UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F/A
(AMENDMENT NO. 1)
[X] REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
[ ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended _____________________
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________________ to ____________________
OR
[ ] SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number ____________________
HEMISPHERE ENERGY CORPORATION
(Exact name of Registrant as specified in its charter)
Province of British Columbia, Canada
(Jurisdiction of incorporation or organization)
2000, 1055 West Hastings Street, Vancouver, British Columbia, Canada V6E 2E9
(Address of principal executive offices)
Dorlyn Evancic, Chief Financial Officer
Telephone: (604) 685-9255
Email: info@hemisphereenergy.ca
2000, 1055 West Hastings Street, Vancouver, British Columbia, Canada V6E 2E9
(Name, Telephone, E-Mail and/or Facsimile number and Address of Company Contact Person)
Securities registered or to be registered pursuant to Section 12(b) of the Act:
Title of each class | | Name of each exchange on which registered |
Securities registered or to be registered pursuant to Section 12(g) of the Act: Common shares, no par value
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [ ] No [X]
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Yes [ ] No [ ]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or 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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [ ] No [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See the definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer [ ] | Accelerated filer [ ] | Non-accelerated filer [X] |
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
| U.S. GAAP [ ] | International Financial Reporting Standards as issued | Other [ ] |
| | by the International Accounting Standards Board [X] | |
If “Other” has been checked in response to previous question, indicate by check mark which financial statement item the registrant has elected to follow.
Item 17 [ ] Item 18 [ ]
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [ ]
TABLE OF CONTENTS
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In this Form 20-F, the terms “we”, “our”, “us”, “the Company” and “Hemisphere” refer, unless the context requires otherwise, to Hemisphere Energy Corporation and its subsidiaries, if any, through which it conducts business.
ABBREVIATIONS
| Oil and Natural Gas Liquids | Natural Gas |
| bbl | barrels | Mcf | thousand cubic feet |
| bbl/d | barrels per day | Mcf/d | thousand cubic feet per day |
| bopd | barrels of oil per day | MMcf | million cubic feet |
| boe | barrels of oil equivalent | MMbtu | million British thermal units |
| boe/d | boe per day | Bcf | billion cubic feet |
| Mboe | thousand barrels of oil equivalent | GJ | gigajoule |
| Mbbl | thousand barrels | | |
| NGL | natural gas liquids | | |
| Other | |
| | |
| M$ | thousands of dollars |
| $/boe | dollar per barrel of oil equivalent |
| ha | hectare |
| 3D | three dimensional |
| API | American Petroleum Institute |
| °API | specific gravity of crude oil measured on the API gravity scale |
| AECO | Alberta Energy Company |
| M3 | Cubic metres |
WTI | West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade |
| W.I. | working interest |
BARREL OF OIL EQUIVALENCY
Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
CONVERSIONS
The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units):
| To Convert From | To | Multiply By |
| Mcf | cubic metres | 28.174 |
| cubic metres | cubic feet | 35.494 |
| bbl | cubic metres | 0.159 |
| cubic metres | bbl | 6.289 |
| feet | metres | 0.305 |
| metres | feet | 3.281 |
| miles | kilometres | 1.609 |
| kilometres | miles | 0.621 |
| acres | hectares | 0.405 |
| hectares | acres | 2.471 |
| gigajoules | MMbtu | 0.950 |
| MMbtu | gigajoules | 1.0526 |
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CURRENCY
All amounts are expressed in Canadian dollars unless otherwise stated. See the information under the heading “Item 3.A. Selected Financial Data – Exchange Rate Data” for relevant information about the rates of exchange between Canadian dollars and United States dollars.
FORWARD-LOOKING STATEMENTS
Certain of the statements in this Form 20-F may be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements include, without limitation, statements regarding:
- financial and business prospects and financial outlook;
- reserve and production estimates;
- drilling plans;
- activities to be undertaken in various areas;
- timing of drilling;
- recompletion and tie-in of wells;
- tax horizon;
- timing of development of undeveloped reserves;
- commodity prices and foreign exchange rates; and
- planned capital expenditures, the timing thereof and the method of funding.
Forward-looking statements reflect management's expectations regarding future plans and intentions, growth, results of operations, performance and business prospects and opportunities. Words such as “may”, “will”, “should”, “could”, “anticipate”, “believe”, “expect”, “intend”, “plan”, “potential”, “continue” and similar expressions may be used to identify these forward-looking statements. These statements reflect management's current beliefs and are based on information currently available to management.
Forward-looking statements involve significant risk and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking statements, including, but not limited to, risks associated with:
- the inherently speculative nature of oil and gas exploration, development and production;
- operational hazards and geological problems;
- volatility in prices and markets for oil and natural gas;
- obtaining additional financing and restrictive terms in future debt financing;
- failure to realize anticipated benefits of acquisitions and dispositions;
- dependence on operators of certain of our assets and on our joint venture partners;
- restricted access to pipelines, storage and processing facilities;
- unavailability of equipment and qualified personnel;
- estimating oil and natural gas reserves;
- intense competition in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas;
- laws and government regulations, including environmental regulation, legislative and regulatory initiatives related to climate change and licensing and permitting;
- changes to the royalty regime;
- currency fluctuations;
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- hedging activities;
- title deficiencies;
- inadequate insurance coverage and uninsurable loss;
- management of growth;
- grant and maintenance of appropriate licenses and leases and working interests in licenses and leases;
- seasonal and unexpected weather patterns;
- non-payment or default by third parties;
- loss of key management personnel;
- reassessment of our income tax returns;
- litigation;
- conflicts of interest among our directors and officers;
- title deficiencies and aboriginal title and rights claims;
- restrictive regulation on the marketing of oil and natural gas; and
- recently adopted accounting pronouncements.
The recovery and reserve estimates of our reserves provided in this Form 20-F are estimates only and there is no guarantee that the estimated reserves will be recovered. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. In addition, forward-looking statements may include statements attributable to third party industry sources. There can be no assurances that the plans, intentions or expectations upon which such forward-looking statements are based will occur.
Forward-looking statements or information are based on a number of factors and assumptions that have been used to develop those statements and information but which may prove to be incorrect. Although we believe that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because we can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things:
- the impact of increasing competition;
- the general stability of the economic and political environment in which we operate;
- the timely receipt of any required regulatory approvals;
- our ability to obtain qualified staff, equipment and services in a timely and cost efficient manner;
- drilling results;
- the ability of the operator of the projects in which we have an interest to operate the project in a safe, efficient and effective manner;
- our ability to obtain financing on acceptable terms;
- well production rates and decline rates;
- the ability to replace and expand our oil and natural gas reserves through acquisition, development of exploration;
- the timing and costs of pipeline, storage and facility construction and expansion and our ability to secure adequate product transportation;
- future oil and natural gas prices;
- currency, exchange and interest rates;
- the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which we operate; and
- our ability to successfully market our oil and natural gas products.
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This list is not exhaustive of the factors that may affect any of our forward-looking statements. Some of the important risks and uncertainties that could affect forward-looking statements are described further under the heading “Item 3.D. Risk Factors”. If one or more of these risks or uncertainties materializes, or if underlying assumptions prove incorrect, our actual results may vary materially from those expected, estimated or projected. Forward-looking statements in this document are not a prediction of future events or circumstances, and those future events or circumstances may not occur. Given these uncertainties, users of the information included in this Form 20-F, including investors and prospective investors are cautioned not to place undue reliance on such forward-looking statements.
The forward-looking statements in this Form 20-F speak only as to the date hereof and are based on our beliefs, opinions and expectations at the time they are made. Except as required by applicable law, including the securities laws of the United States and Canada, we do not intend to update any of the forward-looking statements to conform these statements to actual results.
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PART I
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
A. Directors and Senior Management
The name, office and function of our directors and senior management are set forth in the following table.
| Name and Office Held | Function |
Don Simmons, P. Geol.
President, Chief Executive Officer, Director,
Corporate Governance Committee Member and
Reserves Committee Member
| As the President and Chief Executive Officer, Mr. Simmons is responsible for strategic planning and operations, as well as managing relations with our legal advisers, regulatory authorities and the investor community; as a director, Mr. Simmons participates in management oversight and helps to ensure compliance with the our corporate governance policies and standards. |
Charles O’Sullivan, B.Sc.
Director, Chairman, Compensation/ Nominating
Committee Member and Chairman and
Corporate Governance Committee Member | As a director, Mr. O’Sullivan supervises our management and helps to ensure compliance with our corporate governance policies and standards. |
Frank Borowicz, QC, CA (Hon)
Director, Corporate Governance Committee
Member and Chairman, Compensation/
Nominating Committee Member and Audit
Committee Member | As an independent director, Mr. Borowicz supervises our management and helps to ensure compliance with our corporate governance policies and standards. |
Bruce McIntyre, P.Geol.
Director, Reserves Committee Member and
Chairman, Compensation/ Nominating
Committee Member and Audit Committee
Member and Chairman | As an independent director, Mr. McIntyre supervises our management and helps to ensure compliance with our corporate governance policies and standards. |
Gregg Vernon, P. Eng.
Director, Reserves Committee Member and Audit
Committee Member | As an independent director, Mr. Vernon supervises our management and helps to ensure compliance with our corporate governance policies and standards. |
Andrew Arthur, P. Geol.
Vice President, Exploration | As Vice President, Exploration, Mr. Arthur is responsible for our oil and gas exploration. |
Ian Duncan, P. Eng.
Chief Operating Officer | As Chief Operating Officer, Mr. Duncan is responsible for our oil and gas operations. |
Dorlyn Evancic, CGA
Chief Financial Officer
| As Chief Financial Officer, Mr. Evancic is responsible for the management and supervision of all of the financial aspects of our business. |
Ashley Ramsden-Wood, P. Eng.
Vice President, Engineering | As Vice President, Engineering, Ms. Ramsden-Wood is responsible for our oil and gas engineering |
The business address for our directors and senior management is 2000, 1055 West Hastings Street, Vancouver, British Columbia, Canada V6E 2E9.
B. Advisers
Our Canadian legal counsel is Fasken Martineau DuMoulin LLP with a business address at Suite 2900 - 550 Burrard Street, Vancouver, British Columbia, Canada V6C 0A3 and our U.S. legal counsel is Dorsey & Whitney LLP with a business address at Suite 1605 – 777 Dunsmuir Street, Vancouver, British Columbia, Canada V7Y 1K4. Our principal bankers are Alberta Treasury Branches with a business address at Suite 600, 444 7th Avenue SW, Calgary, Alberta, Canada T2P 0X8.
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C. Auditors
Our current auditors are Smythe Ratcliffe LLP, Chartered Accountants, with a business address at 700 – 355 Burrard Street, Vancouver, British Columbia, Canada V6C 2G8. Smythe Ratcliffe LLP, Chartered Accountants, are members of the Institute of Chartered Accountants of British Columbia and are registered with both the Canadian Public Accountability Board and the U.S. Public Company Accounting Oversight Board. Smythe Ratcliffe LLP, Chartered Accountants, were first appointed as our auditors on June 30, 1981.
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE
Not applicable.
ITEM 3. KEY INFORMATION
A. Selected Financial Data
Selected Year End Financial Data
We have selected financial data and information in the following tables for the fiscal years ended February 28, 2010 and 2011, February 29, 2012 and December 31, 2012 and 2013 that were derived from our audited financial statements. These audited financial statements have been audited by Smythe Ratcliffe LLP. Certain prior years’ comparative figures have been reclassified, if necessary.
The information in the following tables should be read in conjunction with the information appearing under the heading “Item 5. Operating and Financial Review and Prospects” and the Company’s audited annual financial statements under the heading “Item 18. Financial Statements”.
On March 1, 2011, we adopted International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”), for financial reporting purposes, using a transition date of March 1, 2010. Our annual audited financial statements for the year ended February 29, 2012, including February 28, 2011 required comparative information, have been prepared in accordance with IFRS, as issued by the International Accounting Standards Board . Financial statements prior to the fiscal year ended February 28, 2011 were prepared in accordance with pre-changeover Canadian generally accepted accounting principles (“Canadian GAAP”).
On August 20, 2012, we announced that we changed our fiscal year-end date from February 28 to December 31. In accordance with relevant legislation, we prepared our first annual audited financial statements as at and for the ten months ended December 31, 2012 with comparative information as at and for the twelve months ended February 29, 2012.
Pursuant to Release No. 33-8879 of the United States Securities and Exchange Commission (“SEC”), “Acceptance from Foreign Private Issuers of Financial Statements Prepared in Accordance with International Reporting Standards Without Reconciliation to U.S. GAAP,” we have included selected financial data prepared in compliance with IFRS without reconciliation to U.S. GAAP.
The following table is a summary of our selected financial information for each of our four most recently completed financial years. All information, except number of shares, is in Canadian dollars. The information is presented in accordance with IFRS.
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| 12 Months
Ended
December 31,
2013 | 10 Months
Ended
December 31,
2012 | 12 Months
Ended
February 29,
2012 | 12 Months
Ended
February 28,
2011 |
| Gross oil and gas revenue | 10,573,199 | 7,875,723 | 4,590,608 | 289,426 |
| Net oil and gas revenue | 8,674,667 | 6,503,840 | 3,888,263 | 257,509 |
| Income (loss) for the year | (5,307,312) | 543,818 | (451,879) | (1,486,455) |
| Income (loss) per share, basic and diluted | (0.10) | 0.01 | (0.01) | (0.07) |
| Net income (loss) for the year | (3,832,078) | 61,361 | 942,665 | (1,486,455) |
| Net income (loss) per share, basic and diluted | (0.07) | 0.00 | 0.03 | (0.07) |
| Weighted-average shares, basic | 54,479,558 | 50,888,868 | 34,211,904 | 20,067,162 |
| Weighted-average shares, diluted | 54,479,558 | 52,308,563 | 34,947,858 | 20,067,162 |
| Number of shares outstanding | 61,307,498 | 53,961,048 | 50,374,701 | 26,071,682 |
| Working capital (deficiency) | (6,700,147) | (3,927,595) | 2,363,944 | 1,729,423 |
| Resource properties and equipment | 25,436,065 | 23,342,590 | 13,905,232 | 1,122,092 |
| Long-term liabilities | 1,323,466 | 467,235 | 358,428 | 67,676 |
| Capital stock | 42,127,674 | 38,805,193 | 36,719,485 | 24,678,806 |
| Retained earnings (deficit) | (25,001,614) | (21,242,708) | (21,304,069) | (22,254,159) |
| Total assets | 29,074,500 | 25,375,435 | 18,914,071 | 3,248,901 |
The following table is a summary of our selected financial information for the fiscal year ended February 28, 2010. All information, except number of shares, is in Canadian dollars. The information is presented in accordance with Canadian GAAP and is not comparable to the financial information presented in accordance with IFRS. We have not provided a table for reconciliation with generally accepted accounting principles of the United States, as there are no material differences.
| 12 Months Ended
February 28, 2010 |
| Gross oil and gas revenue | 191,745 |
| Net oil and gas revenue | 165,016 |
| Loss for the year | (614,707) |
| Loss per share, basic and diluted | (0.05) |
| Net loss for the year | (614,707) |
| Net loss per share, basic and diluted | (0.05) |
| Weighted-average shares, basic | 11,810,380 |
| Weighted-average shares, diluted | 11,810,380 |
| Number of shares outstanding | 16,447,457 |
| Working capital | 559,483 |
| Resource properties and equipment | 1,110,616 |
| Long-term liabilities | 42,186 |
| Capital stock | 22,414,494 |
| Retained earnings (deficit) | (25,403,181) |
| Total assets | 2,074,329 |
Selected Financial Data for the Six Months Ended June 30, 2014 and 2013
The following table is our summary of financial information for the six months ended June 30, 2014 and 2013. The financial information has been prepared in accordance with IFRS. All information, except number of shares, is in Canadian dollars.
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| 6 Months Ended
June 30, 2014 | 6 Months Ended
June 30, 2013 |
| Gross oil and gas revenue | 7,363,497 | 4,449,530 |
| Net oil and gas revenue | 6,034,480 | 3,752,240 |
| Net income for the period | 1,678,231 | 375,454 |
| Income per share, basic and diluted | 0.03 | 0.01 |
| Weighted-avg shares, basic | 64,849,484 | 54,035,945 |
| Weighted-avg shares, diluted | 66,541,290 | 55,057,091 |
| Number of shares outstanding | 75,053,498 | 54,047,948 |
| Working capital (deficiency) | (1,911,603) | (4,643,327) |
| Resource properties and equipment | 31,986,198 | 24,577,855 |
| Long-term liabilities | 1,371,609 | 495,214 |
| Capital stock | 51,370,717 | 38,861,222 |
| Retained earnings deficit | 22,762,261 | 20,867,253 |
| Total assets | 37,052,954 | 26,470,166 |
Exchange Rate Data
The following table sets forth, for each period indicated, the high, low and average exchange rates for Canadian dollars expressed in United States dollars, provided by the Bank of Canada. The exchange rates set forth in the following table demonstrate trends in exchange rates, but the actual exchange rates used throughout this Form 20-F may vary. The average exchange rate is calculated by using the average on the last day of each month during the relevant period. On September 30, 2014, the noon exchange rate for 1 Canadian dollar expressed in United States dollars as reported by the Bank of Canada, was Cdn$1.00 = US$0.8922.
$1 Canadian dollar equivalent in U.S. dollars
(noon exchange rate) | High
| Low
| Average
|
| Year ended February 28, 2010 | 0.9755 | 0.7692 | 0.9004 |
| Year ended February 28, 2011 | 1.0268 | 0.9278 | 0.9802 |
| Year ended February 29, 2012 | 1.0583 | 0.9430 | 1.0084 |
| Year ended December 31, 2012 | 1.0299 | 0.9599 | 1.0017 |
| Year ended December 31, 2013 | 1.0164 | 0.9348 | 0.9707 |
Six months ended June 30, 2014 | 0.9422 | 0.8888 | 0.9117 |
| April 2014 | 0.9172 | 0.9056 | |
| May 2014 | 0.9228 | 0.9113 | |
| June 2014 | 0.9367 | 0.9143 | |
July 2014 | 0.9404 | 0.9167 | |
August 2014 | 0.9211 | 0.9106 | |
September 2014 | 0.9206 | 0.8922 | |
B. Capitalization and Indebtedness
Our authorized share capital consists of an unlimited number of common shares without par value. As at June 30, 2014 we had 75,053,498 common shares issued and outstanding. As at September 30, 2014 there are 75,368,498 common shares issued and outstanding.
As at June 30, 2014, there were 5,300,000 stock options outstanding to purchase common shares. As at September 30, 2014, there are 5,770,000 stock options outstanding to purchase common shares. The terms and conditions of such stock options are contained in our stock option plan (the “Stock Option Plan”). A summary of some of the relevant parts of the Stock Option Plan are given under the heading “Item 6.B. – Stock Option Plan”.
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As at June 30, 2014, there were 2,053,775 warrants outstanding to purchase common shares. As at September 30, 2014 there are 2,053,775 warrants outstanding to purchase common shares.
The following table sets forth our total indebtedness and capitalization as at June 30, 2014. Investors should read this table in conjunction with our unaudited condensed interim financial statements for the three and six months ended June 30, 2014 and 2013, together with the accompanying notes, and with the other information appearing under the heading “Item 5 – Operating and Financial Review and Prospects”.
| As of June 30, 2014
($) |
| Liabilities | |
| Accounts payable and accrued liabilities | 4,485,503 |
| Bank indebtedness | - |
| Flow-through premium liability | 369,240 |
| Decommissioning obligations | 1,371,609 |
| Total liabilities | 6,226,352 |
| Equity | |
| Capital stock | 51,370,717 |
| Share-based payment reserve | 2,134,495 |
| Warrant reserve | 83,651 |
| (Deficit) | (22,762,261) |
| Total shareholders’ equity | 30,826,602 |
| Total liabilities and shareholders’ equity | 37,052,954 |
We have a demand operating credit facility in the amount of $10,500,000 with Alberta Treasury Branches (“ATB”) under a commitment letter dated September 19, 2013, as amended effective June 23, 2014 (the “Commitment Letter”). The demand operating credit facility is secured by a general security agreement and a floating charge on all of our lands. The demand operating credit facility bears interest at ATB’s prime rate plus 1.75% as well as a standby charge for any undrawn funds. As at June 30, 2014, we had nil drawn from our credit facility.
C. Reasons for the Offer and Use of Proceeds
Not applicable.
D. Risk Factors
Investors should carefully consider the risk factors set out below and consider all other information contained here and in our other public filings before making an investment decision. The risks set out below are not an exhaustive list, nor should they be taken as a complete summary or description of all the risks associated with our business and the oil and natural gas business generally.
Risks Related to the Company’s Business and Industry
Exploration, development and production of oil and gas resources are inherently speculative, and a failure to add new reserves would have a material adverse effect on our financial condition and results of operations.
Without the continual addition of new reserves, any existing reserves we may have at any particular time will decline over time as such existing reserves are depleted and rate of production slows, and therefore our long-term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. Future increase in our reserves and replacement of our existing reserves will depend not only on our ability to explore and develop any properties we may have from time to time, but also on our ability to select and acquire suitable producing properties or prospects. No assurance can be given that we will be able to continue to locate satisfactory properties for acquisition or participation. In addition, if acquisitions or participations are identified, our management may determine that current markets, the terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. Further, future acquisitions or participations that management decides to pursue may involve unprofitable efforts from dry wells and from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. There is no assurance that we will discover or acquire any further commercial quantities of oil and natural gas to replace our existing reserves or increase our reserves in the future.
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Our future oil and gas exploration, development and production operations are hazardous and subject to uncertainty, and these hazards and uncertainties could adversely affect our business, financial condition, results of operations and prospects.
Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards of drilling operations such as fire, explosion, blowouts, cratering, sour gas releases, spills and extreme weather conditions, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or personal injury, and including geological problems such as unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. In particular, we may explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to us. Such risks and hazards may delay or greatly increase the cost of operations, may adversely affect the development of new wells or the production from successful wells and may cause losses that could have a material adverse effect on our business, financial condition, results of operations and prospects.
Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly which could adversely affect our net production revenue and oil and natural gas operations, reserves and our ability to budget for and project the return on acquisitions and on development and exploration projects.
The prices of oil and natural gas prices may be volatile and subject to fluctuation, and any material decline in prices could result in a reduction of our net production revenue and the volumes of our reserves and could negatively impact our ability to budget for and project the return on acquisitions and on development and exploration projects.
Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control. These factors include economic conditions, in the United States and Canada, the actions of the Organization of the Petroleum Exporting Countries (“OPEC”), governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources. The economics of producing from some wells may change as a result of lower prices, which could result in reduced production of oil or gas and a reduction in the volumes of our reserves. We might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in our expected net production revenue and a reduction in our oil and gas acquisition, development and exploration activities.
In addition, any substantial and extended decline in the price of oil and gas would have an adverse effect on the carrying value of our reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on our business, financial condition, results of operations and prospects. In particular, bank borrowings available to us may, in part, be determined by our borrowing base. A sustained material decline in prices from historical average prices could reduce our borrowing base, therefore reducing the bank credit available to us which could require that a portion, or all, of any of our outstanding bank debt be repaid.
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Further, petroleum prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and the demand of these commodities due to the current state of the world economies, OPEC actions and the ongoing credit and liquidity concerns. Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and on development and exploration projects.
If we are unable to generate sufficient funds from our operations and other financing sources, we may not be able to undertake or complete future drilling programs or fund our ongoing activities, which would adversely affect our business, financial condition, results of operations and prospects.
Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times or to fund the substantial capital expenditures that we may incur for the acquisition, exploration, development and production of oil and natural gas reserves in the future, which insufficiency may cause us to seek financing that could be limited, unavailable or available only on unfavorable terms. Failure to obtain such financing on a timely basis could cause us to forfeit our interest in certain properties, miss certain acquisition opportunities and reduce or terminate our operations. Additional debt or equity financing may not be available to meet our financing requirements or, if available, it may not be on terms acceptable to us. The market events and conditions witnessed over the past several years, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility to and reductions in commodity prices. The continued uncertainty in the global economic situation means that we may continue to face restricted access to capital and increased borrowing costs. To the extent that our cash flow from our reserves is insufficient, whether as a result of lower oil and natural gas prices or otherwise, and that external sources of capital are limited, unavailable or available only on unfavourable terms, our ability to make capital investments, maintain existing properties, undertake or complete future drilling programs or to generally carry out our oil and natural gas acquisition, exploration and development activities may be constrained, and, as a result, our business, financial condition, results of operations and cash flow may be materially and adversely affected.
We may not be able to obtain future debt financing, or only under restrictive terms, which may adversely impact our exploration and production activities.
From time to time, we may enter into transactions to acquire assets or the shares of other organizations. These transactions may be financed in whole or in part with debt, which may increase our debt levels above industry standards for oil and natural gas companies of similar size. Depending on future exploration and development plans, we may require additional debt financing that may not be available or, if available, may not be available on favourable terms. Neither our notice of articles nor articles limit the amount of indebtedness that we may incur. The level of our indebtedness from time to time could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.
In addition, the terms of the indebtedness we may incur could include covenants imposing significant restrictions on us, including limitations on our ability to encumber or charge our assets or properties in order to secure any further indebtedness and restrictions on our ability to amalgamate with or merge into any other entity or sell, transfer, lease or otherwise dispose of all or substantially all of our properties or assets, without first repaying the indebtedness in full. These restrictions may affect our ability to operate our business and may limit our ability to take advantage of potential business opportunities as they arise and, in turn, may materially and adversely affect our business, financial condition and results of operations.
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We may not realize anticipated benefits of acquisitions and dispositions, which could adversely affect our business, financial condition, results of operations and prospects.
Achieving the benefits of acquisitions and dispositions of businesses and assets in our ordinary course of business depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner, our ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses with our operations and the timing of dispositions to coincide with an advantageous price. The integration of acquired business may require substantial management effort, time and resources and may divert management's focus from other strategic opportunities and operational matters. Management continually assesses the value and contribution of services provided and assets required to provide such services. In this regard, non-core assets are periodically disposed of, so that we can focus our efforts and resources more efficiently. Depending on the state of the market for such non-core assets at the time of sale, certain of our non-core assets, if disposed of, could be expected to realize less than their carrying value on our financial statements. An inability on our part to realize anticipated benefits of acquisitions and dispositions, whether because of a failure to consolidate functions and integrate operations and procedures in a timely and efficient manner, to combine the acquired businesses with our operations or to dispose of businesses and assets at an opportune time, could adversely affect our business, financial condition, results of operations and prospects.
We depend upon operators of certain of our assets and on joint venture partners, and any failure of an operator or joint venture partner to perform, or any disputes or disagreement with an operator or joint venture partner, could adversely affect our business, financial condition, results of operations and prospects.
We do not operate all of our projects and we own certain of our projects with joint venture partners. For those projects that we do not operate, we have limited ability to exercise influence over the operations of our projects, or the associated costs of operations, that are operated by other companies. Our return on assets operated by others depends upon a number of factors that may be outside of our control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices. In addition, we own certain of our interests through joint venture or similar arrangements. Joint ventures involve risks not otherwise present when exploring and developing properties directly, including, for example, that a joint venture partner may not pay its share of obligations, we may incur liabilities as a result of an action taken by a joint venture partner and that we may be required to devote significant management time to the requirements of the joint venture for which we will not receive a commensurate return. Failure of an operator to perform, or disputes with operators or other participants, may result in delays, litigation or operational impasse. The risks described above or the failure to resolve disagreements could result in significant cost and delay, or adversely affect the ability of the parties to operate and develop the relevant projects, which could adversely affect our business, financial condition, results of operations and prospects.
Our ability to market oil and natural gas depends on our ability to transport our product to market, and restricted access to pipelines, storage and processing facilities may adversely affect our business, financial condition, results of operations and prospects.
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The lack of firm pipeline capacity and the pro-rationing of capacity on the inter-provincial pipeline systems continues to affect the oil and natural gas industry in western Canada, which, along with potential deliverability uncertainties related to the proximity of our reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines and facilities, may limit our ability to produce and market our oil and gas production, and therefore we may receive discounted pricing. There is no guarantee that current pipeline construction projects, including projects to increase rail handling and transportation of oil and other liquid hydrocarbons, presently pending before various regulatory bodies will be approved or will ameliorate conditions. As a result, even if we are able to engage in successful exploration and production activities, we may not be able to effectively market the oil and natural gas that we produce, which could adversely affect our business, financial condition, results of operations and prospects.
Unavailability of equipment and qualified personnel could delay our exploration and production activities which may adversely affect our business, financial condition, results of operations and prospects.
There can be no assurance that sufficient drilling and completion equipment, services and supplies will be available when needed or that qualified personnel will be available. Our oil and gas exploration and development activities are dependent on the availability of drilling and related equipment in the particular areas where such activities will be conducted. Demand for limited equipment or access restrictions may affect the availability of such equipment to us. Similarly, if the demand for, and wage rates of, qualified rig crews rise in the drilling industry, then the oil and gas industry may experience shortages of qualified personnel to operate drilling rigs. Unavailability of equipment and qualified personnel could each delay our exploration and development activities, which could adversely affect our business, financial condition, results of operations and prospects.
Our reserve estimates depend on many assumptions that may prove to be inaccurate and are subject to revision based on production history, and material inaccuracies in the reserve estimates or the underlying assumptions, or revision based on production history, may adversely affect the quantities and present value of our reserves.
There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. Our reserves and associated cash flow information included in this Form 20-F are estimates only. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times may vary. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves will vary from estimates thereof and such variations could be material.
Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas were estimated by experience and analogy to similar producing pools. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.
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Competition in the oil and natural gas industry is intense, and many of our competitors have greater resources than us which can increase competitive pressures and could have an adverse effect on our business, financial condition, results of operations and prospects.
The petroleum industry is competitive in all its phases. We compete with numerous other industry participants in the search for, and the acquisition of, oil and natural gas properties, and without the acquisition of suitable oil and gas properties our ability to increase our reserves in the future may be impaired. In addition, we compete with other industry participants for the sourcing and availability of equipment, raw materials and component parts necessary in petroleum and natural gas exploration and development. As demand for drilling rigs and related equipment and services increases, delays and increased pricing may occur, either of which could result in delays in our planned projects and adversely affect our business. Further, we compete with other industry participants in the distribution and marketing of oil and gas with respect to price, methods, pipeline access and reliability of delivery and availability of imported products, all of which may be affected by factors beyond our control and which could adversely affect the our financial condition and results of operations. Our competitors include oil and natural gas companies that have substantially greater financial and technical, resources, staff and facilities than us, and therefore may be able to take advantage of opportunities not available to us, obtain drilling rigs and related equipment and services that we cannot and secure superior means of distribution and marketing of oil and gas, each of which could have an adverse effect on our business, financial condition, results of operations and prospects.
Our operations are subject to various laws and governmental regulations, including permitting, and the implementation of new regulations or the modification of existing regulations could have an adverse effect on our business, financial condition, results of operations and prospects.
The exploration, production, pricing, marketing and transportation of oil and natural gas are subject to extensive controls and regulations imposed by various levels of government, which may be amended from time to time. Governments may regulate or intervene with respect to exploration and production practices and activities, price, taxes, royalties and the exportation of oil and natural gas. Also, in order to conduct oil and natural gas operations, we will require licenses and permits from various governmental authorities. There can be no assurance that we will be able to obtain all of the licenses and permits that may be required to conduct operations that it may wish to undertake. Governmental regulations may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for natural gas and crude oil and increase our costs, any of which may have an adverse effect on our business, financial condition, results of operations and prospects.
Our operations are subject to various environmental laws and regulation, which require compliance that can be burdensome and expensive.
All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material, the suspension or revocation of necessary licenses and permits, and civil liability for pollution damage. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. No assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on our business, financial condition, results of operations and prospects.
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Legislative and regulatory initiatives related to climate change could have an adverse effect on our operations and on the demand for oil and gas.
Studies over recent years have indicated that emissions of certain gases may be contributing to a warming of the Earth's atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that require reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. There has been much public debate with respect to Canada's and Provincial Governments’ respective strategies with respect to climate change and the control of greenhouse gases. See the discussion under the heading “Item 4.B. Government Regulations – Environmental and Climate Change Regulation”. Any existing or future legislative or regulatory initiatives that restrict or reduce emissions of greenhouse gases could result in increased operating and compliance costs to us and, further, may adversely affect demand for the fossil fuels we produce, including by increasing the cost of combusting fossil fuels and by creating incentives for the use of alternative fuels and energy. Implementation of such initiatives for reducing greenhouse gases could accordingly have an adverse impact on the nature of oil and natural gas operations, including ours. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and the evolving legislative requirements, it is not possible to predict the impact on us and our operations and financial condition.
Changes to the royalty regime may reduce our earnings and adversely affect our financial condition and results of operations.
There can be no assurance that the governments of Alberta, British Columbia or Canada will not adopt a new royalty regime or modify the methodology of royalty calculations that would increase the royalties we pay. See the information regarding royalty rates under the heading “Item 4.B. Government Regulations – Provincial Royalties and Incentives”. An increase of royalty rates would reduce our earnings and make certain of our projects uneconomic.
Fluctuations in foreign currency exchange rates could have an adverse effect on our business and results of operations.
World oil and gas prices are quoted in United States dollars and the price received by Canadian producers, including us, is therefore affected by the Canadian/United States dollar exchange rate, which will fluctuate over time. In recent years, the Canadian dollar has increased materially in value against the United States dollar. Material increases in the value of the Canadian dollar negatively impact our production revenues. Future Canadian/United States dollar exchange rate fluctuations could accordingly impact our cash flows and the future value of our reserves as determined by independent evaluators.
Our future hedging activities may not prove beneficial.
From time to time, we may enter into agreements to receive fixed prices on our oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, we will not benefit from such increases and we may nevertheless be obligated to pay royalties on such higher prices, even though not received by it, after giving effect to such agreements.
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We may incur losses as a result of title deficiencies as title to our oil and natural gas producing properties cannot be guaranteed and may be subject to prior recorded or unrecorded agreements, transfer, claims or other defects.
Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat our claim, and our actual interest in properties may, therefore, vary from our records. The loss of a property, including the loss of our investment, or the loss of the right to produce all or a portion of oil and gas resources under a property could have a material adverse effect on our business, financial condition, results of operations and prospects.
Exploration and development oil and gas properties involve significant risks that cannot always be covered by insurance or contractual protections, and in the event that a significant accident occurs for which we are not fully insured, our business, financial conditions, results of operations and prospects could be adversely affected.
Our involvement in the exploration for and development of oil and natural gas properties may result in us becoming subject to liability for pollution, blow outs, leaks of sour natural gas, property damage, personal injury or other hazards. Although we maintain insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability and may not be sufficient to cover the full extent of such liabilities. In addition, such risks are not, in all circumstances, insurable or, in certain circumstances, we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of any uninsured liabilities would reduce the availability of our funds. The occurrence of a significant event that we are not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on our business, financial condition, results of operations and prospects.
We may be unable to manage our anticipated growth.
We may be subject to growth-related risks including capacity constraints and pressure on our internal systems and controls. Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to expand, train and manage our employee base. Our inability to deal with this growth may have a material adverse effect on our business, financial condition, results of operations and prospects.
We are dependent upon the grant and maintenance of appropriate licenses and leases and if we are unable to meet all obligations necessary to maintain these licenses and leases it could have an adverse effect on our business, financial condition, results of operations and prospects.
