial statement impact occurred upon adoption.

Revenue from Contracts with Customers

The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product to a customer. Revenue is measured based on the consideration the Company expects to receive in exchange for those products.

Performance Obligations and Significant Judgments

The Company sells oil and natural gas products in Turkey. The Company enters into contracts that generally include one type of distinct product in variable quantities and priced based on a specific index related to the type of product.

The oil and natural gas are typically sold in an unprocessed state to processors and other third parties for processing and sale to customers. The Company recognizes revenue at a point in time when control of the oil is transferred. For oil sales, control is typically transferred to the customer upon receipt at the wellhead or a contractually agreed upon delivery point. Under the Company’s natural gas contracts with processors, control transfers upon delivery at the wellhead or the inlet of the processing entity’s system. For the Company’s other natural gas contracts, control transfers upon delivery to the inlet or to a contractually agreed upon delivery point. In the cases where the Company sells to a processor, the Company has determined that the Company is the principal in the arrangement and the processors are the Company’s customers. The Company recognizes the revenue in these contracts based on the net proceeds received from the processor.

Transfer of control drives the presentation of transportation and gathering costs within the accompanying unaudited consolidated statements of operations. Transportation and gathering costs incurred prior to control transfer are recorded within the transportation and gathering expense line item on the accompanying unaudited consolidated statements of operations, while transportation and gathering costs incurred subsequent to control transfer are recorded as a reduction to the related revenue.

A portion of the Company’s product sales are short-term in nature. For those contracts, the Company uses the practical expedient in Accounting Standards Codification (“ASC”) 606-10-50-14 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For the Company’s product sales that have a contract term greater than one year, the Company uses the practical expedient in ASC 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to an unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has no unsatisfied performance obligations at the end of each reporting period.

The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including any variable consideration identified. There is a low level of uncertainty due to the precision of measurement and use of index-based pricing with predictable differentials. Additionally, any variable consideration identified is not constrained.

Accounts receivable consist of oil and natural gas receivables. The Company has classified these as short-term assets in the balance sheet because the Company expects repayment or recovery within the next 12 months. The Company evaluates these accounts receivable for collectability and, when necessary, records allowances for expected unrecoverable amounts. The Company deems all accounts receivable to be collectable and has not recorded any allowance for doubtful accounts.

In accordance with ASC 360 “Property, Plant and Equipment”, the Company tests long-lived assets or asset groups for recoverability when events or changes in circumstances indicate that their carrying amount may not be recoverable. Circumstances that could trigger a review include, but are not limited to: significant decreases in the market price of the assets; significant adverse changes in the business climate or legal factors; accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of the assets; current period cash flow or operating losses combined with a history of losses or a forecast of continuing losses associated with the use of the assets; and current expectation that the assets will more likely than not be sold or disposed significantly before the end of their estimated useful life. Recoverability is assessed based on the carrying amount of the assets and their fair value, which is generally determined based on the sum of the undiscounted cash flows expected to result from the use and the eventual disposal of the assets, as well as specific appraisal in certain instances. An impairment loss is recognized when the carrying amount of the assets is not recoverable and exceeds fair value.

The Company follows the full cost method of accounting for oil and natural gas operations, whereby all costs of exploring for and developing oil and natural gas reserves are capitalized and accumulated in cost centers on a country-by-country basis. Costs include: license and land acquisition costs, geological, engineering, geophysical, seismic, and other data, carrying charges on non-productive properties and costs of drilling and completing both productive and non-productive wells. General and administrative costs which are associated with acquisition, exploration and development activities are capitalized. General and administrative costs are capitalized other than to the extent of the Company’s working interest in operated capital expenditure programs on which operator’s fees have been charged equivalent to standard industry operating agreements.

The costs in each cost center, including the costs of well equipment, are depleted and depreciated using the unit-of-production method based on the estimated proved reserves before royalties. The costs of acquiring and evaluating significant unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion.

The capitalized costs (less accumulated depletion and depreciation in each cost center) are limited to an amount equal to the estimated future net revenue from proved reserves (based on prices and costs at the balance sheet date) plus the cost (net of impairments) of unproved properties. The total capitalized costs, less accumulated depletion and depreciation, site restoration provision and future income taxes of all cost centers, is further limited to an amount equal to the future net revenue from proved reserves plus the cost (net of impairments) of unproved properties of all cost centers less estimated future site restoration costs, general and administrative expenses, financing costs and income taxes.

Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly decrease the Company’s total proven reserves.

Property and equipment are stated at cost and depreciated using the straight-line method over the shorter of the estimated useful life of the asset or the lease term. The estimated useful lives are: other equipment are depreciated over 20 years; and operating lease right-of-use assets and leasehold improvements are depreciated over the term of the lease.

The Company records the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that results from the acquisition, construction, development, and/or normal use of the long-lived assets. The Company also records a corresponding asset that is amortized over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each period to reflect the passage of time (accretion expense) and changes in the estimated future cash flows underlying the obligation (asset retirement cost).

The carrying amounts reported in the consolidated balance sheets for cash equivalents, account receivables, notes receivable, accounts payable and accrued liabilities and loans payable approximate fair value because of the immediate or short-term maturity of these financial instruments. None of these instruments are held for trading purposes.

The Company accounts for income taxes using the asset and liability method in accordance with ASC 740, “Accounting for Income Taxes”. The asset and liability method provides that deferred tax assets and liabilities are recognized for the expected future tax consequences of temporary differences between the financial reporting and tax bases of assets and liabilities and for operating loss and tax credit carry forwards. Deferred tax assets and liabilities are measured using the currently enacted tax rates and laws that will be in effect when the differences are expected to reverse. The Company records a valuation allowance to reduce deferred tax assets to the amount that is believed more likely than not to be realized.

As of December 31, 2018, and 2017, the Company did not have any amounts recorded pertaining to uncertain tax positions. The Company recognizes interest and penalties related to uncertain tax positions in general and administrative expense. The Company did not incur any penalties or interest during the years ended December 31, 2018 and 2017. On December 22, 2017 the U.S. enacted the Tax Cuts and Jobs Act (“the Tax Act”) which significantly changed U.S. tax law. The Tax Act lowered the Company’s statutory federal income tax rate from a maximum of 39% to a rate of 21% effective January 1, 2018. The company has deferred tax losses and assets and they were adjusted as a result of the change in tax law reducing the federal income tax rate. The Company’s tax years 2014 and forward remain open.

Operations outside the United States prepare financial statements in currencies other than the United States dollar. The income statement amounts are translated at average exchange rates for the year, while the assets and liabilities are translated at year-end exchange rates. Translation adjustments are accumulated as a separate component of stockholders’ equity and other comprehensive income. The functional currency of the Company’s Bulgarian operations is considered to be the Bulgarian Lev. The functional currency of the Company’s Turkish operations is considered to be the Turkish lira.

The Company records stock-based compensation in accordance with ASC 718 (“Compensation – Stock Compensation”) using the fair value method. All transactions in which goods or services are the consideration received for the issuance of equity instruments are accounted for based on the fair value of the consideration received or the fair value of the equity instrument issued, whichever is more reliably measurable.

The Company uses the Black-Scholes option pricing model to calculate the fair value of stock-based awards. This model is affected by the Company’s stock price as well as assumptions regarding a number of subjective variables. These subjective variables include, but are not limited to, the Company’s expected stock price volatility over the term of the awards, and actual and projected stock option exercise behaviors. The value of the portion of the award that is ultimately expected to vest is recognized as an expense in the statement of operations over the requisite service period.

The Company computes loss per share of Company stock in accordance with ASC 260 “Earnings per Share” which requires presentation of both basic and diluted earnings per share (“EPS”) on the face of the income statement. Basic EPS is computed by dividing the loss available to common shareholders (numerator) by the weighted average number of shares outstanding (denominator) during the period. Diluted EPS gives effect to all dilutive potential common shares outstanding during the period using the treasury stock method and convertible preferred stock using the if-converted method. In computing diluted EPS, the average stock price for the period is used in determining the number of shares assumed to be purchased from the exercise of stock options or warrants. Diluted EPS excludes all dilutive potential shares if their effect is anti-dilutive. As of March 31, 2019 and 2018, the Company had 22,154,782 and 11,990,000 potentially dilutive shares outstanding, which were excluded from the calculation of diluted EPS, respectively.

Comprehensive loss consists of net loss and foreign currency cumulative translation adjustment.

New Accounting Pronouncements

Adopted in the Current Year

In February 2016, the Financial Accounting Standards Board, or FASB, established Topic 842, Leases, by issuing Accounting Standards Update (“ASU”) No. 2016-02, which requires lessors to classify leases as a sales-type, direct financing, or operating lease and requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. Topic 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements.