Our properties are held in the form of licences and leases and working interests in licences and leases. If we or the holder of a licence or lease fails to meet the specific requirement of such licence or lease, such licence or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each licence or lease will be met. The termination or expiration of our licences or leases or the working interests relating to a licence or lease may have a material adverse effect on our business, financial condition, results of operations and prospects.
Seasonal and unexpected weather patterns may lead to a decrease in exploration and production activity which would adversely impact our operations.
The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Also, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Seasonal factors and unexpected weather patterns may lead to declines in our exploration and production activity during certain parts of the year, which would adversely impact our operations.
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We may be exposed to third-party credit risk through certain of our business arrangements, and non-payments or defaults by these third parties could have an adverse effect on our financial condition and results of operations.
We may be exposed to third party credit risk through our contractual arrangements with our current or future joint venture partners, marketers of our oil and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to us, such failures may have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in an ongoing capital program, potentially delaying the program and the results of such program until we find a suitable, alternative partner.
Our business may suffer if we lose key management personnel which could result in us having to cease operations.
Our success depends in large measure on certain key management personnel. Competition for qualified personnel in the oil and natural gas industry is intense, and there can be no assurance that we will be able to attract, retain and replace all personnel necessary for the development and operation of our business. We do not have any key person insurance. The loss of the services of key management personnel may have a material adverse effect on our business, financial condition, results of operations and prospects, and could ultimately cause us to cease operations.
Reassessment of our income tax returns may prove to be detrimental to our business and financial condition.
We file all required income tax returns and believe they are in full compliance with the provisions of the Income Tax Act (Canada) and all other applicable provincial tax legislation. However, such returns are subject to reassessment by the applicable taxation authority. In the event of a successful reassessment, whether by re-characterization of exploration and development expenditures or otherwise, such reassessment may have an impact on current and future taxes payable and could be detrimental to our business and financial condition.
Our operations are subject to various litigation risks that could impact our financial condition and results of operations.
In the normal course of our operations, we may become involved in, named as a party to, or be the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions, relating to personal injuries, property damage, property taxes, land rights, the environment and contract disputes. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to us and as a result, could have a material adverse effect on our assets, liabilities, business, financial condition and results of operations. Even if we prevail in any such legal proceeding, the proceedings could be costly and time-consuming and may divert the attention of management and key personnel from our business operations, which could adversely affect our financial condition.
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Conflicts of interest may arise among our directors and officers as a result of their involvement with other oil and gas endeavors leading to the potential loss of personnel which could adversely affect our business, financial condition, results of operations and prospects.
There are potential conflicts of interest to which some of our directors and officers will be subject in connection with our operations. Some of our directors and officers are engaged and will continue to be engaged in the search of oil and gas interests on their own behalf and on behalf of other corporations. Frank Borowicz, one of our directors, is also a director of West Cirque Resources Ltd. Bruce McIntyre, one of our directors, is also a director of New Zealand Energy Corp. Gregg Vernon, one of our directors, is also a director of Petrodorado Energy Ltd. Such associations may give rise to conflicts of interest from time to time that can be resolved only through our directors and officers exercising such judgment as are consistent with duties to their other business interests and ours. Such conflicts pose the risk that we may enter into a transaction on terms which place us in a worse position than if no conflict existed.
Conflicts of interest, if any, that arise will be subject to and be governed by procedures prescribed by the Business Corporations Act (British Columbia) (the “BCBCA”) which requires a director or officer of a corporation who is a party to or is a director or an officer of or has a material interest in any person who is a party to a material contract or proposed material contract with us, to disclose his interest and to refrain from voting on any matter in respect of such contract unless otherwise permitted under the BCBCA.
Our properties and assets may be subject to aboriginal title and rights claims and if such a claim is successfully made in respect of our property or assets, it could adversely affect our business, financial condition, results of operations and prospects.
Aboriginal peoples have claimed aboriginal title and rights to portions of western Canada. We are not aware that any claims have been made in respect of our properties and assets; however, if a claim arose and was successful, our ability to develop such property and assets could be impaired, or we may lose the such property and assets altogether, each of which could have an adverse effect on our business, financial condition, results of operations and prospects.
Restrictive regulation may limit our ability to market oil and natural gas and could adversely affect our business, financial condition, results of operations and prospects
Restrictive regulation implemented in the future could affect our ability to market oil and natural gas.
The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to the markets, the value of refined products, the supply/demand balance, and other contractual terms. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the “NEB”). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires a public hearing and the approval of the Governor in Council.
The price of natural gas is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day), must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires a public hearing and the approval of the Governor in Council.
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The governments of Alberta and British Columbia also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements, and market considerations.
Subject to certain limitations under the North American Free Trade Agreement among the governments of Canada, U.S., and Mexico, effective on January 1, 1994 (“NAFTA”), Canada may impose export restrictions on oil and natural gas to the U.S.
Any inability to market our oil and natural gas due to restrictive regulations could adversely impact our ability to generate revenues from our petroleum assets, business, financial condition, result from operations and prospects.
Recently adopted accounting pronouncements may impact our future results and financial position.
Certain pronouncements have been issued by the IASB that are mandatory for accounting periods after June 30, 2014 or later periods. The new standards, amendments and interpretations, which are set forth under the heading “Item 5. Operating and Financial Review and Prospects – Future Accounting Pronouncements”, have not been early adopted in our financial statements. We cannot predict what impact, if any, the new guidance will have on our future results and financial position.
Risks Relating to the Common Shares
We have never paid dividends and do not expect to do so in the foreseeable future.
We do not currently pay any dividends on our outstanding common shares. Payments of dividends in the future will be dependent on, among other things, our cash flow, results of operations and financial condition, the need for funds to finance ongoing operations and other considerations, as our board of directors (“Board of Directors”) considers relevant.
Future sales or issuances of equity securities could decrease the value of the common shares, dilute investors' voting power and reduce our earnings per share.
Our constating documents permit it to issue an unlimited number of common shares. Our goal is to continually increase our oil and gas reserves. To achieve that goal, we will require substantial amounts of capital in excess of funds from operations. We may choose to raise the required capital through the issuance of additional common shares or other securities convertible, exercisable or exchangeable for common shares. We may also make future acquisitions through the issuance of shares. We cannot predict the size of future issuances of equity securities or the size and terms of future issuances of debt instruments or other securities convertible, exercisable or exchangeable into common shares or the effect, if any, that future issuances and sales of our securities will have on the market price of the common shares. Any transaction involving the issuance of previously authorized but unissued shares, or securities convertible, exercisable or exchangeable into common shares, including exercises of presently outstanding options, would result in dilution to holders of common shares.
Re-sales of substantial amounts of the common shares, or the availability of such securities for re-sale, could adversely affect the prevailing market price for the common shares and dilute our earnings per share. A decline in the market price of the common shares could impair our ability to raise additional capital through the sale of securities should we have the desire to do so.
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The market price of our common shares may be volatile and your investment in our common shares could suffer a decline in value.
The market price of common shares may fluctuate due to a variety of factors relative to our business, including announcements of new developments, fluctuations in our operating results, sales of the common shares in the marketplace, failure to meet analysts’ expectations, any public announcements made in regards to us, the impact of various tax laws or rates and general market conditions or the worldwide economy. In recent years, stock markets have experience significant price fluctuations, which have been unrelated to the operating performance of the affected companies. There can be no assurance that the market price of our common shares will not experience significant fluctuations in the future, including fluctuations that are unrelated to our performance, and volatility may affect your ability to sell our common shares at an advantageous price.
Since our officers and directors are located in Canada, it may be difficult to enforce any U.S. judgment for claims brought against us or our officers and directors.
We are organized under the laws of the Province of British Columbia, Canada, our assets are located in Canada and many of our officers and directors are residents of Canada. While a cross border treaty exists between the U.S. and Canada relating to the enforcement of foreign judgments, the process of such is cumbersome and in some cases has prevented the enforcement of judgments. As a result, while actions may be brought in Canada, it may be impossible to affect service of process within the U.S. on our officers and directors or to enforce against these persons any judgments in civil and commercial matters, including judgments under U.S. federal securities laws. In addition, a Canadian court may not permit an original action in Canada or enforce in Canada a judgment of a U.S. court based on civil liability provisions of U.S. federal securities laws.
ITEM 4. INFORMATION ON THE COMPANY
A. History and Development of the Company General
Our head office is located at 2000, 1055 West Hastings Street, Vancouver, British Columbia, Canada V6E 2E9 and our registered office is located at 2900-550 Burrard Street, Vancouver, British Columbia, Canada V6C 0A3. Our telephone number is (604) 685-9255.
We were originally incorporated as “Pan-Cana Development Corp.” on March 6, 1978 under the Company Act (British Columbia) and changed our name to Hemisphere Development Corp. on May 18, 1978. We are currently organized pursuant to the BCBCA, which replaced the Company Act (British Columbia) in 2004. We are a corporation domiciled in British Columbia, Canada.
On December 10, 1999, the shareholders approved a consolidation of our issued and outstanding shares on the basis of one new share for every five old shares and our name was changed to “Northern Hemisphere Development Corp.” effective January 14, 2000, pursuant to the filing of the requisite documentation with the Registrar of companies for the Province of British Columbia.
On April 14, 2009, the shareholders approved a consolidation of our issued and outstanding shares on the basis of one new share for every five old shares and our name was changed to “Hemisphere Energy Corporation” effective April 24, 2009, pursuant to the filing of the requisite documentation with the Registrar of companies for the Province of British Columbia.
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On March 12, 2014, our Board of Directors approved and adopted an advance notice policy (the “Advance Notice Policy”) which was approved by the shareholders on June 6, 2014. The purpose of the Advance Notice Policy is to provide shareholders, the Board of Directors and management with a clear framework for nominating directors. The Advance Notice Policy fixes a deadline by which holders of record of our common shares must submit director nominations to us prior to any annual general or special meeting of shareholders and sets forth the information that a shareholder must include in the notice to the Company for the notice to be in proper written form in order for any director nominee to be eligible for election at any annual or special meeting of shareholders. The complete copy of the Advance Notice Policy is included as an exhibit to this Form 20-F.
Our common shares are publicly traded on the TSX Venture Exchange (the “TSX-V”) as a Tier 1 issuer under the symbol “HME”.
General Development of the Business
We are a junior exploration and production, oil and gas company focused on developing core areas that provide low to medium risk drilling opportunities to increase production, reserves and cash flow. We have production in the Jenner and Atlee Buffalo areas of southeast Alberta and the Trutch area of northeast British Columbia. Our continued growth plan is through drilling existing prospects and executing strategic acquisitions and farm-ins.
In the first six months of 2014, we successfully drilled and commenced production of three horizontal development wells (two in Jenner and one in Atlee Buffalo) and commenced our summer drilling program of five development wells in the Atlee Buffalo area. On July 23, 2014, we announced that we closed an acquisition for additional petroleum and natural gas leases in the Atlee Buffalo area of southeast Alberta. The property included an 85% working interest in 1.75 sections (1,120 acres) of land adjacent to our existing land base for total consideration of $510,000.
On May 14, 2014, we closed a bought-deal equity financing consisting of 13,333,500 common shares at a price of $0.75 per common share for aggregate gross proceeds of $10,000,125. In conjunction with the closing of the bought-deal equity financing, we paid $700,009 in finders’ fees. We will use the net proceeds from the offering to accelerate our capital program which is focused on continuing the development of our Atlee Buffalo and Jenner properties, as well as for general corporate purposes and reducing our current indebtedness under our credit facility.
Three Year History of the Company
Fiscal year ended February 29, 2012
On March 25, 2011, we closed an acquisition in Jenner which included approximately 25 bopd, associated facilities and infrastructure, 100% working interest in 2,600 acres of land, and a 3D seismic survey that covered a portion of the acquired lands for a total cost of $1.1 million.
On May 5, 2011, we closed a non-brokered private placement resulting in the issuance of 2.6 million common shares for gross proceeds of $1.0 million and 1.4 million common shares on a flow-through basis for gross proceeds of $621,000.
On July 21, 2011, we announced initial production results from the first horizontal well of our drilling program targeting oil in the Glauconitic formation in Jenner. During the first five days of production, the stabilized production rate for the last 72 hours was 230 bopd.
On November 10, 2011, we closed a non-brokered private placement resulting in the issuance of 2.2 million flow-through shares for gross proceeds of $1.4 million. We also closed an acquisition in Trutch increasing our production and working interests ranging 30% to 100% for $250,000 cash and 100,000 common shares valued at $0.35 each.
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On November 15, 2011, we announced we completed and equipped the second horizontal oil well of our drilling program targeting the Glauconitic formation in Jenner. The well tested an average 156 bopd over a 72 hour period.
On January 10, 2012, we announced we completed and equipped the third horizontal well targeting oil in the Glauconitic formation on our Jenner property and provided initial production results. During twelve days of production, the average production rate over the last 72 hours was approximately 207 bopd.
Also on January 10, 2012, we entered a farm-in agreement to earn land in Jenner whereby we committed to drilling one horizontal well with the option of drilling a second well to earn additional land.
On January 27, 2012, we closed a strategic acquisition in Jenner producing approximately 98 bopd, additional oil processing facilities, 8.5 net sections (5,380 acres) of land and 3D seismic coverage for a total cost of $6.0 million. In January, we closed this acquisition in conjunction with a brokered private placement resulting in the issuance of 12.3 million common shares for gross proceeds of $8.6 million.
Ten months ended December 31, 2012
On June 14, 2012, we entered into a seismic option and farm-in agreement in the Jenner area which included initial obligations to acquire 3D seismic data and the option to drill a test well with the potential to acquire additional 3D seismic and drill additional wells to earn a maximum of 6.5 sections.
On November 16, 2012, we filed a Notice of Change in Year-End under NI 51-102 Continuous Disclosure Obligations (“NI 51-102”) changing our fiscal year-end from February 28 to December 31 to better align financial reporting with the calendar year and industry peers. The transition year from March 1, 2012 to December 31, 2012 included reporting the nine months ended November 30, 2012, followed by the ten months ended December 31, 2012.
On December 20, 2012, we closed the first tranche of a non-brokered private placement resulting in the issuance of 1.8 million common shares for gross proceeds of $1.2 million.
During the year, we successfully drilled eight oil wells (7 horizontal and 1 vertical). We also expanded our landholdings through Crown land sales acquiring 2.25 sections (1,440 acres) in southeast Alberta. Existing facilities at Jenner were upgraded adding a heated free-water-knockout separator for greater fluid handling capacity and reduction of operating costs.
Fiscal year ended December 31, 2013
On January 25, 2013, we closed the second and final tranche of a non-brokered private placement resulting in the issuance of 86,900 common shares for gross proceeds of $56,485.
On April 24, 2013, we increased our credit facility from $5.5 million to $9.5 million (the “Credit Facility”) as a result of reserve additions and production increases from our 2012 drilling activity.
On May 14, 2013, we successfully graduated to Tier 1 on the TSX-V. Tier 1 is the premier tier and is reserved for the most advanced issuers with the most significant financial resources on the TSX-V.
On October 16, 2013, we entered into a formal letter of intent with an intermediate Canadian producer to purchase certain oil and gas assets in the Atlee Buffalo area of southeast Alberta. This acquisition included 100% working interest in 8.25 sections of contiguous land spanning two large Glauconitic oil pools at a cost of $3.35 million and an effective date of June 1, 2013. This acquisition subsequently closed on November 18, 2013 and was funded by the Credit Facility, which was increased to $10.5 million upon the closing.
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On November 21, 2013, we announced a Bought Deal Equity Financing (the “Financing”) with a syndicate of underwriters for aggregate gross proceeds of $4.3 million to accelerate our capital program focused on Jenner and the newly acquired Atlee Buffalo property. The Financing closed on December 10, 2013.
During the year, we successfully drilled two horizontal oil wells in north Jenner. We have also expanded our landholdings through Crown land sales acquiring 13.75 sections (8,800 acres) in southeast Alberta. We upgraded our main oil battery by increasing our water handling capacity and debottlenecking our oil processing system as a means to optimize fluid rates at a number of existing wells and increase base oil production. Additionally, we added a gas sweetening tower which removes H2S (hydrogen sulfide) from the gas stream allowing us to meet third party pipeline specifications and send solution gas to sales.
Financings
In addition to production revenue, we have financed operations through funds from loans, private placements of common shares, bought deal equity financings of common shares, common shares issued for property and shares issued upon exercise of stock options and share purchase warrants. See the table and accompanying notes under the heading “Item 10.A. Share Capital – Common Shares” which summarizes our issuances of common shares for the past three fiscal years and from January 1 to September 30, 2014.
Capital Expenditures
We are focused on developing core areas that provide low to medium risk drilling opportunities to increase production, reserves and cash flow. Our continued growth plan is through drilling existing prospects and executing strategic acquisitions and farm-ins.
Past Capital Expenditures
The following table sets forth our principal capital expenditures and divestitures since the beginning of our last three financial years to June 30, 2014.
| Fiscal year ended or period | Cash flows used for equipment and resource properties |
January 1, 2014 to June 30, 2014 | 7,882,507(2) |
| December 31, 2013 | 9,973,313(3) |
| December 31, 2012(1) | 11,767,518(4) |
| February 29, 2012 | 13,075,574(5) |
Notes:
| | (1) | Due to our fiscal year-end change, this fiscal year represents a ten month period. |
| | (2) | $23,584 of these funds was spent on the purchase of corporate assets and equipment and $7,858,924 was spent on our resource properties. For a breakdown on the resource property expenditures, see Notes 7 and 8 of our condensed interim financial statement for the three and six months ended June 30, 2014 and June 30, 2013 included as an exhibit to this Form 20-F. |
| | (3) | All of these funds were spent on our resource properties. For a breakdown on the resource property expenditures, see Notes 7 and 8 of our audited financial statements for the twelve months ended December 31, 2013 and ten months ended December 31, 2012 included as an exhibit to this Form 20-F. |
| | (4) | All of these funds were spent on our resource properties. For a breakdown on the resource property expenditures, see Notes 7 and 8 of our audited financial statements for the twelve months ended December 31, 2013 and ten months ended December 31, 2012 included as an exhibit to this Form 20-F. |
| | (5) | $10,200 of these funds was spent on the purchase of corporate assets and equipment; and $13,065,374 was spent on our resource properties. |
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During the period from January 1, 2014 to June 30, 2014, we drilled and commenced production of three horizontal development wells, two at the Jenner property and one at the Atlee Buffalo property, completed production improvements to an Atlee Buffalo well and commenced our five well drilling program in the Atlee Buffalo area. We also completed rental equipment buyouts and equipment upgrade at the main production facility in Jenner. The equipment upgrades included costs associated with a solution gas compressor that was completed and put online in the second quarter of 2014. We also completed a workover on a shut-in injection well in order to bring it back online and improve its injection capacity to allow it to dispose of more fluids in the future. Finally, we completed a small acquisition in the surrounding Jenner area which resulted in the acquisition of 1.75 sections (1,120 acres).
During the twelve months ended December 31, 2013, we drilled two new wells in north Jenner and built and upgraded infrastructure in the Jenner area. The infrastructure included pipelines for new well and upgrades to our main Jenner battery. The upgrades included an increase in fluid handling capacity and the installation of a solution gas sweetening tower, which allows us to sell our gas. We also completed a property acquisition of oil and gas assets in the Atlee Buffalo area of southeast Alberta from an intermediate Canadian producer effective June 1, 2013.
During the ten months ended December 31, 2012, we drilled and completed eight wells in the Jenner area and built infrastructure at our main Jenner battery. The infrastructure included pipelines for new wells and upgrading our main production facility with a new water disposal pump and heated free-water-knockout separator to allow for greater fluid handling capacity.
During the fiscal year ended February 29, 2012, we completed two significant land acquisitions in the Jenner area. The first acquisition was completed in March 2011 which included five sections of land and produced approximately 25 barrels of oil per day. The second acquisition was completed in January 2012 which consisted of 8.5 net sections of land and operated oil production of approximately 100 bopd, as well as production facilities. During the fiscal year ended February 29, 2012, we also drilled and completed three horizontal wells and one vertical exploration well in the Jenner area.
The following table sets forth additions to property and equipment and exploration and evaluation assets.
| From January 1,
2014 to June 30, 2014
($) | 12 Months
Ended
December 31,
2013
($) | 10 Months
Ended
December 31,
2012
($) | 12 Months
Ended February
29, 2012
($)
|
| Land and lease | 105,252 | 117,274 | 19,648 | 30,143 |
| Geological and geophysical | 187,315 | 368,116 | 251,605 | 203,987 |
| Drilling and completions | 5,554,894 | 2,476,925 | 6,946,744 | 3,695,782 |
| Investment in facilities | 1,936,724 | 3,914,804 | 4,478,757 | 2,429,092 |
| Development capital | 7,784,185 | 6,877,119 | 11,696,754 | 6,359,004 |
| | | | | |
| Property acquisitions | 124,739 | 3,092,055 | 191,644 | 7,448,832 |
Fixed assets | 23,584 | - | - | - |
| Dispositions | (50,000) | - | - | - |
| Total capital expenditures | 7,882,507 | 9,969,174 | 11,888,398 | 13,807,836 |
Reconciliation
The following table provides reconciliation from total capital expenditures to the cash flows used for equipment and resource properties from January 1, 2014 to June 30, 2014 and for the twelve months ended December 31, 2013, ten months ended December 31, 2012 and twelve months ended February 29, 2012.
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| From January
1, 2014 to
June 30, 2014
($) | 12 Months
Ended
December 31,
2013
($) | 10 Months
Ended
December 31,
2012
($) | 12 Months
Ended
February 29,
2012
($) |
| Total capital expenditures | 7,882,507 | 9,969,174 | 11,888,398 | 13,807,836 |
| Exploration and evaluation expense(1) | - | - | (120,882) | 10,198 |
| Accumulated depletion associated with disposition(2) | - | 4,139 | - | - |
| Change in non-cash working capital(3) | - | - | - | (707,460) |
| Share issuance for property(4) | - | - | - | (35,000) |
| Cash flows used for equipment and resource properties | 7,882,507 | 9,973,313 | 11,767,518 | 13,075,574 |
Notes:
| | (1) | In the past, we included exploration and evaluation expenses in our capital expenditures schedule, which created a variance when comparing to the Statement of Cash Flows. We revised this reporting effective December 31, 2013. |
| | (2) | This was an immaterial amount which was not segregated from accumulated depreciation in the Statement of Cash Flows. |
| | (3) | In the past, we presented all of the changes in non-cash working capital in one amount under operating activities in the Statement of Cash Flows, which created a variance when comparing to the capital expenditures schedule. We revised this reporting effective December 31, 2012. |
| | (4) | This was an immaterial amount which was not factored in the Statement of Cash Flows. |
Present capital expenditures
In June 2014, we commenced our summer drilling program of five development wells in the Atlee Buffalo area of southeast Alberta. Two of the five wells from the drilling program have been on production for over 30 days and are producing approximately 100 boe/d (93% oil) and 65 boe/d (88% oil), respectively. The remaining three wells were drilled from a second surface pad location where drilling operations finished in mid-July. We are also in the process of placing four wells that were previously shut-in, back on production. On July 23, 2014, we announced that we closed an acquisition for additional petroleum and natural gas leases in the Atlee Buffalo area of southeast Alberta. The property included an 85% working interest in 1.75 sections (1,120 acres) of land adjacent to our existing land base for total consideration of $510,000.
These capital expenditures will be funded by our credit facility, as well as a bought-deal equity financing which closed on May 14, 2014 for aggregate gross proceeds of $10,000,125.
B. Business Overview
General
We are a junior exploration and production, oil and gas company focused on developing core areas that provide low to medium risk drilling opportunities to increase production, reserves and cash flow. We have production in the Jenner and Atlee Buffalo areas of southeast Alberta and the Trutch area of northeast British Columbia. Our continued growth plan is through drilling existing prospects and executing strategic acquisitions and farm-ins.
Operations and Principal Activities
Our operations and principal activities consist of the exploration for and production of oil and natural gas.
Daily Production
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The following table sets forth our average daily production for the three months ended December 31, 2013, one month ended December 31, 2012, twelve months ended December 31, 2013 and ten months ended December 31, 2012.
| 3 Months
Ended
December 31,
2013 | 1 Month
Ended
December
31, 2012 | 12 Months
Ended
December 31,
2013 | 10 Months Ended
December 31,
2012
|
| Oil (bbl/d) | 443 | 405 | 381 | 378 |
| Natural gas (Mcf/d) | 746 | 139 | 474 | 161 |
| NGL (bbl/d) | 2 | 2 | 3 | 3 |
| Total (boe/d) | 569 | 430 | 463 | 408 |
| Oil and NGL weighting | 78% | 95% | 83% | 93% |
The increases in oil production for the three and twelve months ended December 31, 2013 can be attributed to the drilling of two new oil wells in the Jenner area in addition to the production acquired from the Atlee Buffalo acquisition in the fourth quarter of 2013. Gas production increased in 2013 as a result of gas volumes from the new Jenner wells, the Atlee Buffalo acquisition and the installation of a gas sweetening tower at our main production facility in Jenner, Alberta.
Summary of Operations Highlights
The following table sets forth our production, average realized prices and revenue for each of the last three fiscal years.
| 12 Months Ended
December 31, 2013 | 10 Months Ended
December 31, 2012 | 12 Months Ended
February 29, 2012 |
| Production | | | |
| Oil (bbl/d) | 381 | 378 | 144 |
| Natural gas (Mcf/d) | 474 | 161 | 246 |
| NGL (bbl/d) | 3 | 3 | 3 |
| Total (boe/d) | 463 | 408 | 188 |
| | | | |
| Average realized prices | | | |
| Crude oil ($/bbl) | 71.19 | 66.76 | 80.08 |
| Natural gas ($/Mcf) | 3.45 | 2.07 | 3.28 |
| NGL ($/bbl) | 68.60 | 60.87 | 67.49 |
| Combined ($/boe) | 62.55 | 63.15 | 66.71 |
| | | | |
| Revenue | | | |
| Oil | 9,903,388 | 7,715,127 | 4,218,120 |
| Natural gas | 596,881 | 102,009 | 294,917 |
| NGL | 72,929 | 58,587 | 77,571 |
| Total | 10,573,199 | 7,875,723 | 4,590,608 |
Marketing and Customers
We market oil and natural gas production from our properties. We sell oil and natural gas to purchasers at market prices. Some of the our natural gas contracts have terms of greater than twelve months and all of our oil contracts have terms of twelve months or less. We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. The market for our oil and natural gas production is well-established. We have no export sales.
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Commodity Price Environment
Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The market for oil and natural gas is beyond our control and prices are difficult to predict. Please see the discussion under the heading “Item 5.D. Trends.”
Seasonality
The exploration for and development of oil and natural gas reserves is dependent on access to areas where production is to be conducted. We have properties in Alberta and British Columbia which are accessible by heavy equipment in winter only when the ground is frozen, typically between December to early April. For this reason drilling and pipeline construction ceases over the remainder of the year, limiting growth to winter only. Production operations continue year round in these areas once production is established. Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances.
In addition, the demand for, and the price of, natural gas increases during the colder winter months and decreases during the warmer summer months. Pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Crude oil and the demand for heating oil are also impacted by seasonal factors, with generally higher prices in the winter. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations. Extreme cold weather may result in sharp increases in the price paid to producers for their production of natural gas.
Human Resources
As at December 31, 2013, we had six full-time head office employees and one full-time field employee. Additionally, we had one full-time consultant, five part-time consultants and one full-time field contractor.
Competition
The oil and gas industry is competitive in all its phases. We compete with numerous other participants in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas. Our competitors include resource companies that have greater financial resources, staff and facilities than us. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery. We believe that our competitive position is equivalent to that of other oil and gas issuers of similar size and at a similar stage of development. See the information under the heading “Item 3.D. Risk Factors – Competition in the oil and natural gas industry is intense, and many of our competitors have greater resources than us which can increase competitive pressures and could have an adverse effect on our business, financial condition, results of operations and prospects”.
Specialized Skill and Knowledge
We rely on specialized skills and knowledge to gather, interpret and process geophysical data, operate production facilities and numerous additional activities required to produce oil and natural gas. We have employed a strategy of contracting consultants and other service providers to supplement the skills and knowledge of our permanent staff in order to provide the specialized skills and knowledge to undertake our oil and natural gas operations effectively.
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Government Regulations
Provincial Royalties and Incentives
General
Other than relatively small amounts held by private parties and First Nations, natural resources in Canada are owned by each Province respectively. As such, royalties fall primarily under provincial jurisdiction. Provincial royalty regimes are a significant factor in the profitability of crude oil, natural gas liquids, sulphur, and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties.
Provincial Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery, and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are, from time to time, carved out of the working interest owner’s interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests.
Occasionally, the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays, and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Generally, royalty holidays and reductions reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and increase the net income and funds from operations of such producers.
Alberta
In Alberta, producers of oil and natural gas from Crown lands are required to pay annual rental payments, currently at a rate of $3.50 per ha, and make monthly royalty payments in respect of oil and natural gas produced.
Under the current “Alberta Royalty Framework” (“ARF”), royalty rates for oil and natural gas are set by a single sliding rate formula which is applied monthly using separate variables to account for production rates and market prices. The maximum royalty payable under the ARF for oil is 40%, and the maximum royalty payable for natural gas is 36%. The Alberta government also levies royalties on volumes of propane, butane, pentanes plus, bitumen and sulphur produced from Crown lands. A five year program of transitional royalty rates with the intent of promoting new drilling ended effective December 31, 2013, and as of January 1, 2014, all producers operating under transitional royalty rates became subject to the ARF rates described above.
There are several incentive programs currently in effect to stimulate oil and gas investment in Alberta. The Natural Gas Deep Drilling Program provides royalty incentives for deep natural gas wells. A new-well incentive program applies to wells beginning production of conventional oil and natural gas and provides for a maximum 5% royalty rate for the first 12 months of production, up to a maximum of 50,000 barrels or 500 MMcf of natural gas. Similar 5% royalty rates are applicable to horizontal gas wells, coal bed methane wells and shale gas wells. In addition to the foregoing, on May 27, 2010, the Government of Alberta announced a number of new initiatives intended to accelerate technological development and facilitate the development of unconventional resources (the “Emerging Resource and Technologies Initiative”). The Emerging Resource and Technologies Initiative will be reviewed in 2014, and the Government of Alberta has committed to providing industry with three years notice at that time if it decides to discontinue the program.
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Producers of oil and natural gas from freehold lands in Alberta are required to pay a freehold mineral tax levied by the Government of Alberta on the value of oil and natural gas production from non-Crown lands. The freehold mineral tax is levied on an annual basis on calendar year production using a formula that takes into consideration, among other things, the volume of monthly production, a specified rate of tax for both oil and gas and the percentages that the owners hold in the title.
British Columbia
Producers of oil and natural gas from Crown lands in British Columbia are required to pay annual rental payments with respect to the Crown leases (currently at a rate of $7.50 per ha), and make monthly payments in respect of royalties and freehold production taxes due in respect of oil and gas produced from Crown and freehold lands.
The amount payable as a royalty in British Columbia in respect of oil depends on the type of oil, the value of the oil, the quantity of oil produced in a month, and the vintage of the oil. Generally, the vintage of oil is based on the determination of whether the oil is produced from a pool discovered before October 31, 1975 (“old oil”), between October 31, 1975, and June 1, 1998 (“new oil”), or after June 1, 1998 (“third-tier oil”). The royalty rates are calculated in three stages, which take into account the vintage of the oil, if the oil produced has already been sold and any royalty exempt value applicable. Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production or 11,450 m3 produced, whichever comes first; and the royalties for third-tier oil are the lowest reflecting the higher costs of exploration and extraction that the producers would incur.
The royalty payable on natural gas produced from British Columbia Crown lands is determined by a sliding scale based on a reference price, which is the greater of the average net price obtained by the producer, and a prescribed minimum price. For non-conservation gas (not produced in association with oil), the royalty rate depends on the date of acquisition of the oil and natural gas tenure rights and the spud date of the well and may also be impacted by the select price, a parameter used in the royalty rate formula to account for inflation. Royalty rates are fixed for certain classes of non-conservation gas when the reference price is below the select price. Conservation gas is subject to a lower royalty rate than nonconservation gas as an incentive for the production and marketing of natural gas, which might otherwise have been flared.
The Government of British Columbia has several royalty credit and royalty reduction programs intended to increase the competitiveness of low productivity natural gas wells, including the Deep Royalty Credit, the Deep Re-Entry Royalty Credit Program, the Deep Discovery Royalty Credit Program, the Coalbed Gas Royalty Reduction and Credit Program, the Marginal Royalty Reduction Program, the Ultra-Marginal Royalty Reduction Program, and the Net Profit Royalty Reduction Program.
Oil produced from an oil well that is located on either Crown or freehold land and completed in a new pool discovered subsequent to June 30, 1974 may also be exempt from the payment of a royalty for the first 36 months of production or 11,450 m3 of production, whichever occurs first.
The Government of British Columbia also maintains an Infrastructure Royalty Credit Program which provides royalty credits for up to 50% of the lesser of the estimated completion cost and the completion cost of certain approved road construction or pipeline infrastructure projects intended to improve, or make possible, the access to new and underdeveloped oil and gas areas.
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The Petroleum and Natural Gas Royalty and Freehold Production Tax Regulation has been amended effective April 1, 2013 to provide for a 3% minimum royalty on affected wells with deep well/deep reentry credits. The 3% minimum royalty applies to deep wells when the net royalty payable would otherwise be zero for a production month.
Producers of oil and natural gas from freehold lands in British Columbia are required to pay monthly freehold production taxes to the Provincial Government. For oil, the level of the freehold production tax is based on the volume of monthly production. For natural gas, the freehold production tax is determined using a sliding scale formula based on the reference price similar to that applied to natural gas production on Crown land, and depends on whether the natural gas is conservation gas or non-conservation gas.
Land Tenure
Crude oil and natural gas located in the western provinces is owned predominantly by the respective Provincial Governments. Provincial Governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms, and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.
Each of the Governments of Alberta and British Columbia has implemented legislation providing for the reversion to the Crown of mineral rights of deep, non-productive geological formations at the conclusion of the primary term of a lease or license. On March 29, 2007, British Columbia’s policy of deep rights reversion was expanded for new leases to provide for the reversion of both shallow and deep formations that cannot be shown to be capable of production at the end of their primary term.
In Alberta, for leases and licenses issued subsequent to January 1, 2009, shallow rights reversion is applied at the conclusion of the primary term of the lease or license. Although Alberta Energy had previously announced that shallow rights reversions would be implemented for leases and licences that had been granted prior to January 1, 2009 by the service of reversion notices at the end of their primary terms, in April 2013, it communicated to industry that it was deferring the service of such notices indefinitely.
Environmental and Climate Change Regulation
The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation, which may be amended from time to time. Such legislation provides for restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material, the suspension or revocation of necessary licenses and permits, and civil liability for pollution damage.
Alberta
Environmental legislation in Alberta is consolidated in the Environmental Protection and Enhancement Act (Alberta) (the “EPEA”) and the Oil and Gas Conservation Act (Alberta) (the “OGCA”). The EPEA and OGCA impose environmental standards, reporting and monitoring obligations, and penalties for non-compliance.