The Company adopted the new standard effective January 1, 2019 and elected the modified retrospective for the transition. The Company elected the following practical expedients:

Lessee Accounting

The new standard requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with a term longer than 12 months. Leases are classified as finance or operating at inception, with classification affecting the pattern and recording of expenses in the statement of operations. Upon transition the Company recognized lease assets and lease liabilities principally for its office lease. When measuring lease liabilities for leases that were classified as operating leases, the Company discounted lease payments using its incremental borrowing rate at January 1, 2019. The weighted-average rate applied was 10%. Refer to Notes 6 and 9.

Included in prepaid expenses and deposits for the three months ended March 31, 2019, is approximately $161,311 relating to field insurance for the Turkey Operations.

Included in prepaid expenses and deposits for the year ended December 31, 2018, is approximately $237,791 relating to field insurance for the Turkey Operations.

The restricted cash relates to drilling bonds provided to GDPA (General Directorate of Petroleum Affairs) for the exploration licenses due to Turkish Petroleum Law. The amounts are for 2% of the annual work budget of the different Turkish licenses which is submitted to GDPA on an annual basis.

Bulgaria

The Company holds a 98,205-acre oil and natural gas exploration claim in the Dobrudja Basin located in northeast Bulgaria. The Company intends to conduct exploration for natural gas and test production activities over a five-year period in accordance with or exceeding its minimum work program obligation. The Company’s commitment is to perform geological and geophysical exploration activities in the first 3 years of the initial term (the “Exploration and Geophysical Work Stage”), followed by drilling activities in years 4 and 5 of the initial term (the “Data Evaluation and Drilling Stage”). The Company is required to drill 10,000 meters (approximately 32,800 feet) of new wellbore (which may be vertical, horizontal, or diagonal) and conduct other exploration activities during the initial term. The Company intends to commence its work program efforts once it receives all regular regulatory approvals of its work programs.

Turkey

Cendere oil field

The primary asset of the Trillion Energy Turkey Companies is the Cendere onshore oil field, which is a profitable oil field located in South East Turkey having a total of 25 wells. The Cendere Field was first discovered in 1988. Oil production commenced during 1990. The operator of the Cendere Field is TPAO. The Company’s interest is 19.6% for all wells except for wells C-13, C-15 and C-16, for which its interest is 9.8%. The produced oil has a gravity of 27.5o API.

The Cendere Field is a long term low decline oil reserve. The Company has a 19.6% interest in the Cendere oil field located in Southeast Turkey. This mature oilfield consistently produces 150 bopd (barrels oil per day) net to the Company. During April 2019, the Company’s average net oil was 128.17 bopd at 96% water cut.

At December 31, 2018, the Cendere field was producing 170 barrels of oil equivalent per day, net to the Trillion Energy Turkey Companies; and averaged 150 barrels of oil equivalent per day during 2018 net to the Trillion Energy Turkey Companies. After the initial development of the Cendere Field, oil production was approximately 2,000 bopd from three wells and which peaked at approximately 7,000 bopd in 1992, when additional wells were put into production. The field started to produce water during the first year of production. As of May 1, 2019, 20.3MMbbls of oil have been produced from the Cendere Field.

A description of the Cendere Field geological and reservoir characteristics is as follows. The reservoirs are located in the South East Anatolian Basin and within the Middle Cretaceous period. The carbonated Derdere Formation is the main reservoir in Cendere Field and has dolomitization and fracturing, which enhance its production characteristics. There are also four additional oil reservoirs contained within Cendere Field. The Cendere Field is covered by 54 km2 of 3D seismic that was acquired in 2004.

The field was developed using a collection of dispersed oil wells from which production is collected and exported to the Cendere gathering station. The produced oil is exported to the TPAO Karakus processing facility which then is transported onwards to the BOTAS-operated oil pipeline. There are 20 well pads which currently house 16 producing wells spread over an area of approximately 15 square kilometers. A field gathering station, located to the southwest of the Cendere Field collects the oil and produced water from a collection of flowlines and manifolds.

The South Akcakoca Sub-Basin (“SASB”)

The Company owns offshore production licenses called the South Akcakoca Sub-Basin (“SASB”). The Company now owns a 49% working interest in SASB, 12.25% which was obtained during January 2018. The additional interest was acquired with cash of $309,515, 1,000,000 shares issued on November 22, 2017 fair valued at $90,000 and a further share issuance of 500,000 shares on January 30, 2018 fair valued at $67,500 for total consideration of $467,015. SASB has four producing fields, each with a production platform plus subsea pipelines that connect the fields to an onshore gas plant. The four SASB fields are located off the north coast of Turkey towards the western end of the Black Sea in water depths ranging from 60 to100 meters. Gas is produced from Eocene age sandstone reservoirs at subsea depths ranging from 1,100 to1,800 meters.

Bakuk gas field

The Company also owns a 50% operated interest in the Bakuk gas field located near the Syrian border. The Bakuk field is shut-in with no plans to revive production in the near term.

In April 2015, the Company loaned $38,570 to a Bulgarian company pursuant to a revolving credit facility, enabling such Bulgarian company to buy and manage land in Bulgaria to be leased by the Company for future well sites. The credit facility has a maximum loan obligation of BGN 1,000,000 ($585,114 USD at March 31, 2019) bears interest at 6.32%, has a five-year term and is secured by the land the Bulgarian company buys. Payment on the facility is due the earlier of the end of the five-year term (April 6, 2020) or demand by the Company. As of March 31, 2019, the outstanding balance on the loan obligation was $48,217 (December 31, 2018: $49,192). The change in balance was due to changes in foreign currency translations.

Loans bearing interest, accrue at 10% per annum are all unsecured. All loans are due on demand. No interest has been inputted on the non-interest-bearing loans as it would be immaterial to the financial statements.

The Company leases certain assets under lease agreements. The lease liability consists of a single lease for office space which was classified as an operating lease. Upon adoption of Topic 842, on January 1, 2019 the Company recognized an addition to right-of-use assets of $60,309 and lease liabilities of $59,076. The difference between the recorded right-of-use assets and lease liabilities is mainly due to the reclassification of prepaid leasehold improvements incurred in lieu of twelve months rent which was included within the right-of-use asset recognized upon transition. As of March 31, 2019, the lease had remaining terms of 3 years and a weighted average remaining lease term of 3 years. Operating right-of-use assets and lease liabilities have been included within property and equipment and lease liabilities on the Company’s condensed consolidated balance sheet as follows:

Operating lease liabilities are measured at the commencement date based on the present value of future lease payments. As the Company’s lease did not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the commencement date in determining the present value of future payments. The Company used a weighted average discount rate of 10% in determining its lease liabilities. The discount rate was derived from the Company’s assessment of current borrowings.

Operating lease right-of-use assets include any prepaid lease payments and exclude any lease incentives and initial direct costs incurred. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term. The lease terms may include options to extend or terminate the lease if it is reasonably certain that the Company will exercise that option.

Accretion on operating lease liabilities for the three months ended March 31, 2019 was $1,424. Principal payments against the operating lease liabilities for the three months ended March 31, 2019 was $5,264.

Future minimum lease payments to be paid by the Company as a lessee for operating leases as of March 31, 2019 for the next five years and thereafter are as follows:

Asset retirement obligations (“AROs”) associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The fair value of AROs is recognized as of the acquisition date. The cost of the tangible asset, including the asset retirement cost, is depleted over the life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. Our ARO is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging costs, remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs.

The Company estimated an ARO for the addition of 12.25% of the South Akcakoca Sub Basin as disclosed in Note 2. For the current period addition, the Company used 2.5% as inflation rate and used a risk-free rate of 10% to present value the obligation.

The following is a description of the Company’s asset retirement obligations:

For the three months ended March 31, 2019

For the three months ended March 31, 2018

The Board of Directors adopted the Park Place Energy Corp. 2013 Long-Term Incentive Equity Plan (the “Incentive Plan” or “2013 Plan”) effective as of October 29, 2013. The Incentive Plan permits grants of stock options (including incentive stock options and nonqualified stock options), stock appreciation rights, restricted stock awards, and other stock-based awards.

The Incentive Plan authorizes the following types of awards:

Under the 2013 Plan, the maximum number of shares of authorized stock that may be delivered is 10% of the total number of shares of common stock issued and outstanding of the Company as determined on the applicable date of grant of an award under the 2013 Plan. Under the 2013 Plan, the exercise price of each option (or other stock-based award) shall not be less than the market price of the Company’s stock as calculated immediately preceding the day of the grant. The vesting schedule for each option or other stock-based award shall be specified by the Board of Directors at the time of grant. The maximum term of options or other stock-based award granted is ten years or such lesser time as determined by the Board of Directors at the time of grant.