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The Province of Alberta has created a single regulator for upstream oil and gas, oil sands and coal development activity, the Alberta Energy Regulator (the “AER”) assuming the functions of multiple regulatory bodies. The objective is enhanced regulatory regime that is efficient, attractive to business and investors, and effective in supporting public safety, environmental management and resource conservation while respecting the rights of landowners. On June 17, 2013, the AER assumed the functions and responsibilities of the former Energy Resources Conservation Board, including those found under the Oil and Gas Conservation Act (“ABOGCA”). On November 30, 2013, the AER assumed the energy related functions and responsibilities of Alberta Environment and Sustainable Resource Development (“AESRD”) in respect of the disposition and management of public lands under the Public Lands Act. On March 29, 2014, the AER is expected to assume the energy related functions and responsibilities of AESRD in the areas of environment and water under the Environmental Protection and Enhancement Act and the Water Act, respectively. The AER’s responsibilities exclude the functions of the Alberta Utilities Commission and the Surface Rights Board, as well as Alberta Energy’s responsibility for mineral tenure. The restructuring of the agencies implementing regulation has not been accompanied by substantive amendments to the underlying Provincial Government policy or legislation.
In December, 2008, the Government of Alberta released a new land use policy for surface land in Alberta, the Alberta Land Use Framework (the “ALUF”). The ALUF sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the Government of Alberta. It calls for the development of region-specific land use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans.
The Alberta Land Stewardship Act (the “ALSA”) was proclaimed in force in Alberta on October 1, 2009 and provides the legislative authority to implement the policies contained in the ALUF. Regional plans established pursuant to the ALSA will be binding on the Government of Alberta and provincial regulators, including those governing the oil and gas industry. In the event of a conflict or inconsistency between a regional plan and another regulation, regulatory instrument or statutory consent, the regional plan will prevail. Further, the ALSA requires local governments, provincial departments, agencies and administrative bodies or tribunals to review their regulatory instruments and make any appropriate changes to ensure that they comply with an adopted regional plan. The ALSA also contemplates the amendment or extinguishment of previously issued statutory consents such as regulatory permits, leases, licenses, approvals and authorizations for the purpose of achieving or maintaining an objective or policy resulting from the implementation of a regional plan. Among the measures to support the goals of the regional plans contained in the ALSA are conservation easements, which can be granted for the protection, conservation and enhancement of land; and conservation directives, which are explicit declarations contained in a regional plan to set aside specified lands in order to protect, conserve, manage and enhance the environment.
The first regional plan under the ALSA, the Lower Athabasca Regional Plan (the “LARP”), came into effect on September 1, 2012. The LARP covers the northeast corner of Alberta and the entirety of the Athabasca oil sands region. The next regional plan to take effect is the South Saskatchewan Regional Plan (the “SSRP”) which covers approximately 83,764 square kilometres and includes 45% of the provincial population. The SSRP was released in draft form in 2013. All input was gathered as of February 28, 2014, and the Government has advised that summary results will be made publically available soon. With the implementation of the new Alberta regulatory structure under the AER, AESRD will remain responsible for development and implementation of regional plans. However, the AER will take on some responsibility for implementing regional plans in respect of energy related activities.
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The Government of Alberta enacted the Climate Change and Emissions Management Act (the “CCEMA”) on December 4, 2003, amending it through the Climate Change and Emissions Management Amendment Act, which received royal assent on November 4, 2008. The CCEMA is based on an emissions intensity approach similar to the Updated Action Plan and aims for a 50% reduction from 1990 emissions relative to GDP by 2020. Alberta facilities emitting more than 100,000 tonnes of carbon dioxide equivalent a year are subject to compliance with the CCEMA. As at year-end 2013, we did not have an interest in any facilities in Alberta that emit more than 100,000 tonnes of carbon dioxide equivalent per year.
On December 2, 2010, the Government of Alberta passed the Carbon Capture and Storage Statutes Amendment Act, 2010. It deemed the pore space underlying all land in Alberta to be, and to have always been, the property of the Crown and provided for the assumption of long-term liability for carbon sequestration projects by the Crown, subject to the satisfaction of certain conditions.
British Columbia
In British Columbia, the Oil and Gas Activities Act (the “OGAA”) governs conventional oil and gas producers, shale gas producers and other operators of oil and gas facilities. Under the OGAA, the British Columbia Oil and Gas Commission (the “Commission”) has broad powers, particularly with respect to compliance and enforcement and the setting of technical safety and operational standards for oil and gas activities. The Environmental Protection and Management Regulation establishes the Government’s environmental objectives for water, riparian habitats, wildlife and wildlife habitat, old-growth forests and cultural heritage resources. The Commission is required to consider these environmental objectives in deciding whether or not to authorize an oil and gas activity. In addition, the Petroleum and Natural Gas Act requires proponents to obtain various approvals before undertaking exploration or production work. Such approvals are given subject to environmental considerations and licences and project approvals can be suspended or cancelled for failure to comply with this legislation or its regulations.
In February, 2008, the Government of British Columbia announced a revenue-neutral carbon tax that took effect July 1, 2008. The tax is consumption-based and applied at the time of retail sale or consumption of virtually all fossil fuels purchased or used in British Columbia. The current tax level is $30 per tonne of carbon dioxide equivalent. British Columbia is currently undertaking a comprehensive review of the carbon tax, and may or may not make changes to its carbon tax regime. In order to make the tax revenue-neutral, British Columbia has implemented tax credits and reductions in order to offset the tax revenues that the Government of British Columbia would otherwise receive from the tax.
On April 3, 2008, British Columbia introduced the Greenhouse Gas Reduction (Cap and Trade) Act (the “Cap and Trade Act”) which received royal assent on May 29, 2008 and partially came into force by regulation of the Lieutenant Governor in Council. Unlike the emissions intensity approach taken by the federal government and the Government of Alberta, the Cap and Trade Act establishes an absolute cap on greenhouse gas emissions. Although more specific details of British Columbia’s cap and trade plan have not yet been finalized, on January 1, 2010, new reporting regulations came into force requiring all British Columbia facilities emitting over 10,000 tonnes of carbon dioxide equivalents per year to begin reporting their emissions. Facilities reporting emissions greater than 25,000 tonnes of carbon dioxide equivalents per year are required to have their emissions reports verified by a third party. Regulations pertaining to proposed offsets and emissions trading remain in development. As at year-end 2013, we did not have an interest in any facilities in British Columbia that emit more than 25,000 tonnes of carbon dioxide equivalent per year.
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Federal
Pursuant to the Jobs, Growth and Long-term Prosperity Act which received Royal Assent on June 29, 2012, the Government of Canada amended or repealed several pieces of federal environmental legislation and in addition, created a new federal environment assessment regime that came in to force on July 6, 2012. The changes to the environmental legislation under the Prosperity Act are intended to provide for more efficient and timely environmental assessments of projects that previously had been subject to overlapping legislative jurisdiction.
In December 2002, the Government of Canada ratified the Kyoto Protocol (“Kyoto Protocol”), which requires a reduction in greenhouse gas (“GHG”) emissions by signatory countries between 2008 and 2012. The Kyoto Protocol officially came into force on February 16, 2005, although on December 12, 2011, the Government of Canada formally withdrew from the Kyoto Protocol.
On April 26, 2007, the Government of Canada released “Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution” (the “Action Plan”) which set forth a plan for regulations to address both GHGs and air pollution. An update to the Action Plan, “Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions” was released on March 10, 2008 (the “Updated Action Plan”). The Updated Action Plan outlines emissions intensity-based targets which will be applied to regulated sectors on either a facility-specific, sector-wide or company-by-company basis. Facility-specific targets apply to the upstream oil and gas, oil sands, petroleum refining and natural gas pipelines sectors. Unless a minimum regulatory threshold applies, all facilities within a regulated sector will be subject to the emissions intensity targets.
The Updated Action Plan makes a distinction between “Existing Facilities” and “New Facilities”. For Existing Facilities, the Updated Action Plan requires an emissions intensity reduction of 18% below 2006 levels by 2010, followed by a continuous annual emissions intensity improvement of 2%. “New Facilities” are defined as facilities beginning operations in 2004 and include both greenfield facilities and major facility expansions that (i) result in a 25% or greater increase in a facility’s physical capacity, or (ii) involve significant changes to the processes of the facility. New Facilities will be given a 3-year grace period during which no emissions intensity reductions will be required. Targets requiring an annual 2% emissions intensity reduction will begin to apply in the fourth year of commercial operation of a New Facility. Further, emissions intensity targets for New Facilities will be based on a cleaner fuel standard to encourage continuous emissions intensity reductions over time. The method of applying this cleaner fuel standard has not yet been determined. In addition, the Updated Action Plan indicates that targets for the adoption of carbon capture and storage technologies will be developed for oil sands in-situ facilities, upgraders and coal-fired power generators that begin operations in 2012 or later.
In the following regulated sectors, the Updated Action Plan will apply only to facilities exceeding a minimum annual emissions threshold: (i) 50,000 tonnes of CO2equivalent per year for natural gas pipelines; (ii) 3,000 tonnes of CO2equivalent per upstream oil and gas facility; and (iii) 10,000 boe/d company. These proposed thresholds are significantly stricter than the current Alberta regulatory threshold of 100,000 tonnes of CO2equivalent per year per facility.
Four separate compliance mechanisms are provided in respect of the above targets: Technology Fund (as defined in the Updated Action Plan) contributions, offset credits, clean development credits and credits for early action. The most significant of these compliance mechanisms, at least initially, will be the Technology Fund and for which regulated entities will be able to contribute in order to comply with emissions intensity reductions. The contribution rate is to increase over time rising from $20 per tonne in 2013 at the nominal rate of gross domestic product growth. Contribution limits will correspondingly decline from 70% in 2010 to 0% in 2018. Monies raised through contributions to the Technology Fund are to be used to invest in technology to reduce greenhouse gas emissions. Alternatively, regulated entities may be able to receive credits for investing in large-scale and transformative projects at the same contribution rate and under similar requirements as mentioned above.
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The offset system is intended to encourage emissions reductions from activities outside of the regulated sphere, allowing non-regulated entities to participate in and benefit from emissions reduction activities. In order to generate offset credits, project proponents must propose and receive approval for emissions reduction activities are to be verified before offset credits can be issued to the project proponent. Those credits can then be sold to regulated entities for use in compliance or non-regulated purchasers that wish to either cancel the offset credits or bank them for future use or sale. A draft of three Program Rules and Guidance documents detailing eligibility requirements and the application processes are expected to be published in the fall of 2009. Canada’s offset system is to be administered under the Canadian Environmental Protection Act, 1999.
Under the Updated Action Plan, regulated entities will also be able to purchase credits created through the Clean Development Mechanism of the Kyoto Protocol. The purchase of such Emissions Reduction Credits is to be restricted to 10% of each firm’s regulatory obligation, with the added restriction that credits generated through forest sink projects will not be available for use in complying with the Canadian regulations.
Although draft regulations for the implementation of the Updated Action Plan were intended to become binding on January 1, 2010, only regulations pertaining to carbon dioxide emissions from coal-fired generation of electricity have been enacted to date. Further, representatives of the Government of Canada have indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the U.S. with respect to GHG emissions regulation. As a result, it is unclear to what extent, if any; the proposals contained in the Updated Action Plan will be implemented.
Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting legislative requirements, it is not currently possible to predict either the nature of those requirements or the impact on our operations and financial condition at this time.
The North American Free Trade Agreement
Canada is free to determine under NAFTA whether exports of energy resources to the U.S. or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price subject to an exception with respect to certain voluntary measures which only restrict the volume of exports; and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export price requirements, any prohibition in any circumstances in which any other form of quantitative restriction is prohibited, and in the case of import-price requirements, such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.
NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. NAFTA also contemplates disciplines on regulators to ensure fair implementation of any regulatory changes, to minimize disruption of contractual arrangements and to avoid undue interference with pricing, marketing and distribution arrangements, which is important for Canadian natural gas exports.
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C. Organizational Structure
We are not part of a group and do not have any subsidiaries.
D. Property, Plants and Equipment
Head Office
Our head office is located in rented premises of approximately 4,000 square feet at 2000, 1055 West Hastings Street, Vancouver, British Columbia, Canada V6E 2E9. We began occupying these premises on June 1, 2014. The monthly base rent is $15,656.
Oil & Gas Properties
Core Assets
Our core assets consist of working interests in the Jenner and Atlee Buffalo properties.
Jenner, Southeast Alberta
The Jenner property is accessible year-round and is located northeast of Brooks, Alberta. We have an average working interest of 98% in approximately 18,819 net acres (7,616 ha). The property, 95% operated by us, has multiple zones of potential, existing infrastructure, and low cost drilling and completions. We drilled two horizontal oil wells during the year ended December 31, 2013.
Atlee Buffalo, Southeast Alberta
The Atlee Buffalo property is accessible year-round and is located approximately 30 km east of Jenner, Alberta. We have a 100% working interest in approximately 5,253 net acres (2,126 ha). The property has high original oil in place in two large Glauconitic pools and very low current recovery factors. Primary recovery at this location will be through horizontal drilling and secondary recovery through water and/or polymer flood.
Non-Core Assets
Our non-core assets consist of working interests in the Trutch, Sylvan Lake, Wainwright and Heathdale properties.
Trutch (Tommy Lakes), Northeast British Columbia
The Trutch property is located approximately 200 kilometres northwest of Fort St. John, British Columbia. We have varying working interests from 30% to 100% in approximately 23,102 net acres (9,349 ha). Competitors to the east and south of the Trutch property have been actively exploring and developing the prolific Tommy Lakes Halfway gas field for a number of years. We currently have an interest in four producing Halfway formation, liquid-rich, natural gas wells in Trutch and recognizes multi-zone potential in the area. We did not drill any wells in this area during 2013.
Sylvan Lake, Central Alberta
The Sylvan Lake property is located approximately 160 kilometres southwest of Edmonton and 170 kilometres north of Calgary in central Alberta. The property can be accessed year-round. We currently have working interests ranging from 15% to 25% in nine producing Edmonton Sands natural gas wells on the property. We did not drill any wells in this area during 2013.
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Wainwright, Central Alberta
The Wainwright property is located in east central Alberta. We recognize the region’s upside potential with year-round access, multiple zones, existing infrastructure and low cost drilling and completions. We currently have a working interest of 68.75% in one section of land. We did not drill any wells in this area during 2013.
Heathdale, Southeast Alberta
The Heathdale property is located northeast of Brooks, Alberta and north of our Jenner Property. We have 3.0 sections (1,920 acres) of land in this area. We did not drill any wells in this area during 2013.
Reserve Data
The standards of the SEC require that proved reserves be estimated using existing economic conditions (constant pricing). Based on this methodology, our results have been calculated utilizing the 12-month average price for each of the years presented.
In 2013, we retained McDaniel Associates & Consultants Ltd. (“McDaniel”), independent petroleum engineering consultants based in Calgary, Alberta, to evaluate our properties. Our reserves report prepared by McDaniel was completed May 27, 2014 and has an effective date of December 31, 2013 (the “McDaniel Report”). The McDaniel Report evaluated our oil, NGL and natural gas reserves.
We have also retained Sproule Associates Limited (“Sproule”), independent petroleum engineering consultants, based in Calgary, Alberta, to evaluate our properties. Our reserves reports prepared by Sproule were completed September 12, 2014 and have effective dates of February 29, 2012 and December 31, 2012, respectively (together, the “Sproule Reports”). The Sproule Reports evaluated our proved crude oil, natural gas and NGL reserves.
All properties evaluated are in Canada and specifically in Alberta and British Columbia.
The tables below are a summary of the oil, NGL and natural gas reserves attributable to our properties and the net present values of future net revenue attributable to such reserves as evaluated in the McDaniel Report and Sproule Reports based on 12 month SEC compliant constant pricing. The tables summarize the data contained in the McDaniel Report and Sproule Reports and, as a result, may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.
The net present values of future net revenue attributable to reserves is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures and well abandonment costs for only those wells assigned reserves by McDaniel and Sproule. It should not be assumed that the undiscounted or discounted net present values of future net revenue attributable to reserves estimated by McDaniel and Sproule represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized below. The recovery and reserve estimates of oil, NGL and natural gas reserves provided are estimates only. Actual reserves may be greater than or less than the estimates provided.
The McDaniel and the Sproule Reports are based on certain factual data we have supplied to McDaniel and Sproule and on McDaniel’s and Sproule’s opinions of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to petroleum properties and contracts (except for certain information residing in the public domain) we have supplied to McDaniel and Sproule. McDaniel and Sproule accepted this data as presented and neither title searches nor field inspections were conducted.
The recovery and reserve estimates on our properties described in this Form 20-F are estimates only. The actual reserves on our properties may be greater or less than those calculated. See the information under “Item 3.D. Risk Factors – Our reserve estimates depend on many assumptions that may prove to be inaccurate and are subject to revision based on production history, and material inaccuracies in the reserve estimates or the underlying assumptions, or revision based on production history, may adversely affect the quantities and present value of our reserves”.
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Controls Over Reserve Report Preparation
Our reserve estimates reports as of December 31, 2013 are prepared by independent qualified reserve evaluators, McDaniel, and our reserve estimates reports as of February 29, 2012 and December 31, 2012 are prepared by independent qualified reserve auditors, Sproule. To ensure accuracy and completeness of the data prior to disclosure of reserve estimates to the public, our Reserves Committee does the following in accordance with applicable laws: (1) reviews our procedures for providing information to the independent qualified reserve evaluators, (2) meets with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the qualified reserves evaluators to report without reservation, (3) reviews the reserves data with management and the independent qualified reserves evaluator. If the Reserves Committee is satisfied with results of its evaluation it will approve the content of our reserve disclosure. If any concerns arise in the reserve committee’s evaluation, the reserves committee will work with management and the independent qualified reserves evaluators to resolve the issues before disclosure of reserves is made public.
As at December 31, 2013, our Reserves Committee was composed of Greg Sadler (Chairman), Bruce McIntyre, Don Simmons and Gregg Vernon. As at the date of this Form 20-F, our Reserves Committee was composed of Bruce McIntyre (Chairman), Don Simmons and Gregg Vernon. Please see the biographical information on the members of the Reserves Committee under the heading “Item 6.A. Directors and Senior Management”.
Summary of Oil and Gas Reserves as of Fiscal Year-End Based on Average Fiscal Year Prices
| Reserves | Heavy Oil | Natural Gas | Natural Gas Liquids |
| Gross(1) | Net(2) | Gross(1) | Net(2) | Gross(1) | Net(2) |
| (Mbbl) | (Mbbl) | (MMcf) | (MMcf) | (Mbbl) | (Mbbl) |
| Developed Producing | 521.6 | 448.3 | 451.2 | 406.2 | 1.3 | 0.9 |
| Non-Producing | 22.7 | 20.9 | 2.8 | 2.1 | - | - |
| Undeveloped | 599.0 | 523.0 | 159.9 | 145.2 | - | - |
| Total Proved | 1,143.4 | 992.2 | 613.8 | 553.5 | 1.3 | 0.9 |
Notes:
| | (1) | Gross reserves are working interest reserves before royalty deductions. |
| | (2) | Net reserves include working interest after royalty deductions plus royalty interest reserves. |
Total Proved Reserves
The following table compares estimated proved reserves and associated present value, discounted at an annual rate of 10% of the future revenue before income tax as at December 31, 2013.
Proved Developed and
Undeveloped Reserves
|
Heavy
Oil(1)
|
Natural
Gas(1)
|
Natural Gas
Liquids(1)
|
Total(1)
| Net Present Value
(before tax,
discounted at 10%
per year)(2) |
| (Mbbl) | (MMcf) | (Mbbl) | (Mboe) | ($M) |
| 2013 12-month average prices (SEC)(3) | 992.2 | 553.5 | 0.9 | 1,085.4 | 22,969.4 |
The following table provides the reconciliation to standardized measure. The information is in thousands of Canadian dollars.
As at December 31, 2013 | Net Present Value,
discounted at 10%
per year (2)(4) |
Present value of estimated future net cash flows before income taxes | 22,969.4 |
Income taxes - discounted | 881.1 |
Standardized measure of discounted future net cash flow | 22,088.3 |
Notes:
| | (1) | Net reserves include working interest after royalty deductions plus royalty interest reserves. |
| | (2) | Present value of estimated future net cash flows before income taxes, discounted at an annual discount rate of 10% (PV-10) is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account the related deferred income taxes, as such taxes may differ among various companies because of differences in the amounts and timing of deductible basis, net operating loss carry forwards and other factors. We believe investors and creditors use our PV-10, before tax, as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10, before tax, should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. |
| | (3) | The 12-month average prices (SEC) are calculated based on an average of market prices posted at or near the first of each month from January to December 2013, adjusted for quality differentials and pipeline transportation costs from wellhead to the interstate pipeline prevailing at December 31, 2013. The 12-month average prices (SEC) used for our properties were Cdn$71.00 per barrel of oil, Cdn$2.97 per Mcf of natural gas and Cdn$66.58 per barrel of natural gas liquids. |
| | (4) | Costs associated with extraction of natural gas products have in most cases been deducted from the natural gas revenues. |
At December 31, 2012, we had six proved undeveloped locations booked. In the twelve months ended December 31, 2013, no proved undeveloped reserves were converted to proved developed reserves.
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For the fiscal year ended December 31, 2013, an additional seven proved undeveloped locations were booked on new lands and offsetting discoveries in the 2012 fiscal year. Two of the previously booked proved undeveloped locations were taken off the books, bringing the total proved undeveloped booked locations to eleven at December 31, 2013. Of these locations, five wells have already been drilled year-to-date and the remainder have surface locations picked and acquisition/licensing underway.
No proved undeveloped reserves have been booked for more than five years.
Oil and Gas Production, Production Prices and Production Costs
The following table sets forth our total net oil and gas production for the twelve months ended December 31, 2013, ten months ended December 31, 2012 and twelve months ended February 29, 2012. Production came from our properties located in British Columbia and Alberta, Canada.
| Production |
Fiscal year ended
| Oil and Natural Gas
Liquids
(bbl) | Natural Gas
(Mcf)
| Total
(boe)
|
| December 31, 2013 | 140,182 | 173,116 | 169,034 |
| December 31, 2012(1) | 116,520 | 49,205 | 124,721 |
| February 29, 2012 | 53,823 | 89,920 | 68,810 |
Note:
| | (1) | Due to our fiscal year-end change, this fiscal year represents a ten month period. |
The following table sets forth the average prices we received for our production for the twelve months ended December 31, 2013, ten months ended December 31, 2012 and twelve months ended February 29, 2012.
| Average Sales Price |
Fiscal year ended
| Oil and Natural Gas
Liquids
($/bbl) | Natural Gas
($/Mcf)
| Total
($/boe)
|
| December 31, 2013 | 71.17 | 3.45 | 62.55 |
| December 31, 2012(1) | 66.72 | 2.07 | 63.15 |
| February 29, 2012 | 79.81 | 3.28 | 66.71 |
Note:
| | (1) | Due to our fiscal year-end change, this fiscal year represents a ten month period. |
The following table sets forth the average production costs, including transportation costs, per unit of production for the twelve months ended December 31, 2013, ten months ended December 31, 2012 and twelve months ended February 29, 2012.
| Average Production Costs |
Fiscal year ended
| Oil and Natural Gas
Liquids
($/bbl) | Natural Gas
($/Mcf)
| Total
($/boe)
|
| December 31, 2013 | 19.73 | 1.41 | 18.15 |
| December 31, 2012(1) | 14.26 | 3.75 | 14.81 |
| February 29, 2012 | 10.57 | 4.19 | 13.74 |
Note:
| | (1) | Due to our fiscal year-end change, this fiscal year represents a ten month period. |
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Drilling and Other Exploratory and Development Activities
During the last three fiscal years, we drilled the following wells in Canada.
| Fiscal Year Ended | Net Exploratory Wells | Net Development Wells |
| Productive | Dry | Productive | Dry |
| December 31, 2013 | | | | |
| Oil | - | - | 2.0 | - |
| Natural Gas | - | - | - | - |
| Total | - | - | 2.0 | - |
| | | | | |
| December 31, 2012(1) | | | | |
| Oil | - | - | 8.0 | - |
| Natural Gas | - | - | - | - |
| Total | - | - | 8.0 | - |
| | | | | |
| February 29, 2012 | | | | |
| Oil | 1.0 | - | 3.0 | - |
| Natural Gas | - | - | - | - |
| Total | 1.0 | - | 3.0 | - |
Note:
| | (1) | Due to our fiscal year-end change, this fiscal year represents a ten month period. |
Delivery Commitments
We have no current delivery commitments for either oil or natural gas.
Present Activities
Atlee Buffalo, Alberta
During the first six months of 2014, we successfully drilled and commenced production of one new well and completed production improvements to an existing well in the Atlee Buffalo area. The new well has already produced over 16,000 barrels of oil equivalent to date and is still producing approximately 66 boe/d. In June 2014, we commenced our summer drilling program consisting of five development wells in the Atlee Buffalo area which are offsetting our first well location. The first two wells of the program have now been on production for over 30 days and are producing approximately 100 boe/d (93% oil) and 65 boe/d (88% oil). We are also in the process of bringing four wells, which were previously shut-in, on production.
On July 23, 2014, we announced that we closed an acquisition for additional petroleum and natural gas leases in the Atlee Buffalo area of southeast Alberta. The property included an 85% working interest in 1.75 sections (1,120 acres) of land adjacent to our existing land base. Total consideration for the acquisition is $510,000.
Jenner, Alberta
During the first six months of 2014, we successfully drilled and commenced production of two new wells and completed rental equipment buyouts and equipment upgrades at the main production facility in Jenner. The equipment upgrades included costs associated with a solution gas compressor that was completed and placed online in April 2014. We also completed a workover on a shut-in injection well in order to bring it back online and improve its injection capacity to allow it to dispose of more fluids in the future.
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Oil and Gas Properties and Wells
As of December 31, 2013, we had 79.0 gross (66.3375 net) producing or shut-in oil or natural gas wells.
| As at December 31, 2013 | Oil | Natural Gas |
| Gross | Net | Gross | Net |
| Producing | 20.0 | 19.8 | 15.00 | 4.85 |
| Shut-In | 40.0 | 38.5 | 4.00 | 3.1875 |
| Total | 60.0 | 58.3 | 19.00 | 8.0375 |
Oil and Gas Properties and Wells
The following table sets forth information for our interest in oil and gas properties as at December 31, 2013 relating to our leasehold acreage. Developed acres are acres spaced or assigned to productive wells. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas or oil, regardless of whether such acreage contains proved reserves. Gross acres are the total number of acres in which a working interest is owned. Net acres are the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
As at December 31, 2013, our developed and undeveloped acres are set forth in the following table.
| | Developed Acreage | Undeveloped Acreage | Total |
| Gross | Net | Gross | Net | Gross | Net |
| Producing | 30,123 | 14,421 | 38,235 | 36,241 | 68,358 | 50,662 |
Our net undeveloped acres as at December 31, 2013, together with expiries for the period from 2014 to 2016 and thereafter, is set forth in the following table.
Location
| Undeveloped Acreage |
Net
| 2014 expirations
| 2015 expirations
| 2016 and
thereafter
expirations |
| Alberta | | | | |
| Atlee Buffalo | 3,333 | 1,667 | - | 1,666 |
| Buffalo Lake | 1,280 | - | 1,280 | - |
| Heathdale | 1,920 | - | - | 1,920 |
| Jenner | 12,489 | 640 | 2,976 | 8,873 |
| Sylvan Lake | - | - | - | - |
| British Columbia | | | | |
| Trutch | 17,219 | - | - | 17,219 |
| Total | 36,241 | 2,307 | 4,256 | 29,678 |
ITEM 4A. UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
The following discussion and analysis of our operating results and financial condition should be read in conjunction with our audited financial statements for the twelve months ended December 31, 2013 and ten months ended December 31, 2012 and related notes included and our unaudited condensed interim financial statements for the three and six months ended June 30, 2014 under the heading “Item 18. Financial Statements”.
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Our financial statements for the fiscal years ended December 31, 2013, December 31, 2012 and February 29, 2012 are presented in Canadian dollars and have been prepared in accordance with IFRS as issued by the IASB.
Certain forward-looking statements are discussed in this Item 5 with respect to our activities and future financial results. These are subject to risks and uncertainties that may cause projected results or events to differ materially from actual results or events. Readers should also read the “Cautionary Note Regarding Forward-Looking Statements” and the risk factors under the heading “Item 3.D. Risk Factors”.
Critical Accounting Estimates
The preparation of these financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that may affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates.
Following are the accounting policies subject to such judgments and the key sources of estimation uncertainty that we believes could have the most significant impact on the reported results and financial position.
Reserves
The estimate of oil and natural gas reserves is integral to the calculation of the amount of depletion charged to the statements of comprehensive income (loss) and is also a key determinant in assessing whether the carrying value of any of our development and production assets have been impaired. Changes in reported reserves can impact asset carrying values and the decommissioning provision due to changes in expected future cash flows. Our reserves are evaluated and reported on by independent reserve engineers at least annually in accordance with Canadian Securities Administrators’ National Instrument 51-101 Standards of Disclosure of Oil and Gas Activities. Reserve estimation is based on a variety of factors including engineering data, geological and geophysical data, projected future rates of production, commodity pricing and timing of future expenditures, all of which are subject to significant judgment and interpretation.
Carrying value of property and equipment and exploration and evaluation assets
We assess at each reporting date whether there is an indication that an asset or cash-generating unit (“CGU”) may be impaired. A CGU is defined as the lowest grouping of assets that generate identifiable cash inflows that are largely independent of cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires significant judgment and interpretation with respect to the way in which management monitors operations. If any indication exists that an asset or CGU may be impaired, we estimate the recoverable amount. The recoverable amounts of individual assets and CGUs have been determined based on the higher of value-in-use calculations and fair value less costs to sell. These calculations require the use of estimates and assumptions, such as estimates of proved plus probable reserves, future production rates, oil and natural gas prices, future costs and other relevant assumptions, all of which are subject to change.
A material adjustment to the carrying value of our property and equipment and exploration and evaluation assets could arise as a result of changes to these estimates and assumptions.
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Decommissioning obligations
Amounts recorded for decommissioning obligations require the use of management’s best estimates of future decommissioning expenditures, expected timing of expenditures and future inflation rates. The estimates are based on internal and third party information and calculations are subject to change over time and may have a material impact on profit and loss or financial position. For more information on our decommissioning obligations, see Note 9 of the aforementioned financial statements.
Share-based payments
We measure the cost of our share-based payments to directors, officers, employees and certain consultants by reference to the fair value of the equity instruments using the Black-Scholes option pricing model at the date they are granted. The assumptions used in determining fair value include: expected lives of options, risk-free rates of return and stock price volatility. Changes to assumptions may have a material impact on the amounts presented. For more information on our share-based payments, see Note 12(b) of the aforementioned financial statements.
Income taxes
Related assets and liabilities are recognized for the estimated tax consequences between amounts included in the financial statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly, affect the amount of the deferred tax asset or liability calculated at a point in time. These differences could materially impact earnings.
Future Accounting Pronouncements
Certain pronouncements were issued by the IASB that are mandatory for accounting periods after June 30, 2014 or later periods.
The following new standards, amendments and interpretations, have not been early adopted in these annual financial statements. We are currently assessing the impact, if any, of this new guidance on our future results and financial position:
| | • | IFRS 9 introduces new requirements for classifying and measuring financial assets, as follows: |
| o | Debt instruments meeting both a “business model” test and a “cash flow characteristics” test are measured at amortized cost (the use of fair value is optional in some limited circumstances) |
| o | Investments in equity instruments can be designated as “fair value through other comprehensive income” with only dividends being recognized in profit or loss |
| o | All other instruments (including all derivatives) are measured at fair value with changes recognized in profit or loss |
| o | The concept of “embedded derivatives” does not apply to financial assets within the scope of the standard and the entire instrument must be classified and measured in accordance with the above guidelines. |
| | | The IASB has indefinitely postponed the mandatory adoption date of this standard. |
| | | |
| | • | This is a revised version incorporating revised requirements for the classification and measurement of financial liabilities, and carrying over the existing de-recognition requirements from IAS 39 Financial Instruments: Recognition and Measurement. |
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| | | The revised financial liability provisions maintain the existing amortized cost measurement basis for most liabilities. New requirements apply where an entity chooses to measure a liability at fair value through profit or loss; in these cases, the portion of the change in fair value related to changes in the entity’s own credit risk is presented in other comprehensive income rather than within profit or loss. |
| | | |
| | | The IASB has indefinitely postponed the mandatory adoption date of this standard. |
| | | |
| | • | A revised version of IFRS 9 which: |
| o | Introduces a new chapter to IFRS 9 on hedge accounting, putting in place a new hedge accounting model that is designed to be more closely aligned with how entities undertake risk management activities when hedging financial and non-financial risk exposures |
| o | Permits an entity to apply only the requirements introduced in IFRS 9 (2010) for the presentation of gains and losses on financial liabilities designated as at fair value through profit or loss without applying the other requirements of IFRS 9, meaning the portion of the change in fair value related to changes in the entity’s own credit risk can be presented in other comprehensive income rather than within profit or loss |
| o | Removes the mandatory effective date of IFRS 9 (2010) and IFRS 9 (2009), leaving the effective date open pending the finalization of the impairment and classification and measurement requirements. Notwithstanding the removal of an effective date, each standard remains available for application. |
| | | This standard has no stated effective date. |
| | | |
| | • | Amendment to IAS 19 Employee Benefits: |
| | o | Clarifies the requirements that relate to how contributions from employees or third parties that are linked to service should be attributed to periods of service. In addition, it permits a practical expedient if the amount of the contributions is independent of the number of years of service, in that contribution, can, but are not required, to be recognized as a reduction in the service cost in the period in which the related service is rendered. |
| | | Applicable to annual periods beginning on or after July 1, 2014. |
| | • | Makes amendments to the following standards: |
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| | o | IFRS 2 — Amends the definitions of “vesting condition” and “market condition” and adds definitions for “performance condition” and “service condition” |
| | o | IFRS 3 — Require contingent consideration that is classified as an asset or a liability to be measured at fair value at each reporting date |
| | o | IFRS 8 — Requires disclosure of the judgments made by management in applying the aggregation criteria to operating segments, clarify reconciliations of segment assets only required if segment assets are reported regularly |
| | o | IFRS 13 — Clarify that issuing IFRS 13 and amending IFRS 9 and IAS 39 did not remove the ability to measure certain short-term receivables and payables on an undiscounted basis (amends basis for conclusions only) |
| | o | IAS 16 and IAS 38 — Clarify that the gross amount of property, plant and equipment is adjusted in a manner consistent with a revaluation of the carrying amount |
| | o | IAS 24 — Clarify how payments to entities providing management services are to be disclosed |
| | | Applicable to annual periods beginning on or after July 1, 2014. |
| | | |
| | • | Makes amendments to the following standards: |
| o | IFRS 1 — Clarify which versions of IFRSs can be used on initial adoption (amends basis for conclusions only) |
| o | IFRS 3 — Clarify that IFRS 3 excludes from its scope the accounting for the formation of a joint arrangement in the financial statements of the joint arrangement itself |
| | o | IFRS 13 — Clarify the scope of the portfolio exception in paragraph 52 |
| o | IAS 40 — Clarifying the interrelationship of IFRS 3 and IAS 40 when classifying property as investment property or owner-occupied property |
Applicable to annual periods beginning on or after July 1, 2014.
Financial Instruments and Risk Management
Fair value estimates of financial instruments are made at a specific point in time, based on relevant information about financial markets and specific financial instruments. As these estimates are subjective in nature, involving uncertainties and matters of significant judgment, they may be subject to future adjustment. Changes in assumptions can significantly affect estimated fair values. Our financial instruments include accounts receivable, reclamation deposits, bank indebtedness, and accounts payable and accrued liabilities.
The fair values of accounts receivable, reclamation deposits, accounts payable and accrued liabilities, and bank indebtedness approximate their carrying values due to the short-term maturity of these financial instruments.
Our activities expose us to a variety of risks that arise as a result of our exploration, development, production and financing activities. The following provides information about our exposure to any risks associated with the oil and gas industry as well as our objectives, policies and processes for measuring and managing risk.
Business Risk
Oil and gas exploration and development involves a high degree of risk whereby many properties are ultimately not developed to a producing stage. There can be no assurance that our future exploration and development activities will result in discoveries of commercial bodies of oil and gas. Whether an oil and gas property will be commercially viable depends on a number of factors including the particular attributes of the reserve and its proximity to infrastructure, as well as commodity prices and government regulations, including regulations relating to prices, taxes, royalties, land tenure, land use, and environmental protection. The exact effect of these factors cannot be accurately predicted, and the combination of these factors may result in an oil and gas property not being profitable.
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Credit risk
Credit risk is the risk of financial loss to us if a customer or counterparty to a financial instrument fails to meet its payment obligations. This risk arises principally from our receivables from joint venture partners and oil and natural gas marketers, our cash balance and our reclamation deposits. Any risk associated with accounts receivable is minimized substantially by the financial strength of our joint venture partners, operators and marketers. The credit risk associated with cash and reclamation deposits is mitigated by ensuring these financial assets are placed with major financial institutions with strong investment-grade ratings by a primary ratings agency. We do not anticipate any default.
Our maximum exposure to credit risk is set forth in the following table.
| 6 Months Ended
June 30, 2014
($) | 12 Months Ended
December 31, 2013
($) | 10 Months Ended
December 31, 2012
($) |
Cash | 1,352,978 | - | - |
| Accounts receivable | 1,132,770 | 1,042,407 | 904,454 |
| Reclamation deposits | 105,535 | 105,535 | 100,535 |
| Total | 2,591,283 | 1,147,942 | 1,004,989 |
Liquidity risk
Liquidity risk is the risk that we will not be able to meet our financial obligations as they come due. We manage liquidity risk by anticipating operating, investing and financing activities and ensuring that it will have sufficient liquidity to meet our liabilities when they become due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to us.
We prepare expenditure budgets on a quarterly and annual basis which are regularly monitored and updated when necessary in order to review debt forecasts and working capital requirements. All of our financial liabilities have contractual maturities of less than 90 days.
As at December 31, 2013, we had negative working capital of $6,700,147 (December 31, 2012 - $3,927,595), which includes bank indebtedness of $4,500,000 (December 31, 2012 - $1,035,000). As at June 30, 2014, we had negative working capital of $1,911,603 (June 30, 2013 - $4,643,327), which includes bank indebtedness of nil (June 30, 2013 - $4,377,500). We fund our operations through production revenue and a demand operating credit facility.
Market risk
Market risk is the risk that changes in market prices, such as, foreign exchange rates, commodity prices, and interest rates will affect the value of the financial instruments. Market risk is comprised of interest rate risk, foreign currency risk and other price risk.
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Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. Borrowings under our credit facilities are subject to variable interest rates. A one percent change in interest rates would not have a material effect on net income and comprehensive income.
Foreign currency risk
We are not exposed to significant foreign currency risk. We sell our oil through a Canadian marketer and receive our revenues in Canadian currency. As North American oil is benchmarked to the West Texas Intermediate (WTI) index, the price of our oil is affected by the Canadian/United States dollar exchange rate. However, our sensitivity analysis shows that for every basis point increase in the Canadian dollar, our profit margin would be adversely affected by less than 0.03% .
Other price risk
Other price risk is the risk that the fair or future cash flows of a financial instrument will fluctuate due to changes in market prices, other than those arising from interest rate risk or foreign currency risk. We are not exposed to significant other price risk.
A. Operating Results
Six months ended June 30, 2014 compared to the six months ended June 30, 2013
1. Revenue
Total revenue for the six months ended June 30, 2014 was $7,363,497, representing a 65% increase of $2,913,968 over the comparable period of 2013. This increase in revenue is consistent with the 36% growth in total production as a result of our drilling program in the Jenner and Atlee Buffalo areas and the 21% increase in combined average realized price for the period. We realized much lower NGL revenue in the period as our wells in the Trutch area were down for the first quarter and most of the second quarter of 2014 due to weather-related issues.
2. Royalties
Royalties for the six months ended June 30, 2014 increased by $631,728 to $1,329,017 over the comparable period of 2013. This can be attributed to the two Jenner oil wells drilled in 2013 under a farm-in agreement which are subject to Alberta Crown royalties and gross overriding royalties as well as the fact that two of our wells ended their royalty holiday in the second quarter of 2014. This increase in royalties is also consistent with our increase in production and combined average realized price for the six months ended June 30, 2014.
3. Production and Operating
Operating costs include all costs for gathering, processing, dehydration, compression, water processing, transportation and marketing of the oil, natural gas and NGLs, as well as additional costs incurred periodically for maintenance and repairs. Operating costs for the six months ended June 30, 2014 were $2,145,365, an increase of $783,426 over the comparable period of 2013. This increase in operating costs can be attributed to third party processing fees for the two wells drilled in 2013, temporary propane use at new wells and costs associated with an unscheduled turnaround at our main production facility in Jenner.
Oil Operations
The average realized heavy oil price increased during the six months ended June 30, 2014 by $15.44/bbl over the comparable period of 2013. This 23% increase in our realized heavy oil price had a substantial effect on our oil revenues for the six months ended June 30, 2014 which increased by 65% over the comparable period of 2013. This increase is a reflection of strong WTI pricing, combined with narrowing WCS heavy oil differentials and a favourable exchange rate in the first six months of 2014.
Average oil royalties for the first six months of 2014 increased by $609,316, or $4.57/boe, over the comparable period of 2013. This increase can be attributed to the two Jenner oil wells drilled in 2013 under a farm-in agreement which are subject to Alberta Crown royalties and gross overriding royalties as well as the fact that two of our wells ended their royalty holiday in the second quarter of 2014. This increase in royalties is also consistent with our 23% increase in our realized heavy oil price for the first quarter of 2014.
Oil operating costs for the first six months of 2014 increased by $678,839, or $4.00/boe, over the comparable period of 2013. This increase in operating costs can be attributed to third party processing fees for the two wells we drilled in the previous fiscal year, temporary propane use for new wells and costs associated with an unscheduled turnaround at our main production facility in Jenner.
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Oil transportation costs for the first six months of 2014 increased by 43% over the comparable period of 2013. This increase can be attributed to the Atlee Buffalo wells acquired in the fourth quarter of 2013 which, compared to the Jenner wells, have a higher transportation cost of $4.35/boe associated with trucking production volumes to processing facilities and sales.
Natural Gas Operations
Our average realized natural gas price also increased in the first six months of 2014 by $1.03/Mcf over the comparable period of 2013. This 29% increase in our realized natural gas price had a substantial effect on our natural gas revenues for six months ended June 30, 2014 which increased by 112% over the comparable period of 2013.
Average natural gas royalties for the six months ended June 30, 2014 increased by $0.63/boe over the comparable period of 2013. This increase can be attributed to the 64% increase in gas production as well as the 29% increase in our realized natural gas price for the period.
Natural gas operating expenses decreased by $3.66/boe over the comparable period of 2013. This decrease can be attributed to our 64% increase in gas production as a result of gas volumes from the new Jenner wells, the Atlee Buffalo acquisition and the installation of a gas sweetening tower at our main production facility in Jenner.
Natural gas transportation costs paid for the six months ended June 30, 2014 were consistent with those paid in the six months ended June 30, 2013.
4. Exploration and Evaluation
Exploration and evaluation expense generally consists of certain geological and geophysical costs, expiry of undeveloped lands and costs of uneconomic exploratory wells. For the six months ended June 30, 2014 and 2013 were $41,666 and $24,669, respectively.
5. Depletion and Depreciation
Depletion and depreciation expense for the six months ended June 30, 2014 increased by $170,729 due to our acquisition of the Atlee Buffalo property in the fourth quarter of 2013, as well as the development of three producing oil wells during the first quarter of 2014. The decrease in depletion and depreciation by $2.61/boe for the six months ended June 30, 2014 can be attributed to our 36% increase in production for the current quarter.
6. General and Administrative
General and administrative expenses for the six months ended June 30, 2014 were $652,320, which represents a decrease of $60,897 over the comparable period of 2013. The general and administrative costs include share-based payments of $nil and $65,070 for the first six months of 2014 and 2013 respectively. Gross general and administrative expenses increased by $103,215 for the six months ended June 30, 2014, and we also captured overhead recoveries in the amount of $255,969 for the new wells drilled in the quarter. The increase in gross general and administrative costs during the first six months of 2014 can be attributed to increased investor relations activities of $10,725, professional fees of $72,846 and staffing costs of $41,015.
We calculate our overhead recovery monthly, based on the capital expenditures incurred in that month. This reflects the capital component of overhead costs applied for each well drilled and construction project at the following recovery rates:
Rates for wells drilled: | Rates for construction projects: |
3% of the first $50,000; plus | 5% of the first $50,000; plus |
2% of the next $100,000; plus | 3% of the next $100,000; plus |
1% of the cost exceeding the sum of the above | 1% of the cost exceeding the sum of the above |
7. Finance Expense
Finance expense for the six months ended June 30, 2014 increased by $72,152 over the comparable period of 2013. This increase is the result of interest charged on our outstanding bank debt. We also incurred $7,500 in part XII.6 tax which is accumulated on the unspent balance of our flow-through expenditures at the end of the quarter.
8. Gain on Disposition
We disposed of a vertical treater from our Jenner facility in the first quarter of 2014, which resulted in a small gain of $2,942 for the six months ended June 30, 2014.
Year ended December 31, 2013 compared to the ten months ended December 31, 2012
1. Revenue
For the twelve months ended December 31, 2013, total revenue increased by $2,697,476, or 34%, over the ten months ended December 31, 2012. This increase is consistent with the 14% growth in production as a result of our drilling programs in the Jenner area and the 6% increase in our average combined realized price.
2. Royalties
Royalties for the twelve months ended December 31, 2013 increased by $526,649 over the comparable period of 2012 which can be attributed to the newly drilled oil wells in Jenner which are subject to Alberta Crown royalties and gross overriding royalties.
3. Production and Operating
Operating costs for the twelve months ended December 31, 2013 was $3,067,174, which is an increase of $1,220,643 over its comparable period of 2012. This increase in operating costs can be attributed to third party processing fees for our recently drilled wells in 2013. For 2014, we are negotiating reduced rates for the third party facility processing.
Oil Operations
Our average realized oil price increased during the twelve months ended December 31, 2013 by $4.43/boe over the ten months ended December 31, 2012. This 7% increase in our realized heavy oil price contributed to the 28% increase in our oil revenues for the year ended December 31, 2013 over the comparable period of 2012. This increase is a reflection of strong WTI pricing, combined with narrowing WCS heavy oil differentials during 2013.
Average oil royalties paid for the twelve months ended December 31, 2013 increased slightly over those paid in the ten months ended December 31, 2012. This increase can be attributed to the new wells drilled in the Jenner area which are subject to Alberta Crown royalties and gross overriding royalties.
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Oil operating expenses increased during the twelve months ended December 31, 2013 by $984,101, or $5.15/boe, over the ten months ended December 31, 2012. This increase in operating costs can be attributed to third party processing fees for the recently drilled wells in 2013.
Oil transportation costs paid for the twelve months ended December 31, 2013 were consistent with those paid in the ten months ended December 31, 2012.
Natural Gas Operations
Our average realized gas price increased during the twelve months ended December 31, 2013 by $1.38/Mcf over the ten months ended December 2012. This 67% increase in our realized natural gas price had a substantial impact on our natural gas revenues for the year ended December 31, 2013, which increased by $494,872 over the ten months ended December 31, 2012. This increase in realized natural gas price is also consistent with the increase in the Alberta 30 day spot AECO prices.
Average gas royalties paid for the twelve months ended December 31, 2013 increased by $20,652, or $0.61/boe, over those paid in the ten months ended December 31, 2012. This increase is consistent with our increase in gas production and 67% increase in our realized natural gas price in the period.
Natural gas operating expenses and transportation costs paid for the twelve months ended December 31, 2013 were consistent with those paid in the ten months ended December 31, 2012.
4. Exploration and Evaluation
Throughout the year, expenditures were made on some of our non-producing properties, including property leases and licenses, reclamation costs and other general expenses. Exploration and evaluation expenses for the twelve months December 31, 2013 was $116,006 as compared to $120,882 for the ten months ended December 31, 2012.
5. Depletion and Depreciation
Depletion and depreciation expense for the twelve months ended December 31, 2013 increased by $849,258 over the comparable period of 2012. This can mainly be attributed to the increase in depletion relative to our acquisition of the Atlee Buffalo property in the fourth quarter of 2013, as well as the development of two producing oil wells during the current fiscal year.
6. General and Administrative
General and administrative expenses for the twelve months ended December 31, 2013 were $1,877,376 and increased by $349,871 over the ten months ended December 31, 2012. The general and administrative costs for the twelve months ended December 31, 2013 and ten months ended December 31, 2012 include share-based payments of $360,464 and $282,872, respectively. We also captured overhead recoveries in the amount of $287,159 for the new wells drilled in the year.
The increase in general and administrative costs can be attributed to increased investor relations activities of $114,563, increased professional fees of $59,648 and higher travel and personnel costs of $274,510 as a result of our ongoing expansion.
We calculate our overhead recovery monthly, based on the capital expenditures incurred in that month. This reflects the capital component of overhead costs applied for each well drilled and construction project at the recovery rates discussed in the general and administrative section of the operating results for the six months ended June 20, 2014.
7. Impairment of Property and Equipment
During the year ended December 31, 2013, we performed an impairment test on our petroleum and natural gas assets. It was determined that the carrying amount of three cash-generating units ("CGUs") exceeded their recoverable amount due to a decline in estimated reserve volumes. Accordingly, we recognized an impairment charge of $5,640,571 for the twelve months ended December 31, 2013 as compared to $184,938 for the ten months ended December 31, 2012.
8. Finance Expense
Finance expense for the twelve months ended December 31, 2013 increased by $155,317 from the comparable period ended December 31, 2012. This increase is the result of interest charged on our outstanding bank debt, which increased by $3,800,000 over the ten months ended December 31, 2012.
9. Gain on Disposition
We disposed of a small gas gathering line for our Sylvan Lake property, which resulted in a gain on disposal of $3,889.
10. Deferred Tax Recovery
We realized an income tax recovery for the twelve months ended December 31, 2013 in the amount of $1,475,234 as compared to an income tax expense of $482,457 for the ten months ended December 31, 2012.
Ten months ended December 31, 2012 compared to the year ended February 29, 2012
1. Revenue
For the ten months ended December 31, 2012, total revenue increased by $3,285,115, or 72%, over the twelve months ended February 29, 2012. This increase can be attributed to the 117% growth in production as a result of our drilling programs in the Jenner area.
2. Royalties
Royalties for the ten months ended December 31, 2012 increased by $669,538 to $1,371,883 and can be attributed to the new oil wells drilled on the Jenner property which are subject to Alberta Crown royalties and gross overriding royalties.
3. Production and Operating
Operating costs for the ten months ended December 31, 2012 increased by $900,813 from the twelve months ended February 29, 2012. This increase in operating costs can be attributed to the fuel and power required to run our operations, higher contract operating costs, and a scheduled maintenance turnaround for our main facility in the Jenner area.
Oil Operations
Our average realized oil price decreased during the ten months ended December 31, 2012 by $13.32 over the twelve months ended February 29, 2012. The decrease can be attributed to lower WTI benchmark pricing as well as increase price differentials between Canadian heavy crude oil and WTI during the period.
Average oil royalties paid for the ten months ended December 31, 2012 increased slightly over those paid in the twelve months ended February 29, 2012. This increase can be attributed to the new wells drilled in the Jenner area which are subject to Alberta Crown royalties and gross overriding royalties.
Oil operating expenses increased for ten months ended December 31, 2012, by 48% over the twelve months ended February 29, 2012. This increase in operating costs can be attributed to the fuel and power required to run our operations, higher contract operating costs, and a scheduled maintenance turnaround for our main facility in the Jenner area.
Oil transportation costs paid for the ten months ended December 31, 2012 were consistent with those paid in the twelve months ended February 29, 2012.
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Natural Gas Operations
Our average realized natural gas price decreased during the ten months ended December 31, 2012 by $1.21/Mcf over the twelve months ended February 29, 2012. This decrease in natural gas price had a substantial impact on our natural gas revenues for the ten months ended December 31, 2012 which decreased by 65% over the twelve months ended February 29, 2012. This decrease in natural gas price is also consistent with the decrease in the Alberta 30 day spot AECO prices.
Average gas royalties paid for the ten months ended December 31, 2012 decreased by 47% as compared to those paid in the twelve months ended February 29, 2012. This decrease is consistent with the 35% decrease in our gas production for the ten months ended December 31, 2012.
Natural gas operating expenses paid for the ten months ended December 31, 2012 were consistent with those paid in the twelve months ended February 29, 2012.
Natural gas transportation costs paid for the ten months ended December 31, 2012 decreased by 43% as compared to those paid in the twelve months ended February 29, 2012. This decrease is consistent with the 35% decrease in our gas production for the ten months ended December 31, 2012.
4. Exploration and Evaluation
Throughout the year, expenditures were made on some of our non-producing properties, including property leases and licenses, reclamation costs and other general expenses. Exploration and evaluation expenses for the ten months December 31, 2012 was $120,882 as compared to $nil for the twelve months ended February 29, 2012.
5. Depletion and Depreciation
The depletion rate is calculated using the unit-of-production method on proved and probable oil and natural gas reserves, taking into account the future development costs to produce the reserves. Depletion and depreciation expense for the ten months ended December 31, 2012 increased by $1,169,497 to $2,239,706. This increase in depletion is relative to the Company's property acquisitions and development of producing wells during the current fiscal period.
6. General and administrative expenses
General and administrative expenses for the ten months ended December 31, 2012 decreased by $539,694, over the twelve months ended February 29, 2012. The general and administrative costs for the ten months ended December 31, 2012 and twelve months ended February 29, 2012 include share-based payments of $282,872 and $1,089,738, respectively.
Excluding the share-based payments, general and administrative expenses increased by $267,172 or 27%. This increase in general and administrative costs can be attributed to increased investor relations services of $73,090, the relocation of our office of $68,328, and the increased travel and personnel costs of $195,052 as required under our ongoing expansion.
7. Impairment of Property and Equipment
During the ten months ended December 31, 2012, we performed an impairment test on our petroleum and natural gas interests. It was determined that the carrying amount of two CGUs exceeded their recoverable amount. Accordingly, we recognized an impairment charge of $184,938 (twelve months ended February 29, 2012 – $251,394).
8. Finance Expense
The increase in finance expense of $34,836 for the ten months ended December 31, 2012 can be attributed to monthly interest charged on our bank debt, as well as the increase in accretion expense. Accretion expense, which increased by $10,277 over the twelve months February 29, 2012, represents the time value change of the decommissioning liability which increased as a result of the addition of eight new oil wells in the ten months ended December 31, 2012.
9. Deferred Tax Expense
We realized a deferred tax expense for the ten months ended December 31, 2012 in the amount of $482,457 as compared to a deferred tax recovery of $ 1,394,544 for the twelve months ended February 29, 2012.
B. Liquidity and Capital Resources
Going Concern and Bank Credit Facility
Our annual audited financial statements for the twelve months ended December 31, 2013, ten months ended December 31, 2012 and twelve months ended February 29, 2012 were prepared on the basis of accounting principles applicable to a going concern, which assumes that we will be able to continue in operation for the foreseeable future and will be able to realize our assets and discharge our liabilities and commitments in the normal course of business. Depending on the results of current drilling operations, we may require additional equity financing to meet our administrative overhead costs, and to continue exploration and development work on our petroleum and natural gas interests in the ensuing year.
We have a demand operating credit facility in the amount of $10,500,000 with ATB under the Commitment Letter. The credit facility is secured by a general security agreement and a floating charge on all of our lands. The credit facility bears interest at the bank’s prime rate plus 1.75% as well as a standby charge for any undrawn funds.
Pursuant to the terms of the demand operating credit facility, we have provided a covenant in the Commitment Letter that at all times our working capital ratio shall not be less than 1.0 to 1.0. The working capital ratio is defined under the terms of the Commitment Letter as current assets including the undrawn portion of the revolving operating demand line credit facility, to current liabilities, excluding any current bank indebtedness. We have maintained compliance with this covenant at all times.
As at December 31, 2013, we had drawn a total of $4,500,000 from the credit facility (December 31, 2012 - $1,035,000) and as at June 30, 2014, we had drawn a total of $nil from the credit facility (June 30, 2013 - $4,377,500).
Cash Balances
We had cash and cash equivalents of nil as at December 31, 2013 and $1,352,978 as at June 30, 2014.
Financial Contracts
We had no financial contracts as at December 31, 2013 or June 30, 2014.
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Working Capital Position
We fund our operations through three key areas: operations funds flow, equity financings through the capital markets and our demand operating credit facility.
| | • | Funds flow from operations. We generated funds flow from operations for the six months ended June 30, 2014 of $3,058,768 (twelve months ended December 31, 2013 - $3,789,201). |
| | | |
| | • | Equity financings. On May 14, 2014, we closed a bought deal financing for gross proceeds of $10,000,125. Upon the receipt of proceeds we paid off our outstanding bank debt which had reached $8,075,000. An additional $921,007 was paid in legal and finders fees in conjunction with the closing of the financing. Finally, the remaining $1,004,118 was used to fund exploration activities, seismic, drilling and related geological work for our Atlee Buffalo summer drilling program. See the table under the heading “Item 10.A. Share Capital – Common Shares” which summarizes our issuances of common shares for the past three fiscal years and from January 1 to September 30, 2014. |
| | | |
| | • | Demand operating credit facility. We currently have total credit facilities limit of $10,500,000, as described under the heading “Item 5.B. Liquidity and Capital Resources”, of which the full amount is available. |
In our opinion, funds available from our demand operating credit facility and the May 2014 bought deal financing provide sufficient working capital for our present requirements and to carry out our summer drilling program of five new oil wells, which commenced in June 2014. The capital requirements related to our summer drilling program was budgeted at $6 million. The first two wells were completed at a combined cost of $2.2 million and were put on production in late July 2014, adding 165 boe/d, as announced in our news release of August 26, 2014. The remaining three wells were completed at a combined cost of approximately $3.4 million and were put on production in late August 2014, adding 340 boe/d, as announced in our news release of September 22, 2014.
Further, in conjunction with an equity financing that closed in November 2013, we are required to spend $2,000,050 in flow-through dollars as part of an exploratory program by December 31, 2014. Finally, as at June 30, 2014, we had the following rental commitments over the next five fiscal years set forth in the following table.
| 2014 | 2015 | 2016 | 2017 | 2018 |
Rental Commitment | $101,481 | $187,875 | $187,875 | $187,875 | $78,281 |
As at June 30, 2014, we had negative working capital of $1,911,603 (June 30, 2013 - $4,643,327), which includes bank indebtedness of $nil (June 30, 2013 - $4,377,500). All of our financial liabilities have contractual maturities of less than 90 days.
As at December 31, 2013, we had negative working capital of $6,700,147, which included bank indebtedness of $4,500,000.
As at December 31, 2012, we had negative working capital of $3,927,595, which included bank indebtedness of $1,035,000.
As at February 29, 2012, we had positive working capital of $2,363,944, which included bank indebtedness of nil.
Capital Resources
Six Months Ended June 30, 2014
During the first and second quarters of 2014, we drilled three wells in the Jenner and Atlee Buffalo areas, completed production improvements to an Atlee Buffalo well and commenced a five well drilling program in Atlee Buffalo. We also spent capital on facilities for rental equipment buyouts and equipment upgrades at the main production facility in Jenner. The equipment upgrades included costs associated with a solution gas compressor that was completed and placed online in the second quarter of 2014. We also completed a workover on a shut-in injection well in order to bring it back online and improve its injection capacity to allow it to dispose of more fluids in the future. Finally, we completed a small acquisition in the surrounding Jenner area which resulted in the acquisition of 1.75 sections (1,120 acres).These capital expenditures were funded through our credit facility.
Twelve Months Ended December 31, 2013
During the twelve months ended December 31, 2013, we drilled two new wells in north Jenner and built and upgraded infrastructure in the Jenner area. The infrastructure included pipelines for new well and upgrades to our main Jenner battery. The upgrades included an increase in fluid handling capacity and the installation of a solution gas sweetening tower, which allows us to sell our gas. We also completed a property acquisition of oil and gas assets in the Atlee Buffalo area of southeast Alberta from an intermediate Canadian producer effective June 1, 2013. These expenditures were funded through our credit facility as well as a bought-deal equity financing for aggregate gross proceeds of $4,300,453.
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Ten Months Ended December 31, 2012
During the ten months ended December 31, 2012, we drilled and completed eight wells in the Jenner area and built infrastructure at our main Jenner battery. The infrastructure included pipelines for new wells and upgrading our main production facility with a new water disposal pump and heated free-water-knockout separator to allow for greater fluid handling capacity. These expenditures were funded through our credit facility, as well as through a private placement for gross proceeds of $1,189,045 and the exercise of 1,752,047 share purchase warrants for proceeds of $1,051,228.
Twelve Months Ended February 29, 2012
During the twelve months ended February 29, 2012, we completed two significant land acquisitions in the Jenner area. The first acquisition was completed in March 2011 which included five sections of land which and produced approximately 25 barrels of oil per day. The second acquisition was completed in January 2012 which consisted of 8.5 net sections of land and operated oil production of approximately 100 barrels of opd, as well as production facilities. During the fiscal year ended February 29, 2012, we also drilled and completed three horizontal wells and one vertical exploration well in the Jenner area.
C. Research and Development, Patents and Licences, etc.
None.
D. Trend Information
Having completed our current summer drilling program, we expect to realize higher revenues from new production and have announced that we have achieved 505 boe/d from the five well program. Our oil, which represents over 93% of our revenue base, is sold through a Canadian marketer and is benchmarked to the WTI index.
On a global basis, over the past three years, oil prices have been relatively stable. The Short-Term Energy Outlook – Market Prices and Uncertainty Report (“STEO”) of the U.S. Energy Information Administration (“EIA”) for September 2014, noted that for the first time in 14 months, North Sea Brent crude oil spot fell outside the relatively narrow $5/bbl range between $107/bbl and $112/bbl. The EIA projects that Brent crude oil prices will average $103/bbl in fourth-quarter 2014 and $103/bbl in 2015. Although the U.S. economy showed robust growth in the second quarter of 2014, recording a revised 4.2% growth rate, economic data in Europe and China were disappointing and points to potentially weaker demand for crude oil going forward, according to the EIA. Given the instability in the Middle East and North Africa, the changing nature of crude oil supplies driven by increasing shale oil production in the U.S. and fluctuations of both economic fortunes and central bank policies, the relative stability over the last three years is remarkable and may not continue.
Indeed, these factors seem to be offsetting one another; for instance, increased U.S. production has counteracted declines in Libya and Iran. Looking ahead, energy prices continue to exhibit many of the same cross-currents, but with somewhat greater downside risk. North America’s supply outlook is robust, with growth potentially equaling trend demand growth alone. In addition, Federal Reserve “tapering” could provide a headwind to commodity prices through a stronger U.S. dollar. Geopolitical risks, which recently have been a tailwind for prices, are more symmetric in 2014 than in past years, with potential for incremental supply of Libyan and Iranian crude to pressure prices lower.
For natural gas, the EIA projected in the STEO for August 2014 that total natural gas consumption in the United States will average 72.6 Bcf/d in 2014, an increase of 1.7% from 2013, led by the industrial sector. In 2015, total natural gas consumption will increase by 0.4 Bcf/d as industrial sector growth offsets lower residential and commercial consumption.
55
The EIA observed in the STEO for September 2014 that natural gas spot prices fell 15% from an average of $4.59 per MMBtu in June to $3.91 per MMBtu in August even as natural gas stock builds continued to outpace historical norms. The EIA expects that the Henry Hub natural gas spot price, which averaged $3.73 per MMBtu in 2013, will average $4.46MMBtu in 2014 and $3.87/MMBtu in 2015.
Natural gas futures prices for December 2014 delivery (for the five-day period ending September 4) averaged $4.07 per MMBtu, and the EIA estimates a 21% probability of exceeding $4.50 per MMBtu at expiration.
E. Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.
F. Tabular Disclosure of Contractual Obligations
The following table sets forth our known contractual obligations as of December 31, 2013 relating to our corporate office and petroleum producing properties. We have no long term debt or loan obligations.
| Contractual Obligations | Payments Due by Period ($) |
Total
| Less than 1
year | 1-3 years
| 3-5 years
| More than 5
years |
| Rental commitment(1) | 763,438 | 155,838 | 533,502 | 74,098 | - |
| Bank credit facility(2) | 4,500,000 | 4,500,000 | - | - | - |
| Flow-through premium liability(3) | 369,240 | 369,240 | - | - | - |
| Total | 5,632,678 | 5,025,078 | 533,502 | 74,098 | - |
Notes:
| | (1) | This represents our commitment to make monthly rental payments pursuant to a rental agreement for our head office. |
| | (2) | An estimate of interest on our bank credit facility cannot be made at this time |
| | (3) | This represents our flow-through premium liability. See Note 12(a)(ii) to our audited financial statements for the fiscal year ended December 31, 2013 for more information. |
G. Safe Harbor
Not applicable.
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
A. Directors and Senior Management
The following table sets forth the name, office held, functions and areas of experience in the Company and principal business activities performed outside the Company of each of our directors and senior management.
56
Name
| Position(s)
with
Hemisphere | Director or
Officer
Since | Principal Business Activities and Other
Principal Directorships
|
Don Simmons, P. Geol.(1)(3)
| President and Chief Executive Officer
| February 2008
| Previously Vice President Exploration of the Company from October 2007. Formerly, a Geologist at Sebring Energy, Encana Corporation and Alberta Energy Company.
|
Charles O’Sullivan, B.Sc.(2)(3)
| Chairman
Director | 2000
1978 | Geophysicist and Mining Executive. Chairman of the Company since 2000.
Chairman of Northern Continental Resources Inc. from 1986 to 2009. |
| Frank Borowicz, QC, CA (Hon)(3)(4) | Director | July 2005 | Retired partner of Davis LLP. Currently President of Pigasus Consulting Services Ltd. and Governor of the Vancouver Board of Trade since 2005. Also, a director of West Cirque Resources Ltd. (TSX –V: WCQ). |
| Bruce McIntyre, P.Geol.(1)(2)(4) | Director | July 2008 | Most recently was an Executive Director of New Zealand Energy Corp. (TSX-V: NZ; OTCQX-NZERF). Previously an independent consultant and President of Wexford Energy Ltd., a private company that provides consulting services for the development and operation of producing natural gas companies (private and public) since 2007. |
| Gregg Vernon, P. Eng.(1)(4) | Director | August 2006 | Currently Interim President and Chief Executive Officer of Petrodorado Energy Ltd. (TSX-V: PDQ) since October 2013. Also a director of Petrodorado Energy Ltd. Currently President of Bochica Oil & Gas Inc. Previously, Interim Chief Operating Officer of Petro Magdalena Energy Corp. (formerly Alange Energy Corp.) from January 2011 to its sale in 2012. Previously, Vice President Business Development of Petro Andina Resources Ltd. |
| Andrew Arthur, P. Geol. | Vice President, Exploration | July 2012 | Consultant for Hemisphere since January 2012. Prior thereto, Technical Lead Oil Business Unit for Enerplus since December 2008 and Vice President, Exploration for PRD Energy Inc. since October 2006. |
| Ian Duncan, P. Eng. | Chief Operating Officer | May 2011 | Previously an Engineer at Hemisphere since January 2011. Prior thereto was an Engineer at Solaris MCI and Talisman Energy Inc. |
| Dorlyn Evancic, CGA | Chief Financial Officer | July 2007 | Previously Chief Financial Officer of Northern Continental Resources Inc. from July 2007 to November 2009. Prior thereto, Chief Financial Officer of Guyana Frontier Mining Corp. from December 2010 to November 2011 and Chief Financial Officer of Gemco Minerals Inc. from March 2005 to February 2010. |
Ashley Ramsden-Wood, P.Eng. | Vice President, Engineering | September 2014 | Consultant for Hemisphere since July 2012. Prior thereto, Reservoir Engineer at Petro-Canada and NAL Resources. |
Notes:
| | (1) | Member of the Reserves Committee. Mr. McIntyre is the Chairman of the Reserves Committee. |
| | (2) | Member of the Compensation/Nominating Committee. Mr. O’Sullivan is Chairman of the Compensation/Nominating Committee. |
| | (3) | Member of the Corporate Governance Committee. Mr. Borowicz is Chairman of Corporate Governance Committee. |
| | (4) | Member of the Audit Committee. Mr. McIntyre is Chairman of the Audit Committee. |
57
Don Simmons, P. Geol. (36 years of age) – President, Chief Executive Officer and Director
Mr. Simmons has extensive experience in petroleum geology and a proven track record of discovering oil and gas in Western Canada and internationally. Initially, Mr. Simmons served as our Vice President Exploration and became President and Chief Executive Officer in February 2008. Prior to joining Hemisphere, Mr. Simmons was a Geologist at a private oil and gas company, Sebring Energy, until its sale in 2007. Prior thereto, he spent five years with EnCana working on various projects in southeast Alberta and Ecuador. Mr. Simmons holds a Bachelor of Science degree in Geological Sciences from Queen’s University and is a member of the Association of Professional Engineers and Geoscientists of Alberta.
Charles O’Sullivan, B.Sc. (71 years of age) – Chairman and Director
Mr. O’Sullivan founded Hemisphere in 1977. He was President from 1977 to 2001 and remains an active Director and Chairman of the Board. From 1977 to 1983 and under Mr. O’Sullivan’s direction, we participated in 86 successful oil and gas wells in the U.S., including the deep Tomcat #1 well. At the time, this well, in the Anadarko Basin, Oklahoma, was the biggest gas well ever drilled in the continental U.S. Mr. O’Sullivan also founded Northern Continental Resources Inc. in 1986, to explore for uranium in the Athabasca Basin of Saskatchewan. He served as Chairman until the company was merged in 2009. Subsequently, the merged company was purchased by Rio Tinto for $640 million in 2011. Mr. O’Sullivan graduated with a Bachelor of Science degree in geophysics in 1965.
Frank Borowicz, QC, CA (Hon) (66 years of age) – Director
Mr. Borowicz has over 35 years of experience in corporate governance and regulatory compliance. He is a retired partner of the international law firm Davis LLP and is a Governor of the Vancouver Board of Trade. He served as Chairman of the BC Industry Training Authority and is an independent director of several public and private companies. Educated at Harvard, Dalhousie and Loyola, Mr. Borowicz is a member of the Institute of Corporate Directors, is a Queens Counsel, and is an honourary member of the Institute of Chartered Accountants.
Bruce McIntyre, P.Geol. (59 years of age) – Director
Mr. McIntyre has over 33 years of oil and gas experience and a proven track record of finding quality oil and gas reserves. Mr. McIntyre was most an Executive Director of New Zealand Energy Corp. Previously, Mr. McIntyre was President and Chief Executive Officer of Sebring Energy Inc., a private Alberta-based exploration and production company that was sold in July 2007. He has also held various other management positions including President and co-founder of Sommer Energy Ltd., President of TriQuest Energy Corp., President and CEO of BXL Energy Ltd. and Exploration Manager for Gascan Resources Ltd. Mr. McIntyre is a member of the American Association of Petroleum Geologists, has a Professional Geologist designation with the Association of Professional Engineers and Geoscientists of Alberta and was the President of the Canadian Society of Petroleum Geologists in 2002.