A continuity of the Company’s outstanding stock options for the three months ended March 31, 2019 is presented below:

At March 31, 2019, the Company had the following outstanding stock options:

As of March 31, 2019, all stock options have fully vested. The weighted average remaining contractual life of outstanding stock options is 3.72 years (December 31, 2018: 3.87). The aggregate intrinsic value of the stock options at March 31, 2019 is $131,100 (December 31, 2018: $Nil).

There was no compensation expense related to stock options recognized during the three months ended March 31, 2019 and 2018. At March 31, 2019, the Company has no unrecognized compensation expense related to stock options.

A continuity of the Company’s outstanding share purchase warrants for the three months ended March 31, 2019 is presented below:

At March 31, 2019, the Company had the following outstanding share purchase warrants:

The weighted average remaining contractual life of outstanding warrants is 1.41 years (December 31, 2018: 1.65).

At March 31, 2019, $104,945 of accounts payable were to related parties as compared to $67,345 at December 31, 2018 for outstanding management and consulting fees. The amounts owed, and owing are unsecured, non-interest bearing, and due on demand.

During the three months ended March 31, 2019, included in general and administrative expenses is $37,500 (2018: $50,000) in respect of directors and management fees.

During 2019 and 2018, the Company’s operations were in the resource industry in Bulgaria, and Turkey with head offices in the United States and a satellite office in Sofia, Bulgaria. The Company operated a few segments, a head office in Canada, an oil and natural gas operations in Turkey and its oil and natural gas properties are located in Bulgaria.

For the period ended March 31, 2019

For the period ended March 31, 2018

The Company is subject to United States federal and state income taxes at a rate of 21%. The reconciliation of the provision for income taxes at the United States federal statutory rate compared to the Company’s income tax expense as reported is as follows:

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to provide readers of our financial statements with a narrative from the perspective of our management on our financial condition, results of operations, liquidity, and certain other factors that may affect our future results. Our MD&A is presented in the following sections:

Our MD&A should be read in conjunction with our unaudited financial statements of Trillion Energy International Inc. (“Trillion Energy”, Company”, “we”, and “our” and formerly known as Park Place Energy, Inc.) and related Notes in Part I, Item 1 of the Quarterly Report on Form 10-Q and Item 8, Financial Statements and Supplementary Data, of the Annual Report on Form 10-K for the year ended December 31, 2018.

Our website can be found at www.trillionenergy.com. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed with or furnished to the U.S. Securities and Exchange Commission (“SEC”), pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (“Exchange Act”), can be accessed free of charge by linking directly from our website under the “Investor Relations - SEC Filings” caption to the SEC’s Edgar Database.

Executive Summary

Trillion Energy is a U.S. based oil and gas exploration and production company focused on expanding its portfolio of projects in Southeast Europe, Turkey, and countries in the immediate vicinity. The Company’s concentration is on recently acquired oil and gas producing assets in Turkey and a coal bed methane exploration license in Bulgaria.

On January 11, 2019, the Company filed a preliminary non-offering prospectus with the British Columbia Securities Commission (“BCSC”). The prospectus is being filed in accordance with the provisions of Canadian National Instrument 41-101 – General Prospectus Requirements to qualify the distribution of the Company’s common shares in Canada. No new securities are being registered for offer. Concurrently with the filing, the Corporation is making an application to list the Corporation’s common shares on the Canadian Securities Exchange. The listing is subject to a number of conditions, including the filing of, and acceptance by, a final non-offering prospectus with the BCSC, and acceptance and approval by the Canadian Securities Exchange.

Effective April 1, 2019, the Company changed its name from Park Place Energy Inc. (OTC: PKPL) to Trillion Energy International Inc. (OTC: TCFF). The Company’s new CUSIP is 89621V103.

Turkey

On January 18, 2017, the Company completed the acquisition of three oil and natural gas producing fields in Turkey. The purchase price for the acquisition of the Trillion Energy Turkey Companies from Tiway Oil B.V. was $2.1 million. At March 31, 2019 net production from these fields was around 199.52 boepd (barrel of oil equivalent per day).