Gregg Vernon, P.Eng. (60 years of age) – Director
Mr. Vernon is a designated professional engineer with over 35 years of international oil and gas industry experience, including managing and administrating major projects in China, Eastern Canada and South America. He is currently the interim President and Chief Executive Officer of Petrodorado Energy Ltd. and President of Bochica Oil & Gas Inc. (private company). Previously, Mr. Vernon was the interim Chief Operating Officer of PetroMagdalena Energy Corp. (formerly Alange Energy Corp.), a Canadian-based international oil and gas exploration and production company until its sale in 2012. He is one of the founders of Petro Andina Resources Ltd., a Canadian company with operations in South America. He is a University of Alberta graduate with his degree in Engineering and is a member of the Society of Petroleum Engineers.
58
Andrew Arthur, P. Geol. (52 years of age) – Vice President, Exploration
Mr. Arthur has over 24 years of both domestic and international oil and gas industry experience. He began consulting for Hemisphere in January 2012 and was appointed Vice President, Exploration in July 2012. Throughout his career, he has been a key technical member in many exploration and development projects having drilled several hundred wells across the Western Canada Sedimentary Basin. Exposure to all facets of the oil and gas industry has led him to progressively senior exploration roles. Mr. Arthur graduated with his B.Sc. Geology (Honours) from the University of British Columbia in 1985. With sponsorship from the Geological Survey of Canada, he continued at the University of British Columbia, completing his Master of Science in Geology in 1987. Mr. Arthur is a member of the Association of Professional Engineers and Geoscientists of Alberta.
Ian Duncan, P. Eng. (31 years of age) – Chief Operating Officer
Mr. Duncan is a professional engineer with a range of experience in many different areas within the oil and gas industry, including drilling, production and facility operations. Mr. Duncan joined Hemisphere in January 2011 and was quickly promoted to Vice President, Engineering in May 2011. Previously, Mr. Duncan was with Solaris MCI, an engineering consulting firm providing facilities engineering services to Encana in the Horn River Shale Basin. Prior thereto, Mr. Duncan spent four years with Talisman Energy Inc. on various exploration projects including Bakken Oil in Saskatchewan and Marcellus Shale Gas in Pennsylvania. Mr. Duncan holds a Bachelor of Science degree in Chemical Engineering from the University of Alberta and is a member of the Association of Professional Engineers and Geoscientists of Alberta.
Dorlyn Evancic, CGA (50 years of age) – Chief Financial Officer
Mr. Evancic has over 25 years of experience in corporate finance and management which includes senior executive positions in a number of public corporations. He has served as Hemisphere’s Chief Financial Officer since July 2007. Previously, Mr. Evancic was Chief Financial Officer of Guyana Frontier Mining Corp, Chief Financial Officer of Northern Continental Resources, and also a Director and Chief Financial Officer of Gemco Minerals Inc. Prior to working in the natural resource industry, Mr. Evancic’s experience included Director of Administration and Finance of Leisure Canada Inc., Vice President of Operations for Urban Resource Technologies Inc. and Financial Controller of Neptune Food Services. He has been a member of the Certified General Accountants Association since 1989.
Ashley Ramsden-Wood, P.Eng. (35 years of age) – Vice President, Engineering
Ms. Ramsden-Wood is a professional engineer with over 12 years of oil and gas industry experience with a focus on British Columbia, Alberta and Saskatchewan. Ms. Ramsden-Wood joined Hemisphere as a consultant in June 2012 and was appointed as Vice President, Engineering effective September 1, 2014. Ms. Ramsden-Wood started her career at Petro-Canada as a Reservoir Engineer and then moved on to exploitation/area engineering roles at NAL Resources where she gained extensive experience in planning and implementing capital projects and development plans, preparing economic valuations, and evaluating acquisitions. Ms. Ramsden-Wood holds a Bachelor of Science degree in Chemical Engineering from the University of British Columbia and is a member of the Association of Professional Engineers and Geoscientists of Alberta.
4. Family Relationships
There are no family relationships among our directors and executive officers.
5. Other Arrangements
There is no arrangement or understanding with major shareholders, customers, suppliers or others, pursuant to which any person was selected as a director of our Board of Directors or a member of our senior management.
B. Compensation
59
The total compensation plan for our executive officers is comprised of base salary, cash bonus and stock options. The total compensation plan for our directors is comprised of stock options, with the exception of our Chairman who receives an annual retainer. There is no policy or target regarding cash and non-cash elements of our compensation program. The Compensation/Nominating Committee of our Board of Directors annually reviews the total compensation of our executive officers against compensation goals and objectives and makes the recommendations to our Board of Directors concerning the individual components of the executives’ compensation. We do not provide executive officers with any personal benefits, nor do we provide any additional cash compensation to our executive officers for serving as directors.
The following table sets for the short-term benefits, which are primarily salaries and wages, and share-based payments, paid to our officers and directors for our fiscal years ended December 31, 2013 and 2012 of twelve months and ten months, respectively.
| 12 Months Ended
December 31, 2013 | 10 Months Ended
December 31, 2012 |
| Short-term benefits | $750,000 | $540,417 |
| Share-based payments | $125,808 | $196,386 |
Director Compensation
Base Salary or Consulting Fees
During the twelve months ended December 31, 2013 we paid $40,000 in director fees. These fees were charged for services provided by the Chairman of our Board of Directors. The following table sets forth compensation paid to our directors who are not executive officers during the fiscal year ended December 31, 2013.
Name
| Fees
earned
| Option-
based
awards(1) | Non-equity
incentive plan
compensation | Pension
value
| All other
compensation
| Total
|
| Frank S. Borowicz | Nil | Nil(2) | N/A | N/A | Nil | Nil |
| Bruce G. McIntyre | Nil | Nil(2) | N/A | N/A | Nil | Nil |
| Charles N. O’Sullivan | $40,000(3) | Nil(2) | N/A | N/A | Nil | $40,000 |
| Greg M. Sadler | Nil | Nil(2) | N/A | N/A | Nil | Nil |
| Gregg K. Vernon | Nil | Nil(2) | N/A | N/A | Nil | Nil |
Notes:
| | (1) | We have calculated the compensation cost by using the Black-Scholes option pricing model as follows: for options granted during the fiscal year ended December 31, 2013 by assuming a risk-free interest rate of 1.71%, a dividend yield of nil, the expected weekly volatility of our share price of 97.86% and an expected life of the options of 5 years. |
| | (2) | On December 16, 2013, our Board of Directors approved 25,000 stock options be granted to each director who is not a named executive officer; however, these stock options were not issued until January 6, 2014 at $0.55 each with a January 6, 2019 expiry. |
| | (3) | Charles O’Sullivan receives annual compensation of $40,000 as Chairman of our Board of Directors. |
Outstanding Option-Based Awards
We have no pension plan or other arrangement for non-cash compensation for our directors, except incentive stock options. The following table discloses the particulars of all awards outstanding for directors who are not executive officers as at December 31, 2013, including awards granted before this most recently completed fiscal year.
60
Name
| Option-Based Awards |
Number of securities
underlying
unexercised options
(#) | Option
exercise price
($)
| Option expiration
date
| Value of unexercised
in-the-money
options(1)
($) |
Frank S. Borowicz
| 50,000
45,000
50,000
30,000
50,000
25,000 | 0.70
0.40
0.30
0.26
0.25
0.27 | February 7, 2017
May 25, 2016
December 23, 2015
September 30, 2015
March 8, 2015
September 28, 2014 | -
3,150
8,500
6,300
11,000
5,000 |
Bruce G. McIntyre
| 50,000
45,000
50,000
30,000
50,000
25,000 | 0.70
0.40
0.30
0.26
0.25
0.27 | February 7, 2017
May 25, 2016
December 23, 2015
September 30, 2015
March 8, 2015
September 28, 2014 | -
3,150
8,500
6,300
11,000
5,000 |
Charles N. O’Sullivan
| 50,000
45,000
25,000
30,000
100,000 | 0.70
0.40
0.30
0.26
0.25 | February 7, 2017
May 25, 2016
December 23, 2015
September 30, 2015
March 8, 2015 | -
3,150
4,250
6,300
22,000 |
Greg M. Sadler
| 50,000
45,000
50,000
30,000
50,000
25,000 | 0.70
0.40
0.30
0.26
0.25
0.27 | February 7, 2017
May 25, 2016
December 23, 2015
September 30, 2015
March 8, 2015
September 28, 2014 | -
3,150
8,500
6,300
11,000
5,000 |
Gregg K. Vernon
| 50,000
45,000
50,000
30,000
50,000
25,000 | 0.70
0.40
0.30
0.26
0.25
0.27 | February 7, 2017
May 25, 2016
December 23, 2015
September 30, 2015
March 8, 2015
September 28, 2014 | -
3,150
8,500
6,300
11,000
5,000 |
Notes:
| | (1) | Value is calculated based on the difference between the exercise price of the options and the closing price of the common shares on the TSX-Venture on December 31, 2013 of $0.47. |
| | (2) | On December 16, 2013, our Board of Directors approved 25,000 stock options be granted to each director who is not a named executive officer; however, these stock options were not issued until January 6, 2014 at $0.55 each with a January 6, 2019 expiry. |
Executive Officer Compensation
The following table summarizes compensation paid to the executive officers, directly or indirectly, during our three most recently completed fiscal years.
61
Name and
Principal
Position
| Non-equity incentive plan compensation |
Fiscal Year
Ended
| Salary
($)
| Share-
based
awards
($)
| Option-
based
awards(1)
($)
| Annual
incentive
plans
($)
| Long-
term
incentive
plans
($) | All other
compen-
sation
($)
| Total
compen-
sation
($)
|
Don
Simmons
President
and CEO | Dec. 31, 2013
Dec. 31, 2012(2)
Feb. 29, 2012
| 150,000
125,000(3)
125,000(3)
| Nil
Nil
Nil
| Nil(9)
Nil
193,922
| 80,000
50,000
60,000
| Nil
Nil
Nil
| Nil
Nil
Nil
| 230,000
175,000
378,922
|
Dorlyn
Evancic
CFO | Dec. 31, 2013
Dec. 31, 2012(2)
Feb. 29, 2012 | 130,000
108,333(5)
71,667(5) | Nil
Nil
Nil | Nil(9)
Nil
102,110 | 30,000
20,000
30,000 | Nil
Nil
Nil | Nil
Nil
Nil | 160,000
128,333
203,777 |
Ian Duncan(6)
Chief Operating
Officer | Dec. 31, 2013
Dec. 31, 2012(2)
Feb. 29, 2012
| 130,000
104,167(7)
91,667(7)
| Nil
Nil
Nil
| Nil(9)
Nil
134,163
| 40,000
30,000
35,000
| Nil
Nil
Nil
| Nil
Nil
Nil
| 170,000
134,167
260,830
|
Andrew
Arthur
Vice
President,
Exploration | Dec. 31, 2013
Dec. 31, 2012(2)
Feb. 29, 2012
| 130,000
98,771(8)
13,125(8)
| Nil
Nil
Nil
| Nil(9)
196,386
58.577
| 20,000
10,000
Nil
| Nil
Nil
Nil
| Nil
Nil
Nil
| 150,000
305,157
71,703
|
Notes:
| | (1) | We have calculated the compensation cost by using the Black-Scholes option pricing model as follows: for options granted during the fiscal year ended December 31, 2013 by assuming a risk-free interest rate of 1.71%, a dividend yield of nil, the expected weekly volatility of our share price of 97.86% and an expected life of the options of 5 years; for options granted during the ten months ended December 31, 2012 by assuming a risk-free interest rate of 1.18%, a dividend yield of nil, the expected annual volatility of tour share price of 137.48% and an expected life of the options of 3.75 years; and for options granted during the fiscal year ended February 29, 2012 by assuming a risk-free interest rate of 1.54%, a dividend yield of nil, the expected weekly volatility of our share price of 139.72% and an expected life of the options of 5 years. We did not grant any stock options to officers during the ten months ended December 31, 2012. |
| | (2) | Fiscal year ended December 31, 2012 is a ten month period due to a change in year-end. |
| | (3) | Effective January 1, 2012, Don Simmons earned an annual salary of $150,000. |
| | (4) | Dorlyn Evancic was appointed Chief Financial Officer on July 16, 2007. Mr. Evancic entered into an executive employment agreement effective January 1, 2012. Prior to this, we had a management agreement with Mr. Evancic and a private company wholly-owned by Mr. Evancic, pursuant to which said company was paid remuneration of $60,000 per year for providing Mr. Evancic’s services as Chief Financial Officer on a part-time basis. |
| | (5) | Effective January 1, 2012, Dorlyn Evancic earned an annual salary of $130,000. |
| | (6) | Ian Duncan was hired on January 24, 2011 and was appointed Vice President, Engineering effective May 26, 2011 and subsequently appointed as Chief Operating Officer effective September 1, 2014. |
| | (7) | Effective January 1, 2012, Ian Duncan earned an annual salary of $125,000. |
| | (8) | Andrew Arthur was appointed Vice President, Exploration on July 5, 2012 earning an annual salary of $130,000. Prior to this, Mr. Arthur entered a consulting agreement with us on January 15, 2012 and was paid remuneration of $750 per day for providing geological services on a part-time basis. |
| | (9) | On December 16, 2013, our Board of Directors approved 50,000 stock options be granted to each executive officer; however, these stock options were not issued until January 6, 2014 at $0.55 each with a January 6, 2019 expiry. |
Outstanding Option-Based Awards
The following table sets forth the particulars of all awards for each executive officer outstanding as at December 31, 2013, including any awards granted before the most recently completed fiscal year.
62
| Option-Based Awards |
Name
| Number of securities
underlying
unexercised options
| Option
exercise price
($)
| Option expiration
date
| Value of unexercised
in-the-money
options(1)
($) |
Don Simmons
President and Chief
Executive Officer
| 250,000 | 0.70 | February 7, 2017 | - |
| 150,000 | 0.40 | May 25, 2016 | 10,500 |
| 100,000 | 0.30 | December 23, 2015 | 17,000 |
| 250,000 | 0.26 | September 30, 2015 | 52,500 |
| 100,000 | 0.25 | March 8, 2015 | 22,000 |
| 250,000 | 0.27 | September 28, 2014 | 50,000 |
Dorlyn Evancic
Chief Financial Officer
| 150,000 | 0.70 | February 7, 2017 | - |
| 45,000 | 0.40 | May 25, 2016 | 3,150 |
| 100,000 | 0.30 | December 23, 2015 | 17,000 |
| 60,000 | 0.26 | September 30, 2015 | 12,600 |
| 45,000 | 0.25 | March 8, 2015 | 9,900 |
| 50,000 | 0.27 | September 28, 2014 | 10,000 |
Ian Duncan
Chief Operating
Officer | 175,000 | 0.70 | February 7, 2017 | - |
| 100,000 | 0.40 | May 25, 2016 | 7,000 |
| 200,000 | 0.30 | January 27, 2016 | 34,000 |
Andrew Arthur
Vice President,
Exploration | 350,000 | 0.61 | July 5, 2017 | - |
100,000
| 0.70
| February 7, 2017
| -
|
Notes:
| | (1) | Value is calculated based on the difference between the exercise price of the options and the closing price of the common shares on the TSX-V on December 31, 2013 of $0.47. |
| | (2) | On December 16, 2013, our Board of Directors approved 50,000 stock options be granted to each named executive officer; however, these stock options were not issued until January 6, 2014 at $0.55 each with a January 6, 2019 expiry. |
Stock Option Plan
The purpose of the Stock Option Plan is to assist in attracting, retaining and motivating our directors, officers and employees and to closely align the personal interests of such directors, officers and employees with our interests and the interests of our shareholders. The allocation of stock options under the Stock Option Plan is determined by our Board of Directors upon recommendation from the Compensation/Nominating Committee of our Board of Directors which, in determining such allocations, considers such factors as previous grants to individuals, our overall performance, share price, the role and performance of the individual in question, the amount of time directed to our affairs and time expended in serving on our committees.
Options are granted from time to time under the Stock Option Plan as determined by our Board of Directors upon recommendation from the Compensation/Nominating Committee of our Board of Directors, including options granted to executive officers. Previous grants of options under the Stock Option Plan are taken into account when the granting of new options is being considered. There were no repricings of Stock Options under the Stock Option Plan or otherwise during our most recently completed fiscal year ended December 31, 2013. We do not have any share-based awards in place.
63
The following information is intended as a summary of the terms of the Stock Option Plan and is qualified in its entirety by the full text of the Stock Option Plan which is included as an exhibit to this Form 20-F.
- Number of Shares Reserved. The number of common shares that may be reserved for issuance under the Stock Option Plan will be 10% of the issued common shares at the time common shares are reserved for issuance as a result of the grant of a stock option, less any common shares reserved for issuance under stock options granted under share compensation arrangements other than the Stock Option Plan.
- Administration. The Stock Option Plan is to be administered by our Board of Directors or by a committee to which such authority is delegated by our Board of Directors from time to time.
- Option Holders. The Stock Option Plan provides that stock options may be issued to our employees, officers, directors and consultants or any of our subsidiaries, a company wholly-owned by such employee, to a Consultant Entity (as defined in the Stock Option Plan) of a consultant or to eligible tax accounts established by or for the consultant or employee under which he or she is the beneficiary.
- Board Discretion. The Stock Option Plan provides that, generally, the number of shares subject to each stock option, the exercise price, the expiry time, the extent to which such stock option is exercisable and other terms and conditions relating to such stock options shall be determined by our Board of Directors or any committee to which such authority is delegated by our Board of Directors from time to time.
- Maximum Term of Options. Stock options granted under the Stock Option Plan will be for a term not exceeding ten years from the date of grant.
- Maximum Options per Person. The number of common shares reserved for issuance to any one option holder pursuant to stock options granted under the Stock Option Plan during any twelve month period may not exceed 5% (or, in the case of a consultant, 2%) of our issued and outstanding common shares at the time of grant. The number of common shares reserved for issuance to any person who is engaged in investor relations activities is limited to an aggregate of 2% of our issued and outstanding common shares at the time of grant.
- Disinterested Shareholder Approval. Disinterested shareholder approval (as defined in the TSX- V corporate finance manual) is required for the grant to Insiders (as defined in the Stock Option Plan), within a 12 month period, of a number of stock options which, when added to the number of outstanding incentive stock options granted to Insiders within the previous 12 months, exceed 10% of our issued shares.
- No assignment. The stock options may not be assigned or transferred.
- Termination Prior to Expiry. Generally, stock options must expire and terminate on a date stipulated by our Board of Directors or the committee appointed by our Board of Directors at the time of grant and, in any event, must terminate within a reasonable time, which may not exceed 12 months, following the date on which the option holder ceases to be an employee, officer, director or consultant, subject to certain conditions as more fully described in the Stock Option Plan. If an option holder dies, the stock options of the deceased option holder will be exercisable by his or her legal representatives for a period not exceeding 12 months or the balance of the term of the stock options, whichever is shorter. If an option holder has a Disability (as defined in the Stock Option Plan), the stock options of the option holder with that Disability will be exercisable for a period not exceeding 12 months or the balance of the term of the stock options, whichever is shorter.
- Vesting. Subject to the discretion of our Board of Directors or the committee appointed by our Board of Directors, stock options granted under the terms of the Stock Option Plan will fully vest on the date of grant of such stock options. In accordance with the policies of the TSX-V, stock options issued to consultants performing investor relations must vest in stages over a minimum of twelve months with no more than one-quarter (¼) of the stock options vesting in any three (3) month period.
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- Hold Period. Any stock options granted under the terms of the Stock Option Plan where the exercise price is based on any discount to the market price (market price will be the closing trading price of our common shares on the day immediately preceding the date of the option grant, and may be less than this price if it is within the discounts permitted by the TSX-V and applicable regulatory authority) and all shares issued on the exercise of such stock options, if exercised prior to the expiration of the applicable four month TSX-V hold period, will be subject to a four month TSX-V hold period from the date the stock options are granted.
- Full Payment for Shares. We will not issue shares pursuant to stock options granted under the Stock Option Plan unless and until the shares have been fully paid for.
- Reduction of Exercise Price. The exercise price of stock options granted to Insiders may not be decreased without disinterested shareholder approval.
- TSXV’s Rules and Policies Apply. In the event of an inconsistency between the terms of the Stock Option Plan and the rules and policies of the TSX-V and applicable the securities commissions, the rules and policies of the TSX-V and securities commissions will govern.
- Termination of Plan. Subject to all necessary regulatory approvals, our Board of Directors or the committee appointed by our Board of Directors may terminate or suspend the plan.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth details of our compensation plans under which our equity securities were authorized for issuance at the end of our most recently completed fiscal year.
| Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights | Weighted-average
exercise price of
outstanding options,
warrants and rights | Number of securities
remaining available for
future issuance under
equity compensation plans |
| Stock Option Plan | 5,680,000 | $0.48 | 450,749(1) |
Note:
| | (1) | The Stock Option Plan reserves for issuance a maximum of 10% of the 61,307,498 common shares outstanding at December 31, 2013. |
Termination and Change of Control Benefits
We have an executive employment agreement with each executive officer which provides termination notice of twelve months without just cause, including termination as a result of a change of control, for which each executive officer would be compensated by an annual base salary of twelve months plus the average annual bonus amount, if any, paid over the two years immediately prior to termination, in addition to the vesting of all stock options. Under a change of control, the executive employment agreements between us and each executive officer state that the executive agrees to remain employed by us during the period commencing with any act taken and any person, or the announcement of an intention to take such act, which may result in a change of control of the Company and ending with the final conclusion of all matters associated with such act or announcement.
Assuming an executive officer was terminated on December 31, 2013, based on annualized base salaries for the current executive officers as at such time, the following table summarizes the estimated compensation to which each current executive officer would have been entitled.
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Name
| Termination without
just cause | Termination with
change of control | Termination for
cause |
| Don Simmons | $230,000 | $230,000 | Nil |
| Dorlyn Evancic | $160,000 | $160,000 | Nil |
| Ian Duncan | $170,000 | $170,000 | Nil |
| Andrew Arthur | $150,000 | $150,000 | Nil |
All stock options granted to executive officers immediately vest under termination without just cause and termination with change of control. The value of stock options held by each executive officer at December 31, 2013 based on the closing price of the common shares on the TSX-V on December 31, 2013 was $152,000 for Mr. Simmons, $52,650 for Mr. Evancic, $41,000 for Mr. Duncan, and nil for Mr. Arthur.
Pension, Retirement or Similar Benefits
We have no pension plans that provide for payments or benefits to any director or executive officer at, following or in connection with retirement. We also do not have any deferred compensation plans relating to any director or executive officer. Accordingly, we have no amounts set aside or accrued to provide pension, retirement or similar benefits.
C. Board Practices
Term of Office
Each director holds office until the next annual general meeting or until his office is earlier vacated in accordance with the articles or with the provisions of the BCBCA. A director appointed or elected to fill a vacancy on our Board of Directors also holds office until the next annual general meeting. The directors were elected at our Annual General and Special Meeting of the shareholders held on June 6, 2014. The term of office of the officers expires at the discretion of the directors.
Service Contracts
See the information under the heading “Item 6.B. – Termination and Change of Control Benefits” for particulars of Don Simmons’ executive employee agreement with us. Other than as disclosed in this Form 20-F, we do not have any service contracts with directors which provide for benefits upon termination of employment.
Committees of the Board
Our Board of Directors has four committees: Corporate Governance Committee, Compensation/Nominating Committee, Reserves Committee and Audit Committee.
Corporate Governance Committee
The Corporate Governance Committee assists our Board of Directors in the oversight of its corporate governance policies and its responsibilities for good governance practices. The following directors serve on our Corporate Governance Committee: Frank Borowicz (Chairman), Charles O’Sullivan and Don Simmons.
The mandate of the Corporate Governance Committee is to:
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- Assist our Board of Directors in fulfilling their oversight responsibilities with respect to good governance practices as defined in National Policy 58-201 Corporate Governance Guidelines and National Instrument 58-101 Disclosure of Corporate Governance Practices.
- Meet annually and at the request of the Corporate Governance Committee Chairman.
- Annually review and amending (if required) our corporate policies, and making recommendations to our Board of Directors.
- Annually review the corporate governance disclosure in our information circular for recommendation to our Board of Directors.
Compensation/Nominating Committee
The Compensation/Nominating Committee assists our Board of Directors in the oversight of its recruitment, retention and motivation of directors, officers and employees in regard to the competitive conformity of compensation and corporate objectives. The Compensation/Nominating Committee also assists our Board of Directors in the oversight of recruiting new directors, as required. The following directors serve on our Compensation/Nominating Committee: Charles O’Sullivan (Chairman), Bruce McIntyre and Frank Borowicz.
The mandate of the Compensation/Nominating Committee is to:
- Assist our Board of Directors in fulfilling their oversight responsibilities with respect to cash and stock compensation of new and existing executives and employees, and nominating new directors, as required.
- Approve stock option grants for employees and consultants.
- Approve cash compensation and stock option grants for officers and directors to recommend to our Board of Directors for approval.
- Meet annually and at the request of the Compensation/Nominating Committee Chairman.
- Review executive compensation packages of our peer group.
- Annually review the Statement of Executive Compensation disclosure in our Information Circular for recommendation to our Board of Directors.
- Identify the competencies and skills represented by the directors and make recommendations to our Board of Directors.
- Recommend director nominees to shareholders at our annual general meeting.
Reserves Committee
The Reserves Committee assists our Board of Directors in the oversight of the integrity in its petroleum and natural gas reserves. The following directors serve on our Reserves Committee: Bruce McIntyre, (Chairman), Don Simmons and Gregg Vernon.
The mandate of the Reserves Committee is to:
- Assist our Board of Directors in fulfilling their oversight responsibilities with respect to the annual review of our petroleum and natural gas reserves.
- Meet annually to review and approve the year-end independent reserves evaluation and corresponding disclosures as prepared by management under applicable laws.
- Annually review the Statement of Reserves and Other Oil and Natural Gas Information in our Annual Information Form for recommendation to our Board of Directors.
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Audit Committee
The Audit Committee assists our Board of Directors in the oversight of its integrity in financial reporting as outlined in National Instrument 52-110 Audit Committees (“NI 52-110”). The Audit Committee consists of no less than three directors, each of whom is “financially literate” and “independent” as defined under NI 52-110, and is annually appointed by our Board of Directors. The Chair of the Audit Committee is appointed by our Board of Directors at the same time as the member appointment. The following directors serve on our Audit Committee: Bruce McIntyre (Chairman), Frank Borowicz and Gregg Vernon.
The mandate of the Audit Committee is to:
- Assist our Board of Directors in fulfilling their oversight responsibilities with respect to the review of financial statements and other relevant public disclosures, compliance with legal and regulatory requirements relating to financial reporting, the external auditors’ qualifications and independence, and the performance of the internal audit function and the external auditors.
- Meet quarterly to review and approve the quarterly financial statements and management’s discussion and analysis for recommendation to our Board of Directors.
- Meet annually to review and approve the audited annual financial statements and management’s discussion and analysis for recommendation to our Board of Directors.
- Annually review the performance of the external auditors.
- Nominating the external auditors for recommendation to our shareholders at the annual general meeting of the shareholders.
- Advise our Board of Directors on the remuneration of the external auditors based on the time required to complete the audit and preparation of the audited annual financial statements, and the difficulty of the audit and performance of the standard auditing procedures under generally accepted auditing standards, Generally Accepted Accounting Principles of Canada and IFRS and the Public Company Accounting Oversight Board standards.
External Auditors
Our external auditors are the independent representatives of the shareholders, yet are also accountable to our Board of Directors and the Audit Committee. The external auditors complete their audit procedures and reviews with professional independence, free from any undue interference from management or directors. The Audit Committee directs and ensures that the management fully co-operates with the external auditors in the course of carrying out their professional duties. The Audit Committee will have access to direct communications with the external auditors, if required.
The external auditors are prohibited from providing any non-audit services to us, without the written consent of the Audit Committee unless such non-audit services are De Minimus Non-Audit Services as outlined in section 2.4 of NI 52-110. In determining whether the external auditors will be granted permission to provide non-audit services, the Audit Committee is to consider that the benefits to us from the provision of such services, outweighs the risk of any compromise to or loss of the independence of the external auditors in carrying out their auditing mandate.
Notwithstanding the above non-audit services, the external auditors are prohibited at all times from carrying out any of the following services, while they are appointed as our external auditors:
- Act as our agent for the sale of all or substantially all of the undertaking of Hemisphere; and
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- Perform any non-audit consulting work for any of our directors or senior officers in their personal capacity, but not as a director, officer or insider of any other entity that is not associated or related to us.
The Audit Committee has the power to terminate the services of the external auditors, with or without the approval of our Board of Directors, acting reasonably.
Annual Review
The Audit Committee annually reviews the Audit Committee Charter for adequacy and is then recommended to our Board of Directors for approval.
D. Employees
As at December 31, 2013, we had six full-time head office employees and one full-time field employee. Additionally, we had one full-time consultant, five part-time consultants and one full-time field contractor.
E. Share Ownership
Shareholdings of Directors and Executives
The shareholdings of common shares of our directors and executive officers and the percent of common shares outstanding on a diluted basis as at September 30, 2014 are set forth in the following table.
Name of Beneficial Owner | Amount and Nature of Beneficial
Ownership | Percent of Class |
Charles O’Sullivan | 1,766,600(1) | 2.12% |
Frank Borowicz | 837,000(2) | 1.01% |
Bruce McIntyre | 456,000(3) | 0.55% |
Gregg Vernon | 475,000(4) | 0.57% |
Don Simmons | 2,011,100(5) | 2.42% |
Dorlyn Evancic | 705,500(6) | 0.85% |
Andrew Arthur | 640,000(7) | 0.77% |
Ian Duncan | 840,476(8) | 1.01% |
Ashley Ramsden-Wood | 530,000(9) | 0.64% |
Total Directors/Executives | 8,261,676 | 9.93% |
Notes:
| | (1) | Of these shares, 1,491,600 are represented by common shares and 275,000 are represented by vested stock options. |
| | (2) | Of these shares, 530,500 are represented by common shares, 250,000 are represented by vested stock options, 25,000 are represented by unvested stock options, and 6,500 are represented by share purchase warrants. |
| | (3) | Of these shares, 181,000 are represented by common shares, 250,000 are represented by vested stock options, and 25,000 are represented by unvested stock options. |
| | (4) | Of these shares, 200,000 are represented by common shares, 250,000 are represented by vested stock options, and 25,000 are represented by unvested stock options. |
| | (5) | Of these shares, 861,100 are represented by common shares, 900,000 are represented by vested stock options, and 250,000 are represented by unvested stock options. |
| | (6) | Of these shares, 205,500 are represented by common shares, 450,000 are represented by vested stock options, and 50,000 are represented by unvested stock options. |
| | (7) | Of these shares, 140,000 are represented by common shares and 400,000 are represented by vested stock options. 100,000 of these shares are vested stock options owned by Caerleon Resources Inc., a private company owned by Andrew Arthur. |
| | (8) | Of these shares, 233,026 are represented by common shares, 525,000 are represented by vested stock options, 50,000 are represented by unvested stock options and 18,165 are represented by share purchase warrants. |
| | (9) | Of these shares, 30,000 are represented by common shares, 300,000 are represented by vested stock options, and 200,000 are represented by unvested stock options. |
All percentages are based on 83,192,273 fully diluted shares outstanding as of September 30, 2014.
Stock Options Outstanding
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Our directors and executive officers to whom outstanding stock options have been granted, the number of common shares subject to such options, the price per option, the grant date and the expiration date are set forth in the following table as at September 30, 2014. All options set forth in the following table are vested unless otherwise noted.
Name
| Options held
(#) | Price per option
($) | Grant date
| Expiration date
|
Don Simmons
| 250,000*
50,000
250,000
150,000
100,000
250,000
100,000
| 0.65
0.55
0.70
0.40
0.30
0.26
0.25
| September 29, 2014
January 6, 2014
February 7, 2012
May 25, 2011
December 23, 2010
September 30, 2010
March 8, 2010
| September 29, 2019
January 6, 2019
February 7, 2017
May 25, 2016
December 23, 2015
September 30, 2015
March 8, 2015
|
Dorlyn Evancic
| 50,000*
50,000
150,000
45,000
100,000
60,000
45,000
| 0.65
0.55
0.70
0.40
0.30
0.26
0.25
| September 29, 2014
January 6, 2014
February 7, 2012
May 25, 2011
December 23, 2010
September 30, 2010
March 8, 2010
| September 29, 2019
January 6, 2019
February 7, 2017
May 25, 2016
December 23, 2015
September 30, 2015
March 8, 2015
|
Ian Duncan
| 50,000*
50,000
175,000
100,000
200,000 | 0.65
0.55
0.70
0.40
0.30 | September 29, 2014
January 6, 2014
February 7, 2012
May 25, 2011
January 27, 2011 | September 29, 2019
January 6, 2019
February 7, 2017
May 25, 2016
January 27, 2016 |
Andrew Arthur
| 50,000
350,000
100,000 | 0.55
0.61
0.70 | January 6, 2014
July 5, 2012
February 7, 2012 | January 6, 2019
July 5, 2017
February 7, 2017 |
| Ashley Ramsden-Wood | 200,000*
50,000
250,000 | 0.65
0.55
0.50 | September 29, 2014
January 6, 2014
March 8, 2013 | September 29, 2019
January 6, 2019
March 8, 2018 |
Frank S. Borowicz
| 25,000*
25,000
50,000
45,000
50,000
30,000
50,000 | 0.65
0.55
0.70
0.40
0.30
0.26
0.25 | September 29, 2014
January 6, 2014
February 7, 2012
May 25, 2011
December 23, 2010
September 30, 2010
March 8, 2010
| September 29, 2019
January 6, 2019
February 7, 2017
May 25, 2016
December 23, 2015
September 30, 2015
March 8, 2015
|
Bruce G. McIntyre
| 25,000*
25,000
50,000
45,000
50,000
30,000
50,000 | 0.65
0.55
0.70
0.40
0.30
0.26
0.25 | September 29, 2014
January 6, 2014
February 7, 2012
May 25, 2011
December 23, 2010
September 30, 2010
March 8, 2010
| September 29, 2019
January 6, 2019
February 7, 2017
May 25, 2016
December 23, 2015
September 30, 2015
March 8, 2015
|
Charles N. O’Sullivan
| 25,000
50,000
45,000
25,000
30,000
100,000 | 0.55
0.70
0.40
0.30
0.26
0.25 | January 6, 2014
February 7, 2012
May 25, 2011
December 23, 2010
September 30, 2010
March 8, 2010 | January 6, 2019
February 7, 2017
May 25, 2016
December 23, 2015
September 30, 2015
March 8, 2015 |
| Gregg K. Vernon | 25,000*
25,000
50,000
45,000
50,000
30,000
50,000 | 0.65
0.55
0.70
0.40
0.30
0.26
0.25 | September 29, 2014
January 6, 2014
February 7, 2012
May 25, 2011
December 23, 2010
September 30, 2010
March 8, 2010 | September 29, 2019
January 6, 2019
February 7, 2017
May 25, 2016
December 23, 2015
September 30, 2015
March 8, 2015 |
Total
Directors/Executives | 4,325,000 | | | |
Note:
(*) represents stock options that are unvested as of the effective date of this document and fully vest on January 30, 2015.
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Our employees are eligible to participate in our Stock Option Plan. A summary of the some of the relevant parts of the Stock Option Plan is given under the heading “Item 6.B. – Stock Option Plan”.
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
A. Major Shareholders
To the best of our knowledge, there are no persons or company who beneficially own, directly or indirectly, or exercise control or direction over, securities carrying more than 5% of the voting rights attached to any class of our voting securities, except for Alpha Capital, which owns 4,400,000 shares representing 5.9% of the voting rights of our common shares as of the date of this Form 20-F.
The voting rights of our major shareholders do not differ from the voting rights of holders of the common shares who are not our major shareholders.
To the best of our knowledge, there has been no significant change in the percentage ownership held by any major shareholders during the past three years.
As of May 31, 2014, our registrar and transfer agent reported we have 49 registered holders of our shares who are U.S. residents, with combined holdings of 1,175,406 common shares.
To the extent of our knowledge, we are not directly or indirectly owned or controlled by another corporation, any foreign government, or any other natural or legal person, severally or jointly.
As of the date of this Form 20-F, there were no arrangements known to us which may, at a subsequent date, result in a change of control.
B. Related Party Transactions
Other than in the ordinary course of business, since the beginning of the preceding three financial years, there have been no transactions or loans between us and:
| (a) | enterprises that directly or indirectly through one or more intermediaries, control or are controlled by, or are under common control with, us; |
| | |
| (b) | associates, meaning unconsolidated enterprises in which we have a significant influence or which have significant influence over us; |
| | |
| (c) | individuals owning, directly or indirectly, an interest in our voting power that gives them significant influence over us, and close members of any such individual’s family; |
| | |
| (d) | key management personnel, that is, those persons having authority and responsibility for planning, directing and controlling our activities, including our directors and senior management and close members of such individuals’ families; and |
| | |
| (e) | enterprises in which a substantial interest in the voting power is owned, directly or indirectly, by any person described in (c) or (d) or over which such a person is able to exercise significant influence, including enterprises owned by our directors or major shareholders and enterprises that have a member of our key management in common. |
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Compensation
For information regarding compensation for our directors and senior management, please see the information under the heading “Item 6.B. Compensation”.
C. Interests of Experts and Counsel
Not applicable.
ITEM 8. FINANCIAL INFORMATION
A. Financial Statements and Other Financial Information
Our financial statements are stated in Canadian dollars and are prepared in accordance with IFRS, as issued by the IASB, the application of which, in our case, conforms in all material respects for the periods presented with the United States generally accepted accounting principles.
The following financial statements and notes thereto are filed with this Form 20-F:
Our unaudited condensed interim financial statements for the three and six months ended June 30, 2014, which comprise the condensed statements of financial position as at June 30, 2014 and December 31, 2013, the condensed statements of income and comprehensive income, cash flows, changes in shareholders’ equity for the three and six months ended June 30, 2014 and 2013, and notes to the unaudited condensed interim financial statements.
Our audited financial statements for the twelve months ended December 31, 2013 and ten months ended December 31, 2012, which comprise the statements of financial position as at December 31, 2013 and 2012, and the statements of income and comprehensive income, changes in shareholders’ equity and cash flows for the twelve months ended December 31, 2013, the ten months ended December 31, 2012 and the twelve months ended February 29, 2012, the independent auditors’ report by Smythe Ratcliffe LLP, Chartered Accountants, a summary of significant accounting policies and the notes to the audited financial statements.
These financial statements can be found under the heading “Item 18. Financial Statements”.
Export Sales
Export sales do not constitute any portion of our sales.
Legal Proceedings
To our knowledge, there have not been any legal or arbitration proceedings, including those relating to bankruptcy, receivership or similar proceedings, those involving any third party, and governmental proceedings pending or known to be contemplated, which may have, or have had in the recent past, significant effect our financial position or profitability.
Also, to our knowledge, there have been no material proceedings in which any director, any member of senior management, or any of our affiliates is either a party adverse to us or our subsidiaries or has a material interest adverse to us or our subsidiaries.
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Policy on Dividend Distributions
We have not declared or paid any dividends since our incorporation. Payments of dividends in the future will be dependent on, among other things, our cash flow, results of operations and financial condition, the need for funds to finance ongoing operations and other considerations, as our Board of Directors considers relevant.
B. Significant Changes
None.
ITEM 9. THE OFFER AND LISTING
A. Offer and Listing Details
Our common shares are listed for trading on the TSX-V under the symbol “HME”. Our high and low market prices of the common shares on the TSX-V for the five most recent full financial years, for each full financial quarter for the two most recent full financial years and for each of the most recent six months are set forth in the following table.
| TSX-V ($) |
| High | Low |
| Year ended | | |
| December 31, 2013 | 0.69 | 0.40 |
| December 31, 2012(1) | 0.85 | 0.46 |
| February 29, 2012 | 0.86 | 0.34 |
| February 28, 2011 | 0.42 | 0.17 |
| February 28, 2010 | 0.40 | 0.185 |
| Quarter ended | | |
September 30, 2014 | 0.79 | 0.63 |
June 30, 2014 | 0.83 | 0.67 |
| March 31, 2014 | 0.85 | 0.49 |
| December 31, 2013 | 0.69 | 0.45 |
| September 30, 2013 | 0.68 | 0.42 |
| June 30, 2013 | 0.55 | 0.40 |
| March 31, 2013 | 0.61 | 0.40 |
| December 31, 2012 | 0.75 | 0.53 |
| September 30, 2012 | 0.72 | 0.51 |
| June 30, 2012 | 0.71 | 0.46 |
| Month ended | | |
September 2014 | 0.75 | 0.63 |
August 2014 | 0.72 | 0.64 |
July 2014 | 0.79 | 0.65 |
| June 2014 | 0.79 | 0.67 |
| May 2014 | 0.78 | 0.67 |
| April 2014 | 0.83 | 0.67 |
Note:
| (1) | Due to our fiscal year-end change, this fiscal year represents a ten month period. |
On September 30, 2014, the closing price of our common shares on the TSX-V was $0.64 per common share.
Transfers of Common Shares
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Our common shares, no par value, are in registered form and the transfer of our common shares is managed by our transfer agent in Canada, Computershare Investor Services Inc., located at 510 Burrard Street, Vancouver, BC V6C 3A8, (Tel: 800-564-6253).
B. Plan of Distribution
Not applicable.
C. Markets
Our common shares, no par value, are currently traded on the TSX-V under the symbol “HME”.
There is currently no market for the common shares in the United States, and there is no assurance that any will develop or, if developed, will be maintained.
D. Selling Shareholders
Not applicable.
E. Dilution
Not applicable.
F. Expenses of the Issue
Not applicable.
ITEM 10. ADDITIONAL INFORMATION
A. Share Capital
Our authorized share capital consists of an unlimited number of common shares without par value.
Common Shares
We are authorized to issue an unlimited number of common shares without par value. As at December 31, 2013, there were 61,307,498 common shares issued and outstanding. As of September 30, 2014 there were 75,368,498 common shares issued and outstanding. No common shares are held by or on behalf of us. The holders of the common shares are entitled to one vote for each common share held on all matters to be voted on by such holders.
The holders of common shares are entitled to receive, pro rata, such dividends as may be declared by our Board of Directors out of funds legally available therefore. The holders of common shares are entitled to receive, pro rata, the remainder of our property on a liquidation in the event of our liquidation, dissolution or winding-up. There are no pre-emptive rights or redemption rights attached to the common shares.
The following table summarizes our issuances of common shares for the past three fiscal years and from January 1 to September 30, 2014.
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| Fiscal Year or Period | Nature of Share Issuance | Number of Shares | Gross Proceeds |
January 1, 2014 through
September 30, 2014 | Bought-Deal Equity Financing(2)
Stock Option Exercise | 13,333,500
690,000 | 10,000,125
220,850 |
December 31, 2013
| Private Placement(3)
Bought-Deal Equity Financing(4) | 86,900
7,259,550 | 56,485
4,300,453 |
December 31, 2012(1)
| Warrant Exercise
Stock Option Exercise
Private Placement(5) | 1,752,047
5,000
1,829,300 | 1,051,228
1,250
1,189,045 |
February 29, 2012
| Private Placement(6)
Warrant Exercise
Stock Option Exercise
Private Placement(7)
Property Acquisition(8)
Private Placement(9) | 3,955,350
5,447,000
105,000
2,200,000
100,000
12,495,669 | 1,651,140
1,666,815
27,050
1,430,000
35,000
8,626,210 |
Notes:
| | (1) | Due to our fiscal year-end change, this fiscal year represents a ten month period. |
| | (2) | On May 14, 2014, we closed a bought-deal equity financing consisting of 13,333,500 common shares at a price of $0.75 per common share for aggregate gross proceeds of $10,000,125. In conjunction with the closing of the bought- deal equity financing, we paid $700,009 in finders’ fees. |
| | (3) | In January 2013, we closed the second and final tranche of a private placement consisting of 86,900 units at a price of $0.65 per unit for gross proceeds of $56,485. Each unit consisted of one common share and one-half of one share purchase warrant. Each whole warrant entitled the holder to purchase one additional common share at a price of $0.90 until January 25, 2014. In conjunction with the closing of the private placement, $456 in finders’ fees and legal fees were paid and 700 finders’ warrants were issued. Each warrant entitled the holder to purchase one common share at a price of $0.90 until January 25, 2014. |
| | (4) | On December 9, 2013, we closed a bought deal equity financing consisting of 4,182,550 units, comprised of one common share and one-half of one share purchase warrant, at a price of $0.55 per unit and 3,077,000 common shares to be issued on a flow-through basis at a price of $0.65 per flow-through share for aggregate gross proceeds of $4,300,453. Each whole warrant entitles the holder to acquire one of our common shares at a price of $0.75 until December 9, 2014. In conjunction with the closing of the private placement, $571,137 in share issuance costs including commissions and legal fees were paid. |
| | (5) | On December 20, 2012, we closed a private placement consisting of 1,829,300 units at a price of $0.65 per unit for gross proceeds of $1,189,045. Each unit consisted of one common share and one-half of one share purchase warrant. Each whole warrant entitled the holder to purchase one additional common share at the price of $0.90 until December 20, 2013. In conjunction with the closing of the private placement, $82,643 in finders’ fees and legal fees were paid and 114,191 finders’ warrants were issued. Each warrant entitled the holder to purchase one common share at a price of $0.90 until December 20, 2013. |
| | (6) | On April 29, 2011, we closed a private placement consisting of 2,575,350 units at a price of $0.40 per unit for gross proceeds of $1,030,140. Each unit consisted of one common share and one-half of one non-transferrable share purchase warrant. Each whole warrant entitles the holder to purchase one additional common share at a price of $0.60 until October 29, 2012. In the same private placement, we issued 1,380,000 flow-through units at a price of $0.45 per flow- through common share for gross proceeds of $621,000. Each flow-through unit consists of one flow-through common share and one-half of one share purchase warrant. Each whole warrant entitles the holder to purchase one additional non-flow-through common share at a price of $0.60 until October 29, 2012. As part of the finders’ fee agreement, $119,074 cash was paid. Additionally, 240,247 finders’ warrants were issued to the agents with each finders’ warrant having the same terms as the placement warrants described above. |
| | (7) | On November 10, 2011, we closed a non-brokered private placement consisting of 2,200,000 flow-through shares at a price of $0.65 per share for gross proceeds of $1,430,000. Under the terms of the financing, $68,705 in finders’ fees were paid and 132,650 finders’ warrants were issued. Each warrant entitles the holder to purchase one common share at a price of $0.80 until November 10, 2012. |
| | (8) | On November 21, 2011, we closed the acquisition of an additional working interest in our Trutch property in northeast British Columbia. Total consideration for the acquisition was $250,000 in cash and the issuance of 100,000 shares. The shares were issued at $0.35 per share, for total share consideration of $35,000. |
| | (9) | On January 27, 2012, we closed a brokered private placement that consisted of 12,323,157 units sold at $0.70 for aggregate subscription proceeds of $8,626,210. Each unit consisted of one common share and one-half of one transferable share purchase warrant, with each whole warrant entitling the holder to purchase one additional common share at a price of $0.95 until January 27, 2014. We paid commissions and fees totaling $603,835, and issued 862,620 agent warrants. Each agent warrant entitled the holder to purchase one common share at a price of $0.70 until January 27, 2014. Additionally, 172,512 Corporate Finance units were issued, each having the same terms as the units sold pursuant to the brokered private placement. These units were measured at $0.70, for total consideration of $120,758. Share issuance costs in the same amount were recorded. |
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Warrants
As of June 30, 2014, we had the following number of warrants to purchase our common shares outstanding.
| Number | Exercise Price | Expiry Date |
| 2,053,775 | $0.75 | December 10, 2014 |
| Total: 2,053,775 | | |
As of December 31, 2013, we had the following number of warrants to purchase our common shares outstanding.
| Number | Exercise Price | Expiry Date |
| 44150 | $0.90 | January 25, 2014 |
| 6,247,834 | $0.95 | January 27, 2014 |
| 862,620 | $0.70 | January 27, 2014 |
| 2,091,275 | $0.75 | December 10, 2014 |
| Total: 9,245,879 | | |
Stock Options
As of June 30, 2014, we had the following number of options to purchase our common shares outstanding.
| Number Outstanding | Number Exercisable | Exercise Price | Expiry Date |
315,000 | 315,000 | $0.27 | September 28, 2014 |
435,000 | 435,000 | $0.25 | March 8, 2015 |
490,000 | 490,000 | $0.26 | September 30, 2015 |
375,000 | 375,000 | $0.30 | December 23, 2015 |
200,000 | 200,000 | $0.30 | January 27, 2016 |
50,000 | 50,000 | $0.38 | February 9, 2016 |
475,000 | 475,000 | $0.40 | May 26, 2016 |
50,000 | 50,000 | $0.48 | July 5, 2016 |
1,500,000 | 1,500,000 | $0.70 | February 8, 2017 |
75,000 | 75,000 | $0.65 | April 24, 2017 |
425,000 | 425,000 | $0.61 | July 5, 2017 |
250,000 | 250,000 | $0.50 | March 8, 2018 |
660,000 | 660,000 | $0.55 | January 6, 2019 |
Total: 5,300,000 | Total: 5,300,000 | | |
As of December 31, 2013, we had the following number of options to purchase our common shares outstanding.
| Number Outstanding | Number Exercisable | Exercise Price | Expiry Date |
| 445,000 | 445,000 | $0.27 | September 28, 2014 |
| 485,000 | 485,000 | $0.25 | March 8, 2015 |
| 520,000 | 520,000 | $0.26 | September 30, 2015 |
| 425,000 | 425,000 | $0.30 | December 23, 2015 |
| 200,000 | 200,000 | $0.30 | January 27, 2016 |
| 50,000 | 50,000 | $0.38 | February 9, 2016 |
| 520,000 | 520,000 | $0.40 | May 26, 2016 |
| 50,000 | 50,000 | $0.48 | July 5, 2016 |
| 1,550,000 | 1,550,000 | $0.70 | February 8, 2017 |
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| 75,000 | 75,000 | $0.65 | April 24, 2017 |
| 425,000 | 425,000 | $0.61 | July 5, 2017 |
| 250,000 | 250,000 | $0.50 | March 8, 2018 |
| 685,000 | 685,000 | $0.55 | January 6, 2019 |
| Total: 5,680,000 | Total: 5,680,000 | | |
Shareholder Rights Plan
Background of the Shareholder Rights Plan
We have adopted a shareholder rights plan (the “Shareholder Rights Plan”), the terms and conditions of which are set out in the Shareholders Rights Plan Agreement between us and Computershare Investor Services Inc., as amended (the “Shareholders Rights Plan Agreement”), dated March 9, 2010. The Shareholder Rights Plan was approved by our shareholders at our Annual General Meeting held on August 17, 2010, extended for two years at our Annual General and Special Meeting held on August 17, 2012 and extended for two years at our Annual General and Special Meeting held on June 6, 2014. Our Shareholder Rights Plan was not adopted in response to any proposal to acquire us.
The following information is intended as a summary of the terms of the Shareholder Rights Plan and is qualified in its entirety by the full text of the Shareholders Rights Plan Agreement which is included as an exhibit to this Form 20-F. Capitalized terms used but not defined in this section have the definitions set forth in the Shareholder Rights Plan Agreement.
Issuance of Rights
To implement the Shareholder Rights Plan, our Board of Directors authorized the issuance of one Right in respect of each common share outstanding at 4:00 p.m. (Vancouver time) on March 9, 2010 (the “Record Time”) and of one Right in respect of each common share issued after the Record Time and prior to the earlier of the Separation Time (as defined below) and the Expiration Time (as defined below). For purposes of this description, the term "common shares" includes both our common shares and any other securities of ours into which such common shares may be subdivided, reclassified or changed from time to time.
The issuance of rights is not dilutive and will not affect reported earnings or cash flow per common share until the Rights separate from the underlying common shares and become exercisable or until the exercise of the Rights. The issuance of the Rights did not change the manner in which shareholders currently trade their common shares, and is not intended to interfere with our ability to undertake equity offerings in the future. Shareholders do not have to return their share certificate(s) in order to have the benefit of the Rights.
Certificates and Transferability
Prior to the Separation Time, the Rights will be evidenced by a legend imprinted on certificates for common shares issued after the Record Time. Rights are also attached to common shares that were outstanding on the Record Time, although share certificates issued prior to the Record Time do not (and need not) bear such a legend. Shareholders are not required to return their certificates in order to have the benefit of the Rights. Prior to the Separation Time, Rights will trade together with our common shares and will not be exercisable or transferable separately from common shares. From and after the Separation Time and prior to the expiration time of the Rights, the Rights will be transferable separately from the common shares, and will be evidenced by separate certificates or other written acknowledgement ("Rights Certificates").
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Separation Time
Until the Separation Time, the Rights will trade together with the common shares, will be represented by the common share certificate and will not be exercisable. After the Separation Time, the Rights will become exercisable, will be evidenced by Rights certificates, and will be transferable separately from the common shares.
The “Separation Time” is the close of business on the tenth Trading Day (or such later day as may be determined by the Board) after the earlier of:
- the “Stock Acquisition Date”, which is the date of the first public announcement that a Person has become an Acquiring Person (as defined below);
- the date of the commencement of, or first public announcement (provided such announcement is made after the Record Time) of an intention of any Person (other than us or any of our Subsidiaries, if any) to commence, a Take-over Bid (other than a Permitted Bid or a Competing Permitted Bid) to acquire Beneficial Ownership of 20% or more of our Voting Shares (defined below); and
- the date upon which a Take-Over Bid ceases to be a Permitted Bid or Competing Bid.
For purposes the Shareholder Rights Plan, “Voting Shares” means our common shares and any other shares of capital stock or voting interests entitled to vote generally in the election of all our directors.
Promptly following the Separation Time, separate Rights Certificates will be mailed to each holder of record of the common shares as of the Separation Time or who subsequently becomes a holder of record of Common Shares upon the exercise of rights attaching to Convertible Securities outstanding at the Stock Acquisition Date (other than an Acquiring Person and, in respect of any Rights Beneficially Owned by such Acquiring Person which are not held of record by such Acquiring Person, the holder of record of such Rights. Thereafter, the Rights Certificates alone will evidence the Rights.
Rights Exercise Privilege
Each Right will entitle the holder, from and after the Separation Time and prior to the Expiration Time, to purchase one of our common shares at a price of $0.15, subject to certain anti-dilution adjustments. The Rights will not be exercisable until the Separation Time. Upon the occurrence of a Flip-in Event (as defined below), each Right held by an entity that is not a person who has acquired, other than pursuant to an exemption available under the Shareholder Rights Plan or pursuant to a Permitted Bid, Beneficial Ownership of 20% or more of our Voting Shares (such person, an “Acquiring Person”) will become exercisable and may be traded separately from the common shares.
Flip-in Event
A “Flip-in Event” is any transaction pursuant to which any Person becomes an Acquiring Person. Except as set out below, upon the occurrence of any Flip-in Event, from and after the close of business on the tenth (10th) Trading Day following the Stock Acquisition Date:
- any Rights Beneficially Owned by the Acquiring Person and Affiliates, Associates and Transferees of the Acquiring Person or any Person acting jointly or in concert with the Acquiring Person will become void; and
- each Right (other than Rights which are void) will entitle the holder thereof to purchase that number of common shares having an aggregate market price on the date of consummation or occurrence of such Flip-in Event equal to twice the relevant Exercise Price.
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Accordingly, a Flip-in Event that is not approved by our Board of Directors will result in significant dilution to an Acquiring Person. Our Board of Directors may, with shareholder approval, at any time prior to the occurrence of a Flip-in Event, elect to redeem all but not less than all of the outstanding Rights at a redemption price of $0.0001 per Right.
Permitted Bid
A bidder can make a takeover bid and acquire common shares without triggering a Flip-In Event under the Shareholder Rights Plan if the takeover bid qualifies as a Permitted Bid. A “Permitted Bid” is a Take-over Bid which is made by means of a Take-over Bid circular and which also complies with the following requirements:
| | (a) | the Take-over Bid is made to all registered holders of Voting Shares; |
| | (b) | the Take-over Bid contains, and the take-up and payment for securities tendered or deposited thereunder is subject to, an irrevocable and unqualified condition that no Voting Shares shall be taken up or paid for pursuant to the Take-over Bid prior to the close of business on the date which is not less than sixty (60) days after the date of the Take-over Bid and only if at such date more than 50% of the Voting Shares held by Independent Shareholders (defined below), including those held by the Acquiring Person, shall have been deposited or tendered pursuant to the Take- over Bid and not withdrawn; |
| | (c) | the Take-over Bid contains an irrevocable and unqualified provision that, unless the Take-over Bid is withdrawn, Voting Shares may be deposited pursuant to such Take-over Bid at any time during the period of time specified in (b) above and that any Voting Shares deposited pursuant to the Take-over Bid may be withdrawn until taken up and paid for; and |
| | (d) | the Take-over Bid contains an irrevocable and unqualified provision that if, on the date on which Voting Shares may be taken up and paid for, more than 50% of the Voting Shares held by Independent Shareholders shall have been deposited or tendered pursuant to the Take-over Bid and not withdrawn, the Offeror will make a public announcement of that fact and the Take-over Bid will remain open for deposits and tenders of Voting Shares for not less than ten (10) business days from the date of such public announcement. |
For purposes of the foregoing, an Independent Shareholders” means holders of Voting Shares other than:
| | (a) | any Acquiring Person; |
| | (b) | any Offeror; |
| | (c) | any Associate or Affiliate of any Acquiring Person or Offeror; |
| | (d) | any Person acting jointly or in concert with any Acquiring Person or any Offeror; and |
| | (e) | any employee benefit plan, deferred profit sharing plan, stock participation plan or trust for the benefit of employees of the Corporation or any Subsidiary of the Corporation but excluding in any event a plan or trust in respect of which the employee directs the manner in which the Voting Shares are to be voted and directs whether the Voting Shares be tendered to a Take-over Bid. |
If an Offeror successfully completes a Permitted Bid, the Shareholder Rights Plan provides that the Rights will be redeemed at $0.0001 per Right.
A Permitted Bid, even if not approved by the Board of Director, may be taken directly to our shareholders. Shareholder approval will not be required for a Permitted Bid. Instead our shareholders will initially have sixty (60) days to tender or to deposit their shares. If more than 50% of the Voting Shares (other than shares Beneficially Owned by the Offeror) have been tendered or deposited and not withdrawn by the end of such sixty (60) day period, the Permitted Bid must be extended for a further period of ten (10) business days to allow initially disapproving shareholders to deposit their shares if they so choose.
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The Shareholder Rights Plan also allows for a competing Permitted Bid (a "Competing Permitted Bid") to be made while a Permitted Bid is in existence. A Competing Permitted Bid must satisfy all of the requirements of a Permitted Bid, except that it may expire on the same date as the Permitted Bid, subject to the requirement that it be outstanding for a minimum period of 35 days (the minimum period required under Canadian securities laws). A Competing Permitted Bid is considered a Permitted Bid for the purposes of the Shareholder Rights Plan.
Permitted Lock-Up Agreements
A person will not become an Acquiring Person by virtue of having entered into an agreement (a "Permitted Lock-Up Agreement") with a shareholder pursuant to which the shareholder agrees to deposit or tender common shares to a takeover bid (the "Lock-Up Bid") made by that person, provided that the agreement meets certain requirements, including that:
- the terms of the agreement are publicly disclosed and a copy of the agreement is publicly available not later than the date of the Lock-Up Bid or, if the Lock-Up Bid has not been made prior to the date on which such agreement is entered into, not later than the first business day following the date of such agreement;
- the shareholder who has agreed to tender common shares to the Lock-Up Bid made by the other party to the agreement is permitted to terminate its obligation under the agreement, and to terminate any obligation with respect to the voting of such common shares, in order to tender common shares to another takeover bid or transaction where the offer price or value of the consideration payable under the other takeover bid or transaction is greater than the price or value of the consideration per common share at which the shareholder has agreed to deposit or tender common shares to the Lock-Up Bid, or is greater than a specified minimum which is not more than 7% higher than the price or value of the consideration per common share at which the shareholder has agreed to deposit or tender common shares under the Lock-Up Bid; and
- no break-up fees, top-up fees, penalties, expenses or other amounts that exceed in the aggregate the greater of (i) 2.5% of the price or value of the consideration payable under the Lock-Up Bid and (ii) 50% of the increase in consideration resulting from another takeover bid or transaction, shall be payable by the locked-up shareholder if the shareholder fails to deposit or tender common shares to the Lock-Up Bid, withdraws common shares previously tendered thereto, or supports another transaction.
Waiver and Redemption
If a potential Offeror does not wish to make a Permitted Bid, it can negotiate with, and obtain the prior approval of, our Board of Directors to make a bid pursuant to a Take-over Bid circular on terms which our Board of Directors considers fair to all shareholders. In such circumstances, our Board of Directors may waive the application of the Shareholder Rights Plan to the transaction, thereby allowing such bid to proceed without dilution of the Offeror, and will be deemed to have waived the application of the Shareholder Rights Plan to all other contemporaneous bids made by Take-over Bid circular.
Protection Against Dilution
The Exercise Price, the number and nature of securities that may be purchased upon the exercise of Rights and the number of Rights outstanding are subject to adjustment from time to time to prevent dilution in the event of stock dividends or subdivisions, consolidations, reclassifications or other changes in the outstanding common shares, pro rata distributions to holders of common shares and other circumstances where adjustments are requirement to appropriately protect the interests of the holders of Rights.
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Exemptions for Investment Advisors
Investment advisors (for client accounts), trust companies (acting in their capacity as trustees or administrators), statutory bodies whose business includes the management of funds (for employee benefit plans, pension plans, or insurance plans of various public bodies), and administrators or trustees of registered pension plans or funds and agents or agencies of the Government of Canada or any Province thereof acquiring greater than 20% of the outstanding common shares are effectively exempted from triggering a Flip-in Event, provided they are not, and have not announced an intention to, in fact making, either alone or jointly or in concert with any other person, a takeover bid.
Duties of Our Board of Directors
The adoption of the Shareholder Rights Plan will not in any way lessen or affect the duty of the Board to act honestly and in good faith with a view to our best interests. The Board of Directors, when a takeover bid or similar offer is made, will continue to have the duty and power to take such actions and make such recommendations to shareholders as are considered appropriate.
Amendment
We may, from time to time, supplement or amend the Shareholder Rights Plan Agreement without shareholder approval to correct clerical or typographical errors or to maintain the validity of the Shareholder Rights Plan Agreement as a result of a change in law. All other amendments require shareholder approval.
Canadian Federal Income Tax Consequences
We will not include any amount in income for the purposes of the Income Tax Act (Canada) as a result of the issuance of the Rights. A right to acquire additional amounts of our shares granted to a shareholder does not constitute a taxable benefit to the recipient that must be included in income or that is subject to non-resident withholding tax if all holders of common shares are granted such right. A Right was issued in respect of each common share outstanding at the Record Time. Therefore, holders of common shares should not have an income inclusion or liability for non-resident withholding tax upon the issuance of the Rights. In any event, we consider that the Rights have a negligible monetary value because we are not aware of any acquisition or take-over bid which would give rise to a Flip-in Event.
Although a holder of a Right may have income or may be subject to non-resident withholding tax if the Rights become exercisable, are exercised or redeemed, we consider the likelihood of such an event occurring to be remote.
B. Memorandum and Articles of Association
Incorporation
We are incorporated under the BCBCA. Our British Columbia incorporation number is BC00172034. A copy of our articles (the “articles”) has been filed as an exhibit to this Form 20-F.
Objects and Purposes of the Company
The articles do not contain a description of our objects and purposes.
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Voting on Certain Proposal, Arrangement, Contract or Compensation by Directors
Other than as disclosed below, the articles do not restrict directors’ power to (a) vote on a proposal, arrangement or contract in which the directors are materially interested or (b) to vote compensation to themselves or any other members of their body in the absence of an independent quorum.
The BCBCA does, however, contain restrictions in this regard. The BCBCA provides that a director who holds a disclosable interest in a contract or transaction into which we have entered or proposes to enter is not entitled to vote on any directors’ resolution to approve that contract or transaction, unless all the directors have a disclosable interest in that contract or transaction, in which case any or all of those directors may vote on such resolution. A director who holds a disclosable interest in a contract or transaction into which we have entered or proposes to enter and who is present at the meeting of directors at which the contract or transaction is considered for approval may be counted in the quorum at the meeting whether or not the director votes on any or all of the resolutions considered at the meeting. A director or senior officer generally holds a disclosable interest in a contract or transaction if (a) the contract or transaction is material to us; (b) we have entered, or proposed to enter, into the contract or transaction, and (c) either (i) the director or senior officer has a material interest in the contract or transaction or (ii) the director or senior officer is a director or senior officer of, or has a material interest in, a person who has a material interest in the contract or transaction. A director or senior officer does not hold a disclosable interest in a contract or transaction merely because the contract or transaction relates to the remuneration of the director or senior officer in that person’s capacity as director, officer, employee or agent of the Company or of an affiliate of the Company.
Borrowing Powers of Directors
The articles provide that we, if authorized by our Board of Directors, may:
- borrow money in the manner and amount, on the security, from the sources and on the terms and conditions that they consider appropriate;
- issue bonds, debentures and other debt obligations either outright or as security for any of our liabilities or obligations or any other person and at such discounts or premiums and on such other terms as they consider appropriate;
- guarantee the repayment of money by any other person or the performance of any obligation of any other person; and
- mortgage, charge, whether by way of specific or floating charge, grant a security interest in, or give other security on, the whole or any part of our present and future assets and our undertaking.
Qualifications of Directors
Under the articles, a director is not required to hold a share in our capital as qualification for his or her office but must be qualified as required by the BCBCA to become, act or continue to act as a director.
Share Rights
Please see the summary of our authorized capital under the heading “Item 10.A. Share Capital – Common Shares”.
Procedures to Change the Rights of Shareholders
The articles state that we may by resolution of our directors: (a) create one or more classes or series of shares or, if none of the shares of a class or series of shares are allotted or issued, eliminate that class or series of shares; (b) increase, reduce or eliminate the maximum number of shares that we are authorized to issue out of any class or series of shares or establish a maximum number of shares that we are authorized to issue out of any class or series of shares for which no maximum is established; (c) if we are authorized to issue shares of a class of shares with par value: (i) decrease the par value of those shares, (ii) if none of the shares of that class of shares are allotted or issued, increase the par value of those shares, (iii) subdivide all or any of our unissued or fully paid issued shares with par value into shares of smaller par value, or (iv) consolidate all or any of our unissued or fully paid issued shares with par value into shares of larger par value; (d) subdivide all or any of our unissued or fully paid issued shares without par value; (e) change all or any of our unissued or fully paid issued shares with par value into shares without par value or all or any of our unissued shares without par value into shares with par value; (f) alter the identifying name of any of our shares; (g) consolidate all or any of our unissued or fully paid issued shares without par value; or (h) otherwise alter our shares or authorized share structure when required or permitted to do so by the BCBCA.
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Meetings
Each director holds office until the next annual general meeting or until his office is earlier vacated in accordance with the articles or with the provisions of the BCBCA. A director appointed or elected to fill a vacancy on our Board of Directors also holds office until the next annual general meeting.
The articles provide that the annual meetings of shareholders must be held at such time in each calendar year and not more than 15 months after the last annual general meeting and at such place as our Board of Directors may from time to time determine. The directors may, at any time, call a meeting of the shareholders.
The holders of not less than five percent of our issued shares that carry the right to vote at a meeting may requisition our directors to call a meeting of shareholders for the purposes stated in the requisition.
Under the articles, the quorum for the transaction of business at a meeting of our shareholders is one or more persons, present in person or by proxy.
The articles state that in addition to those persons who are entitled to vote at a meeting of the shareholders, the only other persons entitled to be present at the meeting are our directors, our president (if any), our secretary (if any), our lawyer or auditor, any persons invited to be present at the meeting by our directors or by the chair of the meeting and any person entitled or required under the BCBCA or the articles to be present at the meeting.
Limitations on Ownership of Securities
Except as provided in the Investment Canada Act (Canada), there are no limitations specific to the rights of non-Canadians to hold or vote the common shares under the laws of Canada or British Columbia, or in the our charter documents.
Change in Control
There are no provisions in the articles or in the BCBCA that would have the effect of delaying, deferring or preventing a change in our control, and that would operate only with respect to a merger, acquisition or corporate restructuring involving us or our subsidiaries.
Ownership Threshold
The articles or the BCBCA do not contain any provisions governing the ownership threshold above which shareholder ownership must be disclosed. Securities legislation in Canada, however, requires that we disclose in our information circular for our annual general meeting, holders who beneficially own more than 10% of our issued and outstanding shares. Most state corporation statutes do not contain provisions governing the threshold above which shareholder ownership must be disclosed. Upon the effectiveness of this Form 20-F, we expect that the United States federal securities laws will require us to disclose, in an annual report on Form 20-F, holders who own 5% or more of our issued and outstanding shares.
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C. Material Contracts
There are no other contracts, other than those disclosed in this Form 20-F and those entered into in the ordinary course of our business, that are material to us and which were entered into in the most recently completed fiscal year or which were entered into before the most recently completed fiscal year but are still in effect as of the date of this Form 20-F:
- Stock Option Plan. The Stock Option Plan was last approved by our shareholders on June 6, 2014. See the discussion under the heading “Item 6.B. – Stock Option Plan”.
- Shareholders Rights Plan Agreement. The Shareholders Rights Plan Agreement sets forth the terms of the Shareholder Rights Plan, which was last approved by our shareholders and extended for two years at our Annual General and Special Meeting Held on August 17, 2012. See the discussion under the heading “Item 6.B. – Shareholder Rights Plan.”
- Demand Operating Credit Facility. We have a demand operating credit facility in the amount of $10,500,000 with ATB under a commitment letter dated September 25, 2013, as amended effective June 23, 2014. The demand operating credit facility is secured by a general security agreement and a floating charge on all our lands. The demand operating credit facility bears interest at ATB’s prime rate plus 1.75% as well as a standby charge for any undrawn funds.
- Executive Employment Agreement with Don Simmons. We entered into an executive employment agreement with Don Simmons effective March 23, 2010 pursuant to which he agreed to serve as our President and Chief Executive Officer
- Executive Employment Agreement with Dorlyn Evancic. We entered into an executive employment agreement with Dorlyn Evancic effective January 1, 2012 pursuant to which he agreed to serve as our Chief Financial Officer.
- Executive Employment Agreement with Ian Duncan . We entered into an executive employment agreement with Ian Duncan effective January 24, 2011 pursuant to which he agreed to serve as our Vice President, Engineering and was subsequently appointed as Chief Operating Officer effective September 1, 2014.