The primary asset of the Trillion Energy Turkey Companies is the Cendere onshore oil field, which is a profitable oil field located in South East Turkey having a total of 25 wells. The Cendere Field was first discovered in 1988. Oil production commenced during 1990. The operator of the Cendere Field is TPAO. The Company’s interest is 19.6% for all wells except for wells C-13, C-15 and C-16, for which its interest is 9.8%. The produced oil has a gravity of 27.5o API. After the initial development of the Cendere Field, oil production was approximately 2,000 bopd from three wells and which peaked at approximately 7,000 bopd in 1992, when additional wells were put into production. The field started to produce water during the first year of production. As of May 1, 2019, 20.3MMbbls of oil have been produced from the Cendere Field. During April 2019, the Company’s average net oil was 128.17 bopd at 96% water cut.

A description of the Cendere Field geological and reservoir characteristics is as follows. The reservoirs are located in the South East Anatolian Basin and within the Middle Cretaceous period. The carbonated Derdere Formation is the main reservoir in Cendere Field and has dolomitization and fracturing which enhance its production characteristics. There are also four additional oil reservoirs contained within Cendere Field.

The Cendere Field is covered by 54 km2 of 3D seismic that was acquired in 2004.

The field was developed using a collection of dispersed oil wells from which production is collected and exported to the Cendere gathering station. The produced oil is exported to the TPAO Karakus processing facility which then is transported onwards to the BOTAS-operated oil pipeline.

There are 20 well pads which currently house 16 producing wells spread over an area of approximately 15 square kilometers. A field gathering station, located to the southwest of the Cendere Field collects the oil and produced water from a collection of flowlines and manifolds.

The Cendere Field is a long term low decline oil reserve. The Company has a 19.6% interest in the Cendere oil field located in Southeast Turkey. This mature oilfield consistently produces between 110 and 123 bopd (barrels oil per day) net to the Company.

At March 31, 2019, the gross oil production rate for the producing wells in Cendre was 142 bbls/day; the average daily 2018 gross production rate for the field was 770 bbls/day. As of May 2019, oil is currently sold at a price of approximately US$67 per barrel for a netback per barrel of approximately US$32. At year-end 2018, the Cendere field was producing 170 barrels of oil per day, net to the Trillion Energy Turkey Companies; and averaged 150 barrels per day during 2018 net to the Trillion Energy Turkey Companies.

The main producing asset was a 36.75% interest in an offshore gas development project called the South Akçakoca Sub-Basin (SASB). The Company further acquired from its partner Foinavon Energy Turkey Inc. 12.25% working interest in the same license for 1,500,000 shares of the Company and $275,000 on February 8, 2018 to have a total of 49%. This field has four offshore platforms connected to an onshore gas plant. On March 31, 2019, net gas production to the Company was around 427 Mcfd (thousand cubic feet per day) from six producing wells. The SASB field potentially holds significant upside.

At SASB, the Company plans to reprocess the 3D seismic to facilitate a potential future program of drilling to bring discovered undeveloped gas pools on to production.

Bulgaria

The Company entered into an exploration license over a 98,000 acre block in northeast Bulgaria in 2014. The overall five year and our first year work programs were approved by the Ministry of Environment (“MEW”), however, the MEW approval was appealed in an administrative proceeding. The administrative court remanded the matter to MEW in May 2017 for a determination by the MEW as to whether an ecological evaluation of the license area should be required. This matter was determined in 2017 and we are in the progress of obtaining an environmental report which will cost an estimated $100,000. Upon the license becoming effective our exploration program will commence in 2019 for a term of five (5) years.

We are required to post a bond (105,000 Euros) upon the 5 year license term commencement. The license period may be extended for up to 5 additional years and may then be converted into an exploitation concession, which can last for up to 35 years. The Company’s initial 5 year commitment involves geological and geophysical exploration activities for the first 3 years followed by drilling at least 10,000 meters (approximately 32,800 feet) of new wellbore in years 4 and 5.

Strategic Focus

Oil and natural gas prices in Turkey and throughout Southeast Europe make this region highly attractive for oil and gas exploration and production. Most of the countries, including Turkey and Bulgaria, import nearly all of their oil and natural gas and consumption is projected to increase. Turkey also contains many opportunities for additional oil and coal bed methane production as well as enhanced oil and natural gas recovery from existing fields. The Company will evaluate these opportunities as they appear. The fiscal terms are highly attractive. In Turkey, there is a 20% corporate tax and a 12.5% royalty. In Bulgaria, the corporate tax rate is 10% and the royalties are on a sliding rate starting at 3.5% up to 13.5%.