- Executive Employment Agreement with Andrew Arthur. We entered into an executive employment agreement with Andrew Arthur effective July 5, 2012 pursuant to which he agreed to serve as our Vice President, Exploration.
- Executive Employment Agreement with Ashley Ramsden- Wood. We entered into an executive employment agreement with Ashley Ramsden-Wood effective September 1, 2014 pursuant to which she agreed to serve as our Vice President, Engineering.
D. Exchange Controls
There are no government laws, decrees or regulations in Canada that restrict the export or import of capital or that affect the remittance of dividends, interest or other payments to non-resident holders of the common shares. Any remittances of dividends to U.S. residents and to other non-residents are, however, subject to withholding tax. See the information under the heading “Item 10.E. Taxation”.
There are no limitations under the laws of Canada or in our organizing documents on the right of foreigners to hold or vote our securities, except that the Investment Canada Act may require review and approval by the Minister of Industry (Canada) of certain acquisitions of our “control” by a “non-Canadian”. The threshold for acquisitions of control is generally defined as being one-third or more of our voting shares. If the investment is potentially injurious to national security it may be subject to review under the Investment Canada Act notwithstanding the percentage interest acquired or amount of the investment. “Non-Canadian” generally means an individual who is not a Canadian citizen, or a corporation, partnership, trust or joint venture that is ultimately controlled by non-Canadians.
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E. Taxation
Certain Canadian Federal Income Taxation Considerations
The following summarizes the principal Canadian federal income tax consequences applicable to the holding and disposition of our common shares by a holder who, for purposes of the Income Tax Act (Canada) (the “Tax Act”) and the Canada-U.S. Tax Convention (as defined below under “Certain United States Federal Income Tax Considerations”), is, or is deemed to be, resident in the United States, holds the common shares as capital property and does not use or hold the common shares in the course of carrying on a business in Canada (a “Holder”). The common shares will generally be considered to be capital property unless the Holder holds the common shares in the course of carrying on a business, or acquires the common shares in a transaction or transactions considered to be an adventure in the nature of trade.
This summary is based on the current provisions of the Tax Act, the regulations thereunder, all amendments thereto publicly proposed by the government of Canada, the published administrative practices of the Canada Revenue Agency and the current provisions of the Canada-U.S. Tax Convention. This summary does not otherwise take into account or anticipate any changes in law, whether by way of legislative, judicial or administrative action or interpretation, nor does it address any provincial, territorial or foreign (including without limitation, any United States) tax considerations.
This summary is of a general nature only and it is not intended to be, nor should it be construed to be, legal or tax advice to any particular Holder. Accordingly, Holders are urged to consult with their own tax advisors about the specific tax consequences of acquiring, holding and disposing of common shares.
A Holder will be liable to pay a Canadian withholding tax on every dividend that is or is deemed to be paid or credited to the Holder on the Holder’s common shares. The rate of withholding tax under the Tax Act is 25% of the gross amount of the dividend paid. However, the Canada-U.S. Tax Convention will reduce that withholding tax rate, provided the Holder is eligible for benefits under the Canada-U.S. Tax Convention. Where applicable, the general rate of withholding tax under the Canada-U.S. Tax Convention will be 15% of the gross amount of the dividend, but if the Holder is a company that owns at least 10% of the voting stock of the Company, the rate of withholding tax will be reduced to 5%. The Company will be required to withhold the applicable tax from the dividend payable to the Holder and to remit that tax to the Receiver General for Canada on account of the Holder. Not all persons who are residents of the United States will qualify for benefits under the Canada-U.S. Tax Convention. Holders are advised to consult their own tax advisors in this regard.
A Holder will generally not be subject to tax under the Tax Act in respect of a capital gain realized on the disposition or deemed disposition of a common share, unless the common share constitutes “taxable Canadian property” to the Holder for purposes of the Tax Act. Provided that the common shares are listed on a “designated stock exchange” for purposes of the Tax Act (which includes the TSX) at the time of disposition, the common shares will generally not constitute “taxable Canadian property” to a Holder unless, at any time during the 60-month period immediately preceding the disposition (i) the Holder, together with persons with whom the Holder does not deal at “arm’s length” for the purposes of the Tax Act, owned 25% or more of the issued shares of any class of shares of the Company and, as such time, (ii) more than 50% of the fair market value of the common shares was derived directly or indirectly from one or a combination of real or immovable property situated in Canada, “Canadian resource properties” or “timber resource properties” (as such terms are defined in the Tax Act), or options or interests in respect of any such properties.
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Even if the common shares are taxable Canadian property to a Holder, any taxable capital gain resulting from the disposition of such shares will not be included in computing the Holder’s income for the purposes of the Tax Act if the shares constitute “treaty protected property” for the purpose of the Tax Act.
Provided the common shares are listed at the time of disposition on the TSX or other “recognized stock exchange” for purposes of the Tax Act, a Holder who disposes of common shares will not be required to satisfy the obligations imposed under Section 116 of the Tax Act and, as such, the purchaser of such shares will not be required to withhold any amount on the purchase price paid.
Holders whose common shares may constitute “taxable Canadian property” should consult their own tax advisors.
Certain United States Federal Income Tax Considerations
The following is a general summary of certain material U.S. federal income tax considerations applicable to a U.S. Holder (as defined below) arising from and relating to the acquisition, ownership and disposition of our common shares.
This summary is for general information purposes only and does not purport to be a complete analysis or listing of all potential U.S. federal income tax considerations that may apply to a U.S. Holder arising from and relating to the acquisition, ownership, and disposition of our common shares. In addition, this summary does not take into account the individual facts and circumstances of any particular U.S. Holder that may affect the U.S. federal income tax consequences to such U.S. Holder, including without limitation specific tax consequences to a U.S. Holder under an applicable tax treaty. Accordingly, this summary is not intended to be, and should not be construed as, legal or U.S. federal income tax advice with respect to any U.S. Holder. This summary does not address the U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences to U.S. Holders of the acquisition, ownership, and disposition of our common shares. In addition, except as specifically set forth below, this summary does not discuss applicable tax reporting requirements. Each prospective U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences relating to the acquisition, ownership, and disposition of our common shares.
No legal opinion from U.S. legal counsel or ruling from the Internal Revenue Service (the “IRS”) has been requested, or will be obtained, regarding the U.S. federal income tax consequences of the acquisition, ownership, and disposition of our common shares. This summary is not binding on the IRS, and the IRS is not precluded from taking a position that is different from, and contrary to, the positions taken in this summary. In addition, because the authorities on which this summary are based are subject to various interpretations, the IRS and the U.S. courts could disagree with one or more of the conclusions described in this summary.
Scope of this Summary
Authorities
This summary is based on the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations (whether final, temporary, or proposed), published rulings of the IRS, published administrative positions of the IRS, the Convention Between Canada and the United States of America with Respect to Taxes on Income and on Capital, signed September 26, 1980, as amended (the “Canada-U.S. Tax Convention”), and U.S. court decisions that are applicable and, in each case, as in effect and available, as of the date of this document. Any of the authorities on which this summary is based could be changed in a material and adverse manner at any time, and any such change could be applied on a retroactive or prospective basis which could affect the U.S. federal income tax considerations described in this summary. This summary does not discuss the potential effects, whether adverse or beneficial, of any proposed legislation.
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U.S. Holders
For purposes of this summary, “U.S. Holder” means a beneficial owner of our common shares that is for U.S. federal income tax purposes:
- an individual who is a citizen or resident of the United States;
- a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) organized under the laws of the United States, any state thereof or the District of Columbia;
- an estate whose income is subject to U.S. federal income taxation regardless of its source; or
- a trust that (1) is subject to the primary supervision of a court within the United States and the control of one or more U.S. persons for all substantial decisions or (2) has a valid election in effect under applicable Treasury Regulations to be treated as a U.S. person.
U.S. Holders Subject to Special U.S. Federal Income Tax Rules Not Addressed
This summary does not address the U.S. federal income tax considerations applicable to U.S. Holders that are subject to special provisions under the Code, including, but not limited to, the following U.S. Holders that: (a) are tax-exempt organizations, qualified retirement plans, individual retirement accounts, or other tax-deferred accounts; (b) are financial institutions, underwriters, insurance companies, real estate investment trusts, or regulated investment companies; (c) are broker-dealers, dealers, or traders in securities or currencies that elect to apply a mark-to-market accounting method; (d) have a “functional currency” other than the U.S. dollar; (e) own our common shares as part of a straddle, hedging transaction, conversion transaction, constructive sale, or other arrangement involving more than one position; (f) acquired our common shares in connection with the exercise of employee stock options or otherwise as compensation for services; (g) hold our common shares other than as a capital asset within the meaning of Section 1221 of the Code (generally, property held for investment purposes); or (h) own, have owned or will own (directly, indirectly, or by attribution) 10% or more of the total combined voting power of our outstanding shares. This summary also does not address the U.S. federal income tax considerations applicable to U.S. Holders who are: (a) U.S. expatriates or former long-term residents of the U.S.; (b) persons that have been, are, or will be a resident or deemed to be a resident in Canada for purposes of the Income Tax Act (Canada) (the “Tax Act”); (c) persons that use or hold, will use or hold, or that are or will be deemed to use or hold our common shares in connection with carrying on a business in Canada; (d) persons whose our common shares constitute “taxable Canadian property” under the Tax Act; or (e) persons that have a permanent establishment in Canada for the purposes of the Canada-U.S. Tax Convention. U.S. Holders that are subject to special provisions under the Code, including, but not limited to, U.S. Holders described immediately above, should consult their own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences relating to the acquisition, ownership and disposition of our common shares.
If an entity or arrangement that is classified as a partnership (or other “pass-through” entity) for U.S. federal income tax purposes holds our common shares, the U.S. federal income tax consequences to such entity and the partners (or other owners) of such entity generally will depend on the activities of the entity and the status of such partners (or owners). This summary does not address the tax consequences to any such owner. Partners (or other owners) of entities or arrangements that are classified as partnerships or as “pass-through” entities for U.S. federal income tax purposes should consult their own tax advisors regarding the U.S. federal income tax consequences arising from and relating to the acquisition, ownership, and disposition of our common shares.
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Ownership and Disposition of Common Shares
The following discussion is subject to the rules described below under the heading “Passive Foreign Investment Company Rules.”
Taxation of Distributions
A U.S. Holder that receives a distribution, including a constructive distribution, with respect to a common share will be required to include the amount of such distribution in gross income as a dividend (without reduction for any foreign income tax withheld from such distribution) to the extent of our current or accumulated “earnings and profits”, as computed for U.S. federal income tax purposes. To the extent that a distribution exceeds our current and accumulated “earnings and profits”, such distribution will be treated first as a tax-free return of capital to the extent of a U.S. Holder's tax basis in our common shares and thereafter as gain from the sale or exchange of such common shares (see “Sale or Other Taxable Disposition of Common Shares” below). However, we may not maintain the calculations of our earnings and profits in accordance with U.S. federal income tax principles, and each U.S. Holder may have to assume that any distribution by us with respect to our common shares will constitute ordinary dividend income. Dividends received on our common shares by corporate U.S. Holders generally will not be eligible for the “dividends received deduction”. Subject to applicable limitations and provided we are eligible for the benefits of the Canada-U.S. Tax Convention, dividends paid by us to non-corporate U.S. Holders, including individuals, generally will be eligible for the preferential tax rates applicable to long-term capital gains for dividends, provided certain holding period and other conditions are satisfied, including that we not be classified as a PFIC (as defined below) in the tax year of distribution or in the preceding tax year. The dividend rules are complex, and each U.S. Holder should consult its own tax advisor regarding the application of such rules.
Sale or Other Taxable Disposition of Common Shares
A U.S. Holder will recognize gain or loss on the sale or other taxable disposition of our common shares in an amount equal to the difference, if any, between (a) the amount of cash plus the fair market value of any property received and (b) such U.S. Holder’s tax basis in such common shares sold or otherwise disposed of. Any such gain or loss generally will be capital gain or loss, which will be long-term capital gain or loss if, at the time of the sale or other disposition, such common shares are held for more than one year.
Preferential tax rates apply to long-term capital gains of a U.S. Holder that is an individual, estate, or trust. There are currently no preferential tax rates for long-term capital gains of a U.S. Holder that is a corporation. Deductions for capital losses are subject to significant limitations under the Code.
Passive Foreign Investment Company Rules
If we were to constitute a PFIC for any year during a U.S. Holder’s holding period, then certain potentially adverse rules would affect the U.S. federal income tax consequences to a U.S. Holder resulting from the acquisition, ownership and disposition of our common shares. We believe that we were not a PFIC during the tax year ended December 31, 2013 and, based on current business plans and financial expectations, we expect that we should not be a PFIC for the current tax year and for the foreseeable future. However, PFIC classification is fundamentally factual in nature, generally cannot be determined until the close of the tax year in question, and is determined annually. Additionally, the analysis depends, in part, on the application of complex U.S. federal income tax rules, which are subject to differing interpretations. Consequently, there can be no assurance that we have never been and will not become a PFIC for any tax year during which U.S. Holders hold our common shares.
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In addition, in any year in which we are classified as a PFIC, a U.S. Holder will be required to file an annual report with the IRS containing such information as Treasury Regulations and/or other IRS guidance may require. A failure to satisfy such reporting requirements may result in an extension of the time period during which the IRS can assess a tax. U.S. Holders should consult their own tax advisors regarding the requirements of filing such information returns under these rules, including the requirement to file an IRS Form 8621.
We generally will be a PFIC under Section 1297 of the Code if, after the application of certain “look-through” rules with respect to subsidiaries in which we hold at least 25% of the value of such subsidiary, for a tax year, (a) 75% or more of our gross income for such tax year is passive income (the “income test”) or (b) 50% or more of the value of our assets either produce passive income or are held for the production of passive income (the “asset test”), based on the quarterly average of the fair market value of such assets. “Gross income” generally includes all sales revenues less the cost of goods sold, plus income from investments and from incidental or outside operations or sources, and “passive income” generally includes, for example, dividends, interest, certain rents and royalties, certain gains from the sale of stock and securities, and certain gains from commodities transactions. Active business gains arising from the sale of commodities generally are excluded from passive income if substantially all (85% or more) of a foreign corporation’s commodities are stock in trade or inventory, depreciable property used in a trade or business or supplies regularly used or consumed in the ordinary course of its trade or business, and certain other requirements are satisfied.
If we were a PFIC in any tax year during which a U.S. Holder held our common shares, such holder generally would be subject to special rules with respect to “excess distributions” made by us on our common shares and with respect to gain from the disposition of our common shares. An “excess distribution” generally is defined as the excess of distributions with respect to the common shares received by a U.S Holder in any tax year over 125% of the average annual distributions such U.S. Holder has received from us during the shorter of the three preceding tax years, or such U.S. Holder’s holding period for our common shares. Generally, a U.S. Holder would be required to allocate any excess distribution or gain from the disposition of our common shares ratably over its holding period for our common shares. Such amounts allocated to the year of the disposition or excess distribution would be taxed as ordinary income, and amounts allocated to prior tax years would be taxed as ordinary income at the highest tax rate in effect for each such year and an interest charge at a rate applicable to underpayments of tax would apply.
While there are U.S. federal income tax elections that sometimes can be made to mitigate these adverse tax consequences (including the “QEF Election” under Section 1295 of the Code and the “Mark-to-Market Election” under Section 1296 of the Code), such elections are available in limited circumstances and must be made in a timely manner.
U.S. Holders should be aware that, for each tax year, if any, that we are a PFIC, we can provide no assurance that we will satisfy the record keeping requirements of a PFIC, or that we will make available to U.S. Holders the information such U.S. Holders require to make a QEF Election with respect to us or any subsidiary that also is classified as a PFIC. U.S. Holders should consult their own tax advisors regarding the potential application of the PFIC rules to the ownership and disposition of our common shares, and the availability of certain U.S. tax elections under the PFIC rules.
Additional Considerations
Additional Tax on Passive Income
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Certain individuals, estates and trusts whose income exceeds certain thresholds will be required to pay a 3.8% Medicare surtax on “net investment income” including, among other things, dividends and net gain from disposition of property (other than property held in certain trades or businesses). U.S. Holders should consult their own tax advisors regarding the effect, if any, of this tax on their ownership and disposition of our common shares.
Receipt of Foreign Currency
The amount of any distribution paid to a U.S. Holder in foreign currency, or on the sale, exchange or other taxable disposition of our common shares, generally will be equal to the U.S. dollar value of such foreign currency based on the exchange rate applicable on the date of receipt (regardless of whether such foreign currency is converted into U.S. dollars at that time). A U.S. Holder will have a basis in the foreign currency equal to its U.S. dollar value on the date of receipt. Any U.S. Holder who converts or otherwise disposes of the foreign currency after the date of receipt may have a foreign currency exchange gain or loss that would be treated as ordinary income or loss, and generally will be U.S. source income or loss for foreign tax credit purposes. Different rules apply to U.S. Holders who use the accrual method with respect to foreign currency received upon the sale, exchange or other taxable disposition of our common shares. Each U.S. Holder should consult its own U.S. tax advisor regarding the U.S. federal income tax consequences of receiving, owning, and disposing of foreign currency.
Foreign Tax Credit
Subject to the PFIC rules discussed above, a U.S. Holder that pays (whether directly or through withholding) Canadian income tax with respect to dividends paid on our common shares generally will be entitled, at the election of such U.S. Holder, to receive either a deduction or a credit for such Canadian income tax. Generally, a credit will reduce a U.S. Holder’s U.S. federal income tax liability on a dollar-for-dollar basis, whereas a deduction will reduce a U.S. Holder’s income subject to U.S. federal income tax. This election is made on a year-by-year basis and applies to all foreign taxes paid (whether directly or through withholding) by a U.S. Holder during a year.
Complex limitations apply to the foreign tax credit, including the general limitation that the credit cannot exceed the proportionate share of a U.S. Holder’s U.S. federal income tax liability that such U.S. Holder’s “foreign source” taxable income bears to such U.S. Holder’s worldwide taxable income. In applying this limitation, a U.S. Holder’s various items of income and deduction must be classified, under complex rules, as either “foreign source” or “U.S. source.” Generally, dividends paid by a foreign corporation should be treated as foreign source for this purpose, and gains recognized on the sale of stock of a foreign corporation by a U.S. Holder should be treated as U.S. source for this purpose, except as otherwise provided in an applicable income tax treaty, and if an election is properly made under the Code. However, the amount of a distribution with respect to our common shares that is treated as a “dividend” may be lower for U.S. federal income tax purposes than it is for Canadian federal income tax purposes, resulting in a reduced foreign tax credit allowance to a U.S. Holder. In addition, this limitation is calculated separately with respect to specific categories of income. The foreign tax credit rules are complex, and each U.S. Holder should consult its own U.S. tax advisor regarding the foreign tax credit rules.
Backup Withholding and Information Reporting
Under U.S. federal income tax law, certain categories of U.S. Holders must file information returns with respect to their investment in, or involvement in, a foreign corporation. For example, U.S. return disclosure obligations (and related penalties) are imposed on individuals who are U.S. Holders that hold certain specified foreign financial assets in excess of certain threshold amounts. The definition of specified foreign financial assets includes not only financial accounts maintained in foreign financial institutions, but also, unless held in accounts maintained by a financial institution, any stock or security issued by a non-U.S. person, any financial instrument or contract held for investment that has an issuer or counterparty other than a U.S. person and any interest in a foreign entity. U. S. Holders may be subject to these reporting requirements unless they hold our common shares in an account at certain financial institutions. Penalties for failure to file certain of these information returns are substantial. U.S. Holders should consult their own tax advisors regarding the requirements of filing information returns, including the requirement to file an IRS Form 8938.
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Payments made within the U.S. or by a U.S. payor or U.S. middleman, of dividends on, and proceeds arising from the sale or other taxable disposition of, our common shares will generally be subject to information reporting and backup withholding tax, at the rate of 28%, if a U.S. Holder (a) fails to furnish such U.S. Holder’s correct U.S. taxpayer identification number (generally on Form W-9), (b) furnishes an incorrect U.S. taxpayer identification number, (c) is notified by the IRS that such U.S. Holder has previously failed to properly report items subject to backup withholding tax, or (d) fails to certify, under penalty of perjury, that such U.S. Holder has furnished its correct U.S. taxpayer identification number and that the IRS has not notified such U.S. Holder that it is subject to backup withholding tax. However, certain exempt persons generally are excluded from these information reporting and backup withholding rules. Backup withholding is not an additional tax. Any amounts withheld under the U.S. backup withholding tax rules will be allowed as a credit against a U.S. Holder’s U.S. federal income tax liability, if any, or will be refunded, if such U.S. Holder furnishes required information to the IRS in a timely manner.
The discussion of reporting requirements set forth above is not intended to constitute a complete description of all reporting requirements that may apply to a U.S. Holder. A failure to satisfy certain reporting requirements may result in an extension of the time period during which the IRS can assess a tax, and under certain circumstances, such an extension may apply to assessments of amounts unrelated to any unsatisfied reporting requirement. Each U.S. Holder should consult its own tax advisor regarding the information reporting and backup withholding rules.
F. Dividends and Paying Agents
There is no dividend restriction; however, we have not declared any dividends since our inception and do not anticipate that it will do so in the foreseeable future. We currently intend to retain future earnings, if any, to finance the development of our business. Any future payment of dividends or distributions will be determined by our Board of Directors on the basis of the earnings, financial requirements and other relevant factors.
There is no special procedure for non-resident holders to claim dividends. Any remittances of dividends to U.S. residents and to other non-residents are, however, subject to withholding tax. See the information under the heading “Item 10.E. Taxation”.
G. Statement by Experts
Our audited financial statements for the twelve months ended December 31, 2013 and ten months ended December 31, 2012 included in this Form 20-F have been audited by Smythe Ratcliffe LLP, Chartered Accountants, with a business address at 700 – 355 Burrard Street, Vancouver, British Columbia, Canada V6C 2G8, as stated in their reports appearing in this Form 20-F and have been so included in reliance upon the reports of such firm given their authority as experts in accounting and auditing.
H. Documents on Display
Upon the effectiveness of this registration statement, we will be subject to the informational requirements of the Securities Exchange Act of 1934. You may read and copy any of our reports and other information at, and obtain copies upon payment of prescribed fees from, the Public Reference Room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. In addition, the SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.
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The documents concerning us referred to in this registration statement may be viewed at our executive offices during normal business hours.
We are required to file reports and other information with the securities commissions in Canada. You are invited to read and copy any reports, statements or other information, other than confidential filings, that we file with the provincial securities commissions. These filings are also electronically available from SEDAR at www.sedar.com, the Canadian equivalent of the SEC’s electronic document gathering and retrieval system.
I. Subsidiary Information
We have no subsidiaries.
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See the discussion under the heading “Item 5. Operating and Financial Review and Prospects – Financial Instruments and Risk Management” as well as Note 5 to our audited financial statements for the twelve months ended December 31, 2013, ten months ended December 31, 2012 and twelve months ended February 29, 2012 filed as part of this Form 20-F.
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
None.
PART II
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
None.
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
The Shareholders Rights Plan Agreement between us and Computershare Investor Services Inc., as amended, was originally executed on March 9, 2010. The Shareholder Rights Plan was thereafter approved by our shareholders at our Annual General Meeting held on August 17, 2010, extended for two years at our Annual General and Special Meeting held on August 17, 2012 and extended for two years at our Annual General and Special Meeting held on June 6, 2014. The Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection with any take-over bid for us. The Shareholder Rights Plan provides our Board of Directors and the shareholders with more time to fully consider any unsolicited take-over bid for us; it will allow our Board of Directors to pursue, if appropriate, other alternatives to maximize shareholder value and it will allow additional time for competing bids to emerge. Existing securities legislation in Canada requires a take-over bid to remain open for only thirty-five (35) days. Our Board of Directors does not believe that this period is sufficient to permit them to determine whether there may be alternatives available to maximize shareholder value or whether other bidders may be prepared to pay more for our shares than the Offeror (as defined in the Shareholder Rights Plan). In addition, our Board of Directors is concerned that, while securities legislation has addressed many concerns of unequal treatment of shareholders, there remains the possibility that control or effective control may be acquired pursuant to a private agreement in which a small number of shareholders dispose of shares at a premium to market price which is not shared with the other shareholders. Also, a person may slowly accumulate shares through stock exchange acquisitions which may result, over time, in an acquisition of control without payment of fair value for control or fair sharing of any control premium among all shareholders. The Shareholder Rights Plan addresses these concerns by applying to all acquisitions of 20% or more of our common shares. See the discussion under the heading “Item 6.B. – Shareholder Rights Plan.”
On March 12, 2014, our Board of Directors approved and adopted the Advance Notice Policy, which was approved by the shareholders on June 6, 2014. The purpose of the Advance Notice Policy is to provide shareholders, the Board of Directors and management with a clear framework for nominating directors. The Advance Notice Policy fixes a deadline by which holders of record of our common shares must submit director nominations to us prior to any annual general or special meeting of shareholders and sets forth the information that a shareholder must include in the notice to the Company for the notice to be in proper written form in order for any director nominee to be eligible for election at any annual or special meeting of shareholders. A complete copy of the Advance Notice Policy is included as an exhibit to this Form 20-F.
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ITEM 15. CONTROLS AND PROCEDURES
Not applicable.
ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT
Not applicable.
ITEM 16B. CODE OF ETHICS
Not applicable.
ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Not applicable.
ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES
Not applicable.
ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS
Not applicable.
ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT
None.
ITEM 16G. CORPORATE GOVERNANCE
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Not applicable.
ITEM 16H. MINE SAFETY DISCLOSURE
Not applicable.
PART III
ITEM 17. FINANCIAL STATEMENTS
See “Item 18. Financial Statements”.
ITEM 18. FINANCIAL STATEMENTS
See the “Index to Financial Statements” on page 95 of this Form 20-F for a list of the financial statements filed as part of this Form 20-F.
ITEM 19. EXHIBITS
| Exhibit | | |
| Number | | Description |
| 1.1 | | Articles* |
| 1.2 | | Notice of Articles* |
| 1.3 | | Certificate of change of name to Hemisphere Energy Corporation dated April 24, 2009* |
| 1.4 | | Certificate of change of name to Northern Hemisphere Development Corp. dated January 14, 2000* |
| 1.5 | | Certificate of change of name to Hemisphere Development Corp. dated May 18, 1978* |
| 2.1 | | Shareholders Rights Plan Agreement between Hemisphere and Computershare Investor Services Inc. dated March 9, 2010, as amended* |
| 4.1 | | McDaniel & Associates - Report of Third Party for the Evaluation of Oil and Gas Resources attributed to selected Hemisphere Energy Corporation's interests in Western Canada |
4.2 | | Sproule Associates Limited – Evaluation of the P&NG Reserves of Hemisphere Energy Corporation (As of December 31, 2012) Constant Dollars |
4.3 | | Sproule Associates Limited – Evaluation of the P&NG Reserves of Hemisphere Energy Corporation (As of February 29, 2012) Constant Dollars |
| 10.1 | | Stock Option Plan* |
| 10.2 | | Executive employment agreement between Hemisphere Energy Corporation and Don Simmons* |
| 10.3 | | Executive employment agreement between Hemisphere Energy Corporation and Dorlyn Evancic* |
| 10.4 | | Executive employment agreement between Hemisphere Energy Corporation and Ian Duncan* |
| 10.5 | | Executive employment agreement between Hemisphere Energy Corporation and Andrew Arthur* |
| 10.6 | | Commitment letter between Hemisphere Energy Corporation and Alberta Treasury Branches dated September 19, 2013* |
| 10.7 | | First Amending Agreement to the Commitment Letter dated September 19, 2013 between Hemisphere Energy Corporation and Alberta Treasury Branches effective June 23, 2014* |
| 10.8 | | Executive employment agreement between Hemisphere Energy Corporation and Ashley Ramsden-Wood
|
| 14.1 | | Advance Notice Policy of Hemisphere Energy Corporation* |
| 99.1 | | Consent of Smythe Ratcliffe LLP |
| 99.2 | | Consent of McDaniel Associates & Consultants Ltd. (included with Exhibit 4.1) |
| 99.3 | | Consent of Sproule Associates Limited |
*Previously filed
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INDEX TO THE FINANCIAL STATEMENTS
For the year ended December 31, 2013, ten months ended December 31, 2012 and year ended
February 29, 2012
For the three and six months ended June 30, 2014
The condensed interim financial statements for the three and six months ended June 30, 2014 are unaudited and were prepared by management.
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MANAGEMENT’S REPORT
To the Shareholders of Hemisphere Energy Corporation:
Management is responsible for the preparation of the financial statements and the consistent presentation of all other financial information that is publicly disclosed. The financial statements have been prepared in accordance with the accounting policies detailed in the notes to the financial statements and in accordance with IFRS and include estimates and assumptions based on management’s best judgment. Management maintains a system of internal controls to provide reasonable assurance that assets are safeguarded and that relevant and reliable financial information is produced in a timely manner. Independent auditors appointed by the shareholders have audited the financial statements. Their report is presented with the financial statements. The Audit Committee, consisting of independent members of the Board of Directors, has reviewed financial statements with management and the independent auditors. The Board of Directors has approved the financial statements on the recommendation of the Audit Committee.
| Vancouver, British Columbia | | |
| April 14, 2014 | | |
| | | |
| (signed) “Don Simmons” | | (signed) “Dorlyn Evancic” |
| Don Simmons, President & CEO | | Dorlyn Evancic, Chief Financial Officer |
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INDEPENDENT AUDITORS’ REPORT
To the Shareholders of Hemisphere Energy Corporation:
We have audited the accompanying financial statements of Hemisphere Energy Corporation, which comprise the statements of financial position as at December 31, 2013 and 2012, and the statements of comprehensive income (loss), changes in shareholders’ equity and cash flows for the year ended December 31, 2013, the ten months ended December 31, 2012 and the year ended February 29, 2012, and a summary of significant accounting policies and other explanatory information.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements present fairly, in all material respects, the financial position of Hemisphere Energy Corporation as at December 31, 2013 and 2012, and its financial performance and its cash flows for the year ended December 31, 2013, the ten months ended December 31, 2012 and the year ended February 29, 2012 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.
Chartered Accountants
Vancouver, British Columbia
April 14, 2014
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STATEMENTS OF FINANCIAL POSITION
(Expressed in Canadian dollars)
| | Note | | December 31, 2013 | | | December 31, 2012 | |
Assets | | | | | | | |
Current assets | | | | | | | |
Accounts receivable | | $ | 1,042,407 | | $ | 904,454 | |
Prepaid expenses | | | 103,172 | | | 115,769 | |
| | | 1,145,579 | | | 1,020,223 | |
| | | | | | | |
Non-current assets | | | | | | | |
Reclamation deposits | 9 | | 105,535 | | | 100,535 | |
Exploration and evaluation assets | 7 | | 1,894,497 | | | 3,189,762 | |
Deferred tax asset | 17 | | 2,387,321 | | | 912,087 | |
Property and equipment | 8 | | 23,541,568 | | | 20,152,828 | |
Total assets | | $ | 29,074,500 | | $ | 25,375,435 | |
| | | | | | | |
Liabilities | | | | | | | |
Current liabilities | | | | | | | |
Accounts payable and accrued liabilities | | $ | 2,976,486 | | $ | 3,912,818 | |
Bank indebtedness | 11 | | 4,500,000 | | | 1,035,000 | |
Flow-through premium liability | 12 | | 369,240 | | | - | |
Total current liabilities | | | 7,845,726 | | | 4,947,818 | |
| | | | | | | |
Non-current liabilities | | | | | | | |
Decommissioning obligations | 9 | | 1,323,446 | | | 467,235 | |
| | | 9,169,172 | | | 5,415,053 | |
| | | | | | | |
Shareholders’ Equity | | | | | | | |
Capital stock | 12 | | 42,127,674 | | | 38,805,193 | |
Share-based payment reserve | 12 (b) | | 2,574,789 | | | 2,214,325 | |
Warrant reserve | 12 (c) | | 204,479 | | | 183,572 | |
Deficit | | | (25,001,614 | ) | | (21,242,708 | ) |
Total shareholders’ equity | | | 19,905,328 | | | 19,960,382 | |
Total liabilities and shareholders’ equity | | $ | 29,074,500 | | $ | 25,375,435 | |
Commitment (note 13)
The accompanying notes are an integral part of these financial statements.
On Behalf of the Board of Directors
| (signed) “Bruce McIntyre” | | (signed) “Don Simmons” |
| Bruce McIntyre, Director | | Don Simmons, Director |
98
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Expressed in Canadian dollars)
| | | 12 Months Ended | | | 10 Months Ended | | | 12 Months Ended | |
| Note | | December 31, 2013 | | | December 31, 2012 | | | February 29, 2012 | |
Oil and natural gas revenue | | $ | 10,573,199 | | $ | 7,875,723 | | $ | 4,590,608 | |
Royalties | | | (1,898,532 | ) | | (1,371,883 | ) | | (702,345 | ) |
Net oil and natural gas revenue | | | 8,674,667 | | | 6,503,840 | | | 3,888,263 | |
| | | | | | | | | | |
Expenses | | | | | | | | | | |
Production and operating | | | 3,067,174 | | | 1,846,532 | | | 945,719 | |
Exploration and evaluation | 7 | | 116,006 | | | 120,882 | | | - | |
Depletion and depreciation | 8 | | 3,088,965 | | | 2,239,706 | | | 1,070,207 | |
General and administrative | 12 (b) | | 1,877,376 | | | 1,527,505 | | | 2,067,199 | |
Impairment of property and equipment | 8 | | 5,640,571 | | | 184,938 | | | 251,394 | |
| | | 13,790,092 | | | 5,919,563 | | | 4,334,519 | |
Results from operating activities | | | (5,115,425 | ) | | 584,277 | | | (446,256 | ) |
Finance expense | 10 | | (195,776 | ) | | (40,459 | ) | | (5,623 | ) |
Gain on disposition | | | 3,889 | | | - | | | - | |
Income (loss) before income taxes | | | (5,307,312 | ) | | 543,818 | | | (451,879 | ) |
Deferred tax (expense) | | | | | | | | | | |
recovery | 17 | | 1,475,234 | | | (482,457 | ) | | 1,394,544 | |
Net income (loss) and comprehensive income (loss) for the period | | $ | (3,832,078 | ) | $ | 61,361 | | $ | 942,665 | |
Income (loss) per share | | | | | | | | | | |
Basic and diluted | 12 (d) | $ | (0.07 | ) | $ | 0.00 | | $ | 0.03 | |
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CASH FLOWS
(Expressed in Canadian dollars)
| | 12 Months Ended | | | 10 Months Ended | | | 12 Months Ended | |
| | December 31, 2013 | | | December 31, 2012 | | | February 29, 2012 | |
Operating activities | | | | | | | | | |
Net income (loss) for the period | $ | (3,832,078 | ) | $ | 61,361 | | $ | 942,665 | |
Items not affecting cash | | | | | | | | | |
Depletion, depreciation and accretion | | 3,095,478 | | | 2,254,029 | | | 1,074,252 | |
Impairment of property and equipment | | 5,640,571 | | | 184,938 | | | 251,394 | |
Deferred tax expense (recovery) | | (1,475,234 | ) | | 482,457 | | | (1,394,544 | ) |
Share-based payments | | 360,464 | | | 282,872 | | | 1,089,738 | |
| | 3,789,201 | | | 3,265,657 | | | 1,963,505 | |
Changes in non-cash working capital | | (123,927 | ) | | 406,975 | | | (1,100,252 | ) |
Cash provided by operating activities | | 3,665,274 | | | 3,672,632 | | | 863,253 | |
Investing activities | | | | | | | | | |
Property and equipment expenditures | | (8,915,499 | ) | | (8,193,606 | ) | | (12,208,884 | ) |
Exploration and evaluation expenditures | | (1,057,814 | ) | | (3,573,912 | ) | | (1,574,150 | ) |
Reclamation deposits | | (5,000 | ) | | 51,442 | | | (3,893 | ) |
Changes in non-cash working capital | | (947,511 | ) | | 2,665,666 | | | 707,460 | |
Cash used in investing activities | | (10,925,824 | ) | | (9,050,410 | ) | | (13,079,467 | ) |
Financing activities | | | | | | | | | |
Shares issued for cash, net of issue costs | | 3,785,800 | | | 2,158,880 | | | 12,457,943 | |
Proceeds from bank indebtedness | | 3,465,000 | | | 1,035,000 | | | - | |
Change in non-cash working capital | | 9,750 | | | - | | | - | |
Cash provided by financing activities | | 7,260,550 | | | 3,193,880 | | | 12,457,943 | |
| | | | | | | | | |
Inflow (outflow) of cash | | - | | | (2,183,898 | ) | | 241,729 | |
Cash, beginning of period | | - | | | 2,183,898 | | | 1,942,169 | |
Cash, end of period | $ | - | | $ | - | | $ | 2,183,898 | |
The accompanying notes are an integral part of these financial statements.