The license area holds great attraction as a potential coal bed methane exploration project. The license area was extensively drilled for coal exploration from 1964 to 1990. It was determined that coal mining was not technically feasible. However, the coal exploration drilling provided us with an extensive database.

Results of Operations

The following summary of our results of operations should be read in conjunction with our unaudited consolidated financial statements for the periods ended March 31, 2019 and 2018 which are included herein.

Revenue

Revenue increased from $964,022 to $1,024,784, growth of 6.3%, for the three months ended March 31, 2019. Revenue increased due to additional production relating to the acquisition of an additional 12.25% working interest in a producing gas property and increased oil prices per barrel.

Expenses

Our general and administrative expenses for the three months ended March 31, 2019 were $417,480 compared to $420,966 for the three months ended March 31, 2018. $160,702 in expenses were from the North American head office compared to $178,344 in the three months ended March 31, 2018, which resulted in a year over year decrease of $17,492. The decrease is mostly attributable to a decrease in general & administrative expenses in the North American operations; $56,150 was for consulting and management fees (2018 - $131,643) and $35,455 in audit and financial services (2018 - $22,142) and partially offset by increased legal and professional fees of $53,774 (2018 - $8,535). The decrease in general and administrative expenses was also partially offset by Turkey general and administrative expenses which accounted for $256,778 of the total general and administrative for 2019 compared to $242,722 for the three months ended March 31, 2018 resulting in a year over year increase of $14,056.

The Company incurred production expenses related to its Tiway operations of $658,453, depletion charges of $151,400, depreciation expense of $12,353 and accretion expense of $100,653 for the three months ended March 31, 2019 compared to production expenses of $711,621, depletion charges of $163,049, depreciation expense of $5,348 and accretion expense of $84,058 for the three months ended March 31, 2018. Production and depletion expenses decreased by $64,817 for the period due to a strengthening of the US dollar compared to the Turkish Lira. This was partially offset by an increase to accretion of asset retirement costs of $16,595 due to the increase in the cost base to the asset retirement obligation from the Foinovan interest acquisition and an increase to depreciation of $7,005 due to the transition to Topic 842 for lease assets and liabilities.

Other Income (Expense)

For the three months ended March 31, 2019, the Company recorded other income (expense) of $538 compared to other income (expense) of ($129,143) for the same period in 2018. This overall decrease in other (expense) was due to a $102,500 loss on debt settlement recorded in 2018.

Loss

Our net loss for the three months ended March 31, 2019 was $315,017 compared to $550,163 for the three months ended March 31, 2018. The decrease in overall net losses was a result of the factors as described above.

Liquidity and Capital Resources

The following table summarizes our liquidity position:

Cash Used in Operating Activities

We used cash of $368,320 from operating activities for the three months ended March 31, 2019 compared to $180,160 for the three months ended March 31, 2019. The loss of $315,017 was offset by $274,968 in non-cash expenses for the three months ended March 31, 2019. An increase of $436,306 in receivables from the additional output associated with the increase in working interest and the increased revenue pushed operating outflows to $328,271. Accounts payable and accrued liabilities increased cash inflows by $30,439 which increased solely in the parent company’s operations.

Cash Flow from Investing Activities

Net cash used in investing activities for the three months ended March 31, 2019 was $31,048 compared to $309,515 in the comparative period due to the Company adding a further interest to the SASB field in the first quarter of 2018.

Cash Provided by Financing Activities

We have funded our business to date primarily from sales of our common stock through private placements and loans. During the three months ended March 31, 2019, we received net cash of $8,000 for stock subscriptions and $3,000 in proceeds from notes payable while repaying $3,200 in loans payable and operating lease payments of $5,264. During the three months ended March 31, 2018, we received net cash of $675,000 for stock subscriptions while repaying $92,520 in loans payable

Future Operating Requirements

Based on our current plan of operations, we estimate that we will require approximately $1.2 million to pursue our plan of operations over the next 12 months. We plan to spend approximately $350,000 on capital expenditures for ongoing redevelopment operations on the Turkish properties primarily for engineering and reports based on reprocessing of data. We also plan to improve our working capital deficit by paying off accounts payable. The operations in Turkey are self-sustaining and will generate net cash flow sufficient to fund in-country general and administrative expenses as well as a portion of our head office overhead. We will require approximately $250,000 for general and administrative expenses.

To reduce our current outstanding trade payables and indebtedness will require approximately $1.2 million; however, we may be able to negotiate terms that will require a lesser amount.

Our current plan of operations in the period 12 months from now contemplates reprocessing of data. Subject to the outcome of reprocessing, our plan for 12- 24 months is the drilling of up to four (4) new wells at SASB. Depending on the timing of the drilling operations at our current interest (currently 49%), we project we will incur up to an additional $16 million in capital expenditures to enable us to conduct such operations.

As of March 31, 2019, the Company had unrestricted cash of $317,378. The Company is attempting to raise additional capital to fund future exploration and operating requirements.

Off-Balance Sheet Arrangements

On October 1, 2018 the Company entered into an agreement to grant to a consultant of the Company a 2% (two percent) gross overriding royalty on petroleum substances produced from certain of its currently undeveloped exploration properties, namely: Block 1-11 Vranino situated in Dobrich District, Bulgaria and seven contiguous exploration licences in the province of Hakkari Yuksekova Semdiali Derecik, Turkey. The Grant of the royalty agreement was for services involving technical and corporate advisory services.

On October 1, 2018 the Company entered into an agreement to grant to the CEO of the Company a 0.5% (one half of one percent) gross overriding royalty on petroleum substances produced from certain of its currently undeveloped exploration properties, namely: Block 1-11 Vranino situated in Dobrich District, Bulgaria and seven contiguous exploration licences in the province of Hakkari Yuksekova Semdiali Derecik, Turkey. The Grant of the royalty agreement was for services involving technical and corporate advisory services.

Forward-Looking Information

Certain statements in this Quarterly Report on Form 10-Q constitute “forward-looking statements” within the meaning of applicable U.S. securities legislation. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “plans,” “expects,” “estimates,” “budgets,” “intends,” “anticipates,” “believes,” “projects,” “indicates,” “targets,” “objective,” “could,” “should,” “may” or other similar words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements, including the factors discussed under Item 1A. Risk Factors in our most recent Annual Report on Form 10-K. Such factors include, but are not limited to, the following: fluctuations in and volatility of the market prices for oil and natural gas products; the ability to produce and transport oil and natural gas; the results of exploration and development drilling and related activities; global economic conditions, particularly in the countries in which we carry on business, especially economic slowdowns; actions by governmental authorities including increases in taxes, legislative and regulatory initiatives related to fracture stimulation activities, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflicts; the negotiation and closing of material contracts; future capital requirements and the availability of financing; estimates and economic assumptions used in connection with our acquisitions; risks associated with drilling, operating and decommissioning wells; actions of third-party co-owners of interests in properties in which we also own an interest; our ability to effectively integrate companies and properties that we acquire; our limited operating history; our history of operating losses; our lack of insurance coverage; and the other factors discussed in other documents that we file with or furnish to the U.S. Securities and Exchange Commission. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors and our course of action would depend upon our assessment of the future, considering all information then available. In that regard, any statements as to: future oil or natural gas production levels; capital expenditures; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital expenditure programs; drilling of new wells; demand for oil and natural gas products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves, including the ability to convert probable and possible reserves to proved reserves; dates by which transactions are expected to close; future cash flows, uses of cash flows, collectability of receivables and availability of trade credit; expected operating costs; changes in any of the foregoing and other statements using forward-looking terminology are forward-looking statements, and there can be no assurance that the expectations conveyed by such forward-looking statements will, in fact, be realized.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.

Readers should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable because we are a smaller reporting company.

Item 4. Controls and Procedures

Evaluation of Disclosure of Controls and Procedures

We carried out an evaluation of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of March 31, 2019 (the “Evaluation Date”). This evaluation was carried out under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, we concluded that our disclosure controls and procedures were effective.

We believe that our consolidated financial statements contained in our Quarterly Report on Form 10-Q for the period ended March 31, 2019 fairly present our financial condition, results of operations and cash flows in all material respects.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

We are not currently involved in any legal proceedings and we are unaware of any pending proceedings.

Item 1A. Risk Factors

Not applicable because we are a smaller reporting company. See risk factors described in Item 1A of the Company’s most recent Annual Report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mining Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.