Supplemental cash flow information (Note 15)
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STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Expressed in Canadian dollars)
| | | Number of | | | | | | Share-based | | | | | | | | | Total | |
| | | common | | | | | | payment | | | Warrant | | | | | | shareholders’ | |
| Note | | shares | | | Capital stock | | | reserve | | | reserve | | | Deficit | | | equity | |
Balance, February 28, 2011 | | | 26,071,682 | | $ | 24,678,806 | | $ | 507,276 | | $ | - | | $ | (22,254,159 | ) | $ | 2,931,923 | |
Non-flow-through share issuance | 12 (a) | | 14,898,507 | | | 9,656,350 | | | - | | | - | | | - | | | 9,656,350 | |
Flow-through share issuance | 12 (a) | | 3,580,000 | | | 1,940,600 | | | - | | | 110,400 | | | - | | | 2,051,000 | |
Warrant exercises | 12 (a) | | 5,447,000 | | | 1,691,990 | | | (25,175 | ) | | - | | | - | | | 1,666,815 | |
Stock option exercises | 12 (a) | | 105,000 | | | 49,636 | | | (22,586 | ) | | - | | | - | | | 27,050 | |
Share issuance costs | 12 (a) | | - | | | (943,272 | ) | | - | | | - | | | - | | | (943,272 | ) |
Finder’s units issued | 12 (a) | | 172,512 | | | 120,758 | | | - | | | - | | | - | | | 120,758 | |
Corporate finance expense | 12 (a) | | - | | | (120,758 | ) | | - | | | - | | | - | | | (120,758 | ) |
Finder’s warrants issued | 12 (a) | | - | | | (389,625 | ) | | 389,625 | | | - | | | - | | | - | |
Shares issued on property acquisition | 12 (a) | | 100,000 | | | 35,000 | | | - | | | - | | | - | | | 35,000 | |
Share-based payments | 12 (b) | | - | | | - | | | 1,089,738 | | | - | | | - | | | 1,089,738 | |
Expiry of stock options | 12 (b) | | - | | | - | | | (7,425 | ) | | - | | | 7,425 | | | - | |
Net income for the year | | | - | | | - | | | - | | | - | | | 942,665 | | | 942,665 | |
Balance, February 29, 2012 | | | 50,374,701 | | | 36,719,485 | | | 1,931,453 | | | 110,400 | | | (21,304,069 | ) | | 17,457,269 | |
Warrant exercises | 12 (a) | | 1,752,047 | | | 1,051,228 | | | - | | | - | | | - | | | 1,051,228 | |
Stock option exercise | 12 (a) | | 5,000 | | | 1,250 | | | - | | | - | | | - | | | 1,250 | |
Share-based payments | 12 (b) | | - | | | - | | | 282,872 | | | - | | | - | | | 282,872 | |
Share issuance | 12 (a) | | 1,829,300 | | | 1,115,873 | | | - | | | 73,172 | | | - | | | 1,189,045 | |
Share issuance costs | 12 (a) | | - | | | (82,643 | ) | | - | | | - | | | - | | | (82,643 | ) |
Net income for the period | | | - | | | - | | | - | | | - | | | 61,361 | | | 61,361 | |
Balance, December 31, 2012 | | | 53,961,048 | | | 38,805,193 | | | 2,214,325 | | | 183,572 | | | (21,242,708 | ) | | 19,960,382 | |
Non-flow-through share issuance | 12 (a) | | 4,269,450 | | | 2,262,808 | | | - | | | 94,079 | | | - | | | 2,356,887 | |
Flow-through share issuance | 12 (a) | | 3,077,000 | | | 2,000,050 | | | - | | | - | | | - | | | 2,000,050 | |
Share-based payments | 12 (b) | | - | | | - | | | 360,464 | | | - | | | - | | | 360,464 | |
Share issuance costs | 12 (a) | | - | | | (571,137 | ) | | - | | | - | | | - | | | (571,137 | ) |
Premium on issuance of flow- | | | | | | | | | | | | | | | | | | | |
through shares | 12 (a) | | - | | | (369,240 | ) | | - | | | - | | | - | | | (369,240 | ) |
Expiry of warrants | 12 (c) | | - | | | - | | | - | | | (73,172 | ) | | 73,172 | | | - | |
Net loss for the year | | | - | | | - | | | - | | | - | | | (3,832,078 | ) | | (3,832,078 | ) |
Balance, December 31, 2013 | | | 61,307,498 | | $ | 42,127,674 | | $ | 2,574,789 | | $ | 204,479 | | $ | (25,001,614 | ) | $ | 19,905,328 | |
The accompanying notes are an integral part of these financial statements.
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NOTES TO THE FINANCIAL STATEMENTS
For the year ended December 31, 2013, ten months ended December 31, 2012 and year ended
February 29, 2012
(Expressed in Canadian dollars)
1.Nature and Continuance of Operations
Hemisphere Energy Corporation (the “Company”) was incorporated under the laws of British Columbia on March 6, 1978. The Company’s principal business is the acquisition, exploration, development and production of petroleum and natural gas interests. It is publicly traded company listed on the TSX Venture Exchange under the symbol “HME”. The Company’s head office is located at 570-789 West Pender Street, Vancouver, British Columbia, Canada V6C 1H2.
2.Basis of Presentation
(a) Statement of compliance
These financial statements are prepared in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board.
The financial statements were authorized for issuance by the Board of Directors on April 14, 2014.
(b) Basis of presentation
These financial statements have been prepared on a historical cost basis, except for financial instruments, which are stated at their fair values. In addition, these financial statements have been prepared using the accrual basis of accounting, except for cash flow information.
(c) Functional and presentation currency
These annual financial statements are presented in Canadian dollars, which is the Company’s functional currency.
(d) Use of estimates and judgments
The preparation of these financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that may affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates.
Following are the accounting policies subject to such judgments and the key sources of estimation uncertainty that the Company believes could have the most significant impact on the reported results and financial position.
Reserves
The estimate of oil and natural gas reserves is integral to the calculation of the amount of depletion charged to the statements comprehensive income (loss) and is also a key determinant in assessing whether the carrying value of any of the Company’s development and production assets have been impaired. Changes in reported reserves can impact asset carrying values and the decommissioning provision due to changes in expected future cash flows. The Company’s reserves are evaluated and reported on by independent reserve engineers at least annually in accordance with Canadian Securities Administrators’ National Instrument 51-101 Standards of Disclosure of Oil and Gas Activities. Reserve estimation is based on a variety of factors including engineering data, geological and geophysical data, projected future rates of production, commodity pricing and timing of future expenditures, all of which are subject to significant judgment and interpretation.
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Carrying value of property and equipment and exploration and evaluation assets
The Company assesses at each reporting date whether there is an indication that an asset or cash-generating unit (“CGU”) may be impaired. A CGU is defined as the lowest grouping of assets that generate identifiable cash inflows that are largely independent of cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires significant judgment and interpretation with respect to the way in which management monitors operations. If any indication exists that an asset or CGU may be impaired, the Company estimates the recoverable amount. The recoverable amounts of individual assets and CGUs have been determined based on the higher of value-in-use calculations and fair value less costs to sell. These calculations require the use of estimates and assumptions, such as estimates of proved plus probable reserves, future production rates, oil and natural gas prices, future costs and other relevant assumptions, all of which are subject to change.
A material adjustment to the carrying value of the Company’s property and equipment and exploration and evaluation assets could arise as a result of changes to these estimates and assumptions.
Critical accounting estimates
Decommissioning obligations
Amounts recorded for decommissioning obligations require the use of management’s best estimates of future decommissioning expenditures, expected timing of expenditures and future inflation rates. The estimates are based on internal and third party information and calculations are subject to change over time and may have a material impact on profit and loss or financial position. For more information on the Company’s decommissioning obligations see note 9.
Share-based payments
The Company measures the cost of its share-based payments to directors, officers, employees and certain consultants by reference to the fair value of the equity instruments using the Black-Scholes option pricing model at the date they are granted. The assumptions used in determining fair value include: expected lives of options, risk-free rates of return and stock price volatility. Changes to assumptions may have a material impact on the amounts presented. For more information on the Company’s share-based payments see note 12(b).
Income taxes
Related assets and liabilities are recognized for the estimated tax consequences between amounts included in the financial statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly, affect the amount of the deferred tax asset or liability calculated at a point in time. These differences could materially impact earnings.
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3. Significant Accounting Policies
(a) Financial instruments
(i) Financial assets
The Company classifies its financial assets in the following categories: held-to-maturity, fair value through profit or loss (“FVTPL”), loans and receivables, and available-for-sale (“AFS”). The classification depends on the purpose for which the financial assets were acquired. Management determines the classification of financial assets at recognition.
Held-to-maturity
Held-to-maturity financial assets are recognized on a trade-date basis and are initially measured at fair value using the effective interest rate method. The Company has no assets classified as held-to-maturity.
Financial assets at fair value through profit or loss
Financial assets at FVTPL are initially recognized at fair value with changes in fair value recorded through profit or loss.
Loans and receivables
Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are classified as current assets or non-current assets based on their maturity date. Loans and receivables are carried at amortized cost less any impairment. Loans and receivables are comprised of accounts receivable and reclamation deposits.
Available-for-sale financial assets
AFS financial assets are non-derivatives that are either designated as available-for-sale or not classified in any of the other financial asset categories. Changes in the fair value of AFS financial assets are recognized as other comprehensive income and classified as a component of shareholders’ equity.
Management assesses the carrying value of any AFS financial assets at least annually and any impairment charges are also recognized in profit or loss. When financial assets classified as AFS are sold, the accumulated fair value adjustments recognized in other comprehensive income are included in profit or loss. The Company does not have any financial instruments classified as AFS.
(ii) Financial liabilities
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Borrowings and other financial liabilities
Borrowings and other financial liabilities are non-derivatives and are recognized initially at fair value, net of transaction costs incurred, and are subsequently stated at amortized cost. Any difference between the amounts originally received, net of transaction costs, and the redemption value is recognized in profit or loss over the period to maturity using the effective interest method.
Borrowings and other financial liabilities are classified as current or non-current based on their maturity date. Financial liabilities are comprised of accounts payable and accrued liabilities and bank indebtedness.
(iii) Fair value hierarchy
Fair value measurements of financial instruments are required to be classified using a fair value hierarchy that reflects the significance of inputs in making the measurements. The levels of the fair value hierarchy are defined as follows:
Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities.
Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.
Level 3 – Inputs for the asset or liability that are not based on observable market data.
Additional disclosure on the measurement of financial instruments is provided in note 4.
(b) Revenue
Revenue from the sale of petroleum and natural gas is recorded when title passes to an external party and is based on volumes delivered to customers at contractual delivery points and rates, and collectability is reasonably assured. The costs associated with delivery, including operating and maintenance costs, transportation and production-based royalty expenses, are recognized during the same period in which the related revenue is earned and reported.
(c) Joint interest operations
The Company’s petroleum and natural gas exploration and production activities are conducted jointly with others, and accordingly, the financial statements reflect only the Company’s proportionate interest in such activities.
(d) Property and equipment and exploration and evaluation assets
(i) Pre-exploration expenditures
Expenditures made by the Company before acquiring the legal right to explore in a specific area do not meet the definition of an asset and therefore are expensed as incurred.
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(ii) Exploration and evaluation expenditures
Costs incurred once the legal right to explore has been acquired are capitalized as exploration and evaluation assets. These costs include, but are not limited to, exploration license expenditures, leasehold property acquisition costs, evaluation costs, drilling costs directly attributable to an identifiable well, and directly attributable general and administrative costs. These costs are accumulated in cost centers by property and are not subject to depletion until technical feasibility and commercial viability has been determined.
Exploration and evaluation assets are assessed for impairment when facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, exploration and evaluation assets are grouped together with developing and producing assets and are tested at an aggregated CGU level.
The technical feasibility and commercial viability is considered to be determinable when proved and probable reserves are determined to exist. A review of each exploration license or field is carried out, at each reporting date, to ascertain whether proved and probable reserves have been discovered. Upon determination of proved and probable reserves, exploration and evaluation assets attributable to those reserves are tested for impairment and reclassified from exploration and evaluation assets to petroleum and natural gas properties.
(iii) Developing and production costs
Items of property and equipment, which include petroleum and natural gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. A CGU’s recoverable amount is the higher of its fair value less costs to sell and its value in use. Where the carrying amount of a CGU exceeds its recoverable amount, the asset group is considered impaired and is written down to its recoverable amount.
Gains and losses on disposal of an item of property and equipment, including petroleum and natural gas properties, are determined by comparing the proceeds from disposal with the carrying amount of property and equipment and are recognized in profit or loss.
(iv) Subsequent costs
Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property and equipment are recognized as petroleum and natural gas properties only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized petroleum and natural gas properties generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of
106
the day-to-day servicing of property and equipment are recognized in profit or loss as incurred.
(v) Depletion and depreciation
Depletion of petroleum and natural gas properties is determined using the unit-of-production method based on production volumes in relation to total estimated proved reserves as determined annually by independent engineers and determined in accordance with National Instrument 51-101. Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil.
The calculation of depletion and depreciation of production equipment is based on total capitalized costs plus estimated future development costs of proved and undeveloped reserves less the estimated net realizable value of production equipment and facilities after the proved reserves are fully produced.
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
| | (i) | The area of the reservoir considered as proved includes: |
| | | | |
| | | (a) | The area identified by drilling and limited by fluid contacts, if any, and |
| | | | |
| | | (b) | Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
| | | | |
| | (ii) | In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. |
| | | | |
| | (iii) | Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. |
| | | | |
| | (iv) | Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: |
| | | | |
| | | (a) | Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and |
| | | | |
| | | (b) | The project has been approved for development by all necessary parties and entities, including governmental entities. |
| | | | |
| | (v) | Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
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Depreciation of other equipment is provided for on a 20-30% declining balance basis. Depreciation methods, useful lives and residual values are reviewed at each reporting date.
(vi) Impairment
Exploration and evaluation assets are assessed for impairment when they are reclassified to developing and producing assets, as petroleum and natural gas properties, and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount.
Fair value less costs to sell is determined to be the amount for which the asset could be sold in an arm’s length transaction. Fair value less costs to sell can be determined by using an observable market or by using discounted future net cash flows of proved and probable reserves using forecasted prices and costs. Value in use is determined by estimating the present value of the future net cash flows expected to be derived from the continued use of the asset or CGU.
Exploration and evaluation assets are grouped together with the Company’s CGUs when they are assessed for impairment, both at the time of any triggering facts and circumstances as well as upon their eventual reclassification to producing assets (petroleum and natural gas properties).
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of goodwill, if any, allocated to the units and then to reduce carrying amounts of other assets in the unit (group of units) on a pro rata basis.
Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.
(e) Decommissioning obligations
Decommissioning obligations are measured at the present value of management’s best estimate of expenditures required to settle the present obligation at the statement of financial position date. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as finance costs whereas increases/decreases due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision.
(f) Share-based payments
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The Company has a stock option plan that is described in note 12(b). Share-based payments to employees are measured at the fair value of the instruments issued and are amortized over the vesting periods. Share-based payments to non-employees are measured at the fair value of the goods or services received or the fair value of the equity instruments issued, if it is determined the fair value of the goods or services cannot be reliably measured, and are recorded at the date the goods or services are received. The amount recognized as an expense is adjusted to reflect the number of awards expected to vest. The offset to the recorded cost is to share-based payments reserve. Consideration received on the exercise of stock options is recorded as capital stock and the related share-based payments reserve is transferred to capital stock. Charges for options that are forfeited before vesting are reversed from share-based payments reserve. For those options that expire or are forfeited after vesting, the recorded value is transferred to deficit.
(g) Equity units
The Company uses the residual value method with respect to the measurement of equity units. The proceeds from the issue of units is allocated between common shares and share purchase warrants on a residual value basis, wherein the fair value of the common shares is based on the market close on the date the units are issued; the balance, if any, is allocated to the attached warrants. Share issue costs are netted against share proceeds.
(h) Flow-through shares and units
The Company may, from time to time, issue flow-through common shares to finance its petroleum and natural gas exploration activities. Canadian income tax law permits the Company to renounce to the flow-through shareholders the income tax attributes of certain petroleum and natural gas exploration and evaluation costs financed by such shares. A liability is recognized for any premium on the flow-through shares and is subsequently reversed as the Company incurs qualifying Canadian exploration expenses.
The effect of renouncement of the qualifying expenditures is to reduce future income tax deductions, which is considered to be a cost of operations that is charged to profit or loss, and a corresponding increase in deferred income tax liability. When flow-through expenditures are renounced, a portion of the deferred income tax assets that were not previously recognized are recognized as a recovery of income taxes in profit or loss.
In circumstances where the Company has issued flow-through shares by way of a unit offering, the proceeds are allocated first to common shares based on the market close at the time the units are priced, and any residual value is allocated next to the warrants reserve based on the fair value of the warrant component using the Black-Scholes option pricing model on grant date. Any remaining residual value is then recognized as a liability for the premium on the flow-through shares.
(i) Income taxes
Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss, except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.
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Current income tax expense is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.
Deferred income tax is recognized using the balance sheet liability method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred income tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred income tax assets and liabilities are offset if there is a legally enforceable right to offset and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred income tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.
(j) Earnings (loss) per share
Basic earnings (loss) per share is calculated by dividing the profit or loss attributable to common shareholders of the Company by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined by adjusting the profit or loss attributable to common shareholders and the weighted average number of shares outstanding for the effects of dilutive instruments such as options and warrants.
The Company uses the treasury stock method to compute the dilutive effect of options, warrants and similar instruments. Under this method the dilutive effect on earnings per share is calculated presuming the exercise of outstanding options, warrants and similar instruments. It assumes that proceeds received from the exercise of stock options and warrants would be used to repurchase common shares at the average market price during the year. However, the calculation of diluted loss per share excludes the effects of various conversions and exercise of options and warrants that would be anti-dilutive.
Shares held in escrow other than where their release is subject to the passage of time are excluded from the computation of loss per share until the conditions for their release are satisfied.
(k) Future accounting pronouncements
(i) IFRS 9 Financial Instruments (2010)
A revised version of IFRS 9 incorporating revised requirements for the classification and measurement of financial liabilities, and carrying over the existing de-recognition requirements from International Accounting Standards (“IAS”) 39 Financial Instruments: Recognition and Measurement.
The revised financial liability provisions maintain the existing amortized cost measurement basis for most liabilities. New requirements apply where an entity chooses to measure a liability at FVTPL; in these cases, the portion of the change in fair value related to changes in the entity’s own credit risk is presented in other comprehensive income rather than within profit or loss.
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| | | The IASB has indefinitely postponed the mandatory adoption date of this standard. The Company is currently assessing the impact of adopting IFRS 9 on the financial statements. |
| | | |
| | (ii) | Offsetting Financial Assets and Financial Liabilities (Amendments to IAS 32) |
| | | |
| | | Amends IAS 32 Financial Instruments: Presentation to clarify certain aspects because of diversity in application of the requirements on offsetting, focused on four main areas: |
| | • | the meaning of “currently has a legally enforceable right of set-off” |
| | • | the application of simultaneous realization and settlement |
| | • | the offsetting of collateral amounts |
| | • | the unit of account for applying the offsetting requirements. |
| | | Applicable to annual periods beginning on or after January 1, 2014. |
| | | |
| | (iii) | Annual Improvements 2010-2012 Cycle |
| | | |
| | | Makes amendments to the following standards: |
| | • | IFRS 2 — Amends the definitions of “vesting condition” and “market condition” and adds definitions for “performance condition” and “service condition” |
| | • | IFRS 3 — Require contingent consideration that is classified as an asset or a liability to be measured at fair value at each reporting date |
| | • | IFRS 8 — Requires disclosure of the judgments made by management in applying the aggregation criteria to operating segments, clarify reconciliations of segment assets only required if segment assets are reported regularly |
| | • | IFRS 13 — Clarify that issuing IFRS 13 and amending IFRS 9 and IAS 39 did not remove the ability to measure certain short-term receivables and payables on an undiscounted basis (amends basis for conclusions only) |
| | • | IAS 16 and IAS 38 — Clarify that the gross amount of property, plant and equipment is adjusted in a manner consistent with a revaluation of the carrying amount |
| | • | IAS 24 — Clarify how payments to entities providing management services are to be disclosed |
| | | Applicable to annual periods beginning on or after July 1, 2014. |
| | | |
| | (iv) | Annual Improvements 2011-2013 Cycle |
| | | |
| | | Makes amendments to the following standards: |
| | • | IFRS 1 — Clarify which versions of IFRSs can be used on initial adoption (amends basis for conclusions only) |
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| | • | IFRS 3 — Clarify that IFRS 3 excludes from its scope the accounting for the formation of a joint arrangement in the financial statements of the joint arrangement itself |
| | • | IFRS 13 — Clarify the scope of the portfolio exception in paragraph 52 |
| | • | IAS 40 — Clarifying the interrelationship of IFRS 3 and IAS 40 when classifying property as investment property or owner-occupied property |
Applicable to annual periods beginning on or after July 1, 2014.
4. Financial Instruments
Fair value estimates of financial instruments are made at a specific point in time, based on relevant information about financial markets and specific financial instruments. As these estimates are subjective in nature, involving uncertainties and matters of significant judgment, they may be subject to future adjustment. Changes in assumptions can significantly affect estimated fair values. At December 31, 2013, the Company’s financial instruments include accounts receivable, reclamation deposits, bank indebtedness, and accounts payable and accrued liabilities.
The fair values of accounts receivable, reclamation deposits, accounts payable and accrued liabilities, and bank indebtedness approximate their carrying values due to the short-term maturity of these financial instruments.
5.Financial Risk Management
The Company’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production and financing activities such as credit risk, liquidity risk and market risk. This note presents information about the Company’s exposure to each of these risks. Management sets controls to manage such risks and monitors them on an ongoing basis pertaining to market conditions and the Company’s activities.
(a) Credit risk
Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its payment obligations. This risk arises principally from the Company’s receivables from joint venture partners and oil and natural gas marketers, and reclamation deposits. The credit risk associated with reclamation deposits is minimized substantially by ensuring this financial asset is placed with major financial institutions with strong investment-grade ratings by a primary ratings agency. The credit risk associated with accounts receivable is mitigated as the Company monitors monthly balances to limit the risk associated with collections. The Company does not anticipate any default. The maximum exposure to credit risk is as follows:
| | | | December 31, 2013 | | | December 31, 2012 | |
| | Accounts receivable | $ | 1,042,407 | | $ | 904,454 | |
| | Reclamation deposits | | 105,535 | | | 100,535 | |
| | | $ | 1,147,942 | | $ | 1,004,989 | |
(b) Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company’s approach to managing liquidity risk is to ensure, as far as possible, that it will have sufficient liquidity to meet its liabilities when they become due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company.
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At December 31, 2013, the Company had negative working capital of $6,700,147 (December 31, 2012 - $3,927,595), which includes bank indebtedness of $4,500,000 (December 31, 2012 - $1,035,000). The Company funds its operations through production revenue and a demand operating credit facility (note 11). All of the Company’s financial liabilities have contractual maturities of less than 90 days.
(c) Market risk
Market risk is the risk that changes in market prices, such as foreign exchange rates, other prices and interest rates will affect the value of the financial instruments. Market risk is comprised of three types of risk: interest rate risk, foreign currency risk and other price risk.
(i) Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. Borrowings under the Company’s credit facilities are subject to variable interest rates. A one percent change in interest rates would not have a material effect on net income (loss) and comprehensive income (loss).
(ii) Foreign currency risk
The Company is not exposed to significant foreign currency risk.
(iii)Other price risk
Other price risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate due to changes in market prices, other than those arising from interest rate risk or foreign currency risk. The Company is not exposed to significant other price risk.
6. Capital Management
The Company manages its capital with the following objectives:
| | (a) | To ensure sufficient financial flexibility to achieve the Company’s ongoing business objectives including the replacement of production, funding of future growth opportunities and pursuit of accretive acquisitions; and |
| | | |
| | (b) | To maximize shareholder return through enhancing the Company’s share value. |
The Company monitors its capital structure and makes adjustments according to market conditions in an effort to meet its objectives given the current outlook of the Company and industry in general. The capital structure of the Company is composed of shareholders’ equity and the undrawn component of the Company’s credit facilities. The Company may manage its capital structure by issuing new shares, repurchasing outstanding shares, obtaining additional financing from the Company’s credit facilities, issuing new debt instruments or other financial or equity-based instruments, adjusting capital spending or disposing of assets. The capital structure is reviewed on an ongoing basis.
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The Company’s capital structure as at December 31, 2013 and 2012 are as follows:
| | | December 31, 2013 | | | December 31, 2012 | |
Shareholders’ equity | $ | 19,905,328 | | $ | 19,960,382 | |
Undrawn component of bank credit facilities | | 6,000,000 | | | 4,465,000 | |
Total capital | $ | 25,905,328 | | $ | 24,425,382 | |
As at December 31, 2013, the Company had total available credit facilities of $10,500,000 (December 31, 2012 - $5,500,000) of which the Company had drawn $4,500,000 (December 31, 2012 - $1,035,000) (note 11).
7. Exploration and Evaluation Assets
Exploration and evaluation assets consist of the Company’s exploration projects, which are pending the determination of proved reserves. For the year ended December 31, 2013, the Company transferred $2,353,078 (ten months ended December 31, 2012 - $3,642,159) to property and equipment.
| Cost | | | |
| Balance February 28, 2011 | $ | 473,527 | |
| Additions | | 1,688,216 | |
| Balance February 29, 2012 | | 2,161,743 | |
| Additions | | 4,791,060 | |
| Exploration and evaluation expense | | (120,882 | ) |
| Transfer to property and equipment | | (3,642,159 | ) |
| Balance, December 31, 2012 | | 3,189,762 | |
| Additions | | 1,173,819 | |
| Exploration and evaluation expense | | (116,006 | ) |
| Transfer to property and equipment | | (2,353,078 | ) |
| Balance, December 31, 2013 | $ | 1,894,497 | |
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8. Property and Equipment
| | Petroleum and | | | | | | | |
| | Natural Gas | | | Other Equipment | | | Total | |
Cost | | | | | | | | | |
Balance, February 28, 2011 | $ | 3,188,325 | | $ | 57,323 | | $ | 3,245,648 | |
Additions | | 12,406,326 | | | 10,199 | | | 12,416,525 | |
Balance, February 29, 2012 | | 15,594,651 | | | 67,522 | | | 15,662,173 | |
Additions | | 7,191,824 | | | - | | | 7,191,824 | |
Transfer from exploration and evaluation assets | | 3,642,159 | | | - | | | 3,642,159 | |
Balance, December 31, 2012 | | 26,428,634 | | | 67,522 | | | 26,496,156 | |
Additions | | 9,765,198 | | | - | | | 9,765,198 | |
Transfer from exploration and evaluation | | | | | | | | | |
assets | | 2,353,078 | | | - | | | 2,353,078 | |
Balance, December 31, 2013 | $ | 38,546,910 | | $ | 67,522 | | $ | 38,614,432 | |
Accumulated Depletion, Depreciation, Amortization and Impairment Losses | | | | | | | | | |
Balance, February 28, 2011 | $ | 2,556,722 | | $ | 40,361 | | $ | 2,597,083 | |
Charge for year | | 1,065,656 | | | 4,551 | | | 1,070,207 | |
Impairment loss | | 251,394 | | | - | | | 251,394 | |
Balance, February 29, 2012 | | 3,873,772 | | | 44,912 | | | 3,918,684 | |
Charge for period | | 2,234,638 | | | 5,068 | | | 2,239,706 | |
Impairment loss | | 184,938 | | | - | | | 184,938 | |
Balance, December 31, 2012 | | 6,293,348 | | | 49,980 | | | 6,343,328 | |
Charge for year | | 3,084,441 | | | 4,524 | | | 3,088,965 | |
Impairment loss | | 5,640,571 | | | - | | | 5,640,571 | |
Balance, December 31, 2013 | $ | 15,018,360 | | $ | 54,504 | | $ | 15,072,864 | |
Net Book Value | | | | | | | | | |
December 31, 2012 | $ | 20,135,286 | | $ | 17,542 | | $ | 20,152,828 | |
December 31, 2013 | $ | 23,528,550 | | $ | 13,018 | | $ | 23,541,568 | |
(a) Property acquisitions for the year ended December 31, 2013:
(i) Property acquisitions constituting a business combination
On November 14, 2013, the Company closed the acquisition of the oil and gas assets in the Atlee Buffalo property in southeastern Alberta. The Company acquired a 100% working interest in land and tangible assets in the Atlee Buffalo property for total cash consideration of $3,155,195 (net of June to September 2013 net production revenue). The acquisition date fair value of the assets acquired consisted of oil production equipment of $670,000 and petroleum and natural gas interests of $2,485,195. The fair value of the assets acquired was equal to the cash consideration paid, and no goodwill or bargain purchase gain was recorded in the transaction.
(ii) Property acquisitions not constituting a business combination
During the 2013 fiscal year, the Company also purchased properties for total expenditures of $132,582 in various Crown land sales through the Alberta Department of Energy. These properties were all located in the Jenner area.
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(b) Property acquisitions for the ten months ended December 31, 2012:
On August 8, 2012, the Company purchased properties for total expenditures of $189,274 in a Crown land sale offered through the Alberta Department of Energy. This property is located in the Company’s core Jenner area and was not considered a business combination.
During the year ended December 31, 2013, the Company performed an impairment test on its petroleum and natural gas assets. It was determined that the carrying amount of three CGUs exceeded their recoverable amount due to a decline in estimated reserve volumes. Accordingly, the Company recognized an impairment charge of $5,640,571 (ten months ended December 31, 2012 - $184,938, year ended February 29, 2012 - $251,394). The impairment test was performed by comparing the estimated net present value of future cash flows from wells classified as proved and probable against their respective carrying amounts. The discounted cash flows were estimated using a discount rate of 5% (ten months ended December 31, 2012 – 5%, year ended February 29, 2012 – 5%) with escalating prices and future development costs, as obtained from the reserve report. The prices used are those used by independent reserve engineers.
9. Decommissioning Obligations
The Company’s decommissioning obligations result from its ownership interest in petroleum and natural gas assets including well sites and gathering systems. The total decommissioning obligation is estimated 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 years.
The Company estimates the total undiscounted amount of cash flows required to settle its decommissioning obligations as at December 31, 2013 is $2,246,800 (December 31, 2012 - $728,000). These payments are expected to be made over the next 24 years with the majority of costs to be incurred between 2019 and 2038. The discount factor, being the risk-free rate related to the liability, is 3.09% (December 31, 2012 – 2.52%) . Inflation of 1.10% (December 31, 2012 – 1.00%) has also been factored into the calculation. The Company also has $105,535 (December 31, 2012 - $100,535) in various reclamation bonds for its properties held by the British Columbia Ministry of Energy, Mines and Petroleum Resources.
| | | December 31, 2013 | | | December 31, 2012 | | | February 29, 2012 | |
Decommissioning obligations, beginning of period | $ | 467,235 | | $ | 358,428 | | $ | 67,676 | |
Increase in estimated future obligations | | 849,698 | | | 94,484 | | | 286,706 | |
Accretion expense | | 6,513 | | | 14,323 | | | 4,046 | |
Decommissioning obligations, end of period | $ | 1,323,446 | | $ | 467,235 | | $ | 358,428 | |
10.Finance Income and Expenses
| | Year Ended | | | 10 Months Ended | | | Year Ended | |
| | December 31, 2013 | | | December 31, 2012 | | | February 29, 2012 | |
Finance expense: | | | | | | | | | |
Interest expense | $ | 189,263 | | $ | 22,813 | | $ | (865 | ) |
Part XII.6 tax | | - | | | 3,323 | | | 2,442 | |
Accretion of provision | | 6,513 | | | 14,323 | | | 4,046 | |
Net finance expenses | $ | 195,776 | | $ | 40,459 | | $ | 5,623 | |
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11. Bank Indebtedness
The Company has a demand operating credit facility in the amount of $10,500,000 with Alberta Treasury Branches under commitment letter as of September 25, 2013. The facility is secured by a general security agreement and a floating charge on all lands of the Company. The facility bears interest at the bank’s prime rate plus 1.75% as well as a standby charge for any undrawn funds.
At December 31, 2013, the Company has drawn a total of $4,500,000 from the credit facility (December 31, 2012 - $1,035,000).
12.Capital Stock
(a) Authorized
Unlimited number of common shares without par value.
Issued and outstanding
The following occurred during the year ended December 31, 2013:
| | (i) | On January 25, 2013, the Company closed the second and final tranche of a private placement consisting of 86,900 units at a price of $0.65 per unit for gross proceeds of $56,485. Each unit consisted of one common share and one-half of one non- transferrable share purchase warrant. Each whole warrant entitles the holder to purchase one additional common share at the price of $0.90 until January 25, 2014. |
| | | |
| | | Using the residual value method to value the units, the fair value of the common shares is $46,057, and the remaining balance of $10,428 is allocated to the share purchase warrants. |
| | | |
| | | In conjunction with the closing of the private placement, $456 in finders’ fees and legal fees were paid and 700 finders’ warrants were issued. Each warrant entitles the holder to purchase one common share at a price of $0.90 until January 25, 2014. |
| | | |
| | (ii) | On December 9, 2013, the Company closed a bought deal private placement consisting of 4,182,550 units, comprised of one common share and one-half of one warrant of the Company at a price of $0.55 per unit and 3,077,000 common shares to be issued on a flow-through basis at a price of $0.65 per flow-through share for aggregate gross proceeds of $4,300,453. Each whole warrant entitled the holder to acquire one common share of the Company at a price of $0.75 until December 9, 2014. |
| | | |
| | | Using the residual value method to value the units, the fair value of the common shares is $2,216,751, and the remaining balance of $83,651 is allocated to the share purchase warrants. |
| | | |
| | | Using the residual value method to value the flow-through shares, the fair value of the common shares is $1,630,810, and the remaining balance of $369,240 is allocated to the flow-through premium liability. |
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In conjunction with the closing of the private placement, $571,137 in share issuance costs including commissions and legal fees were paid.
The following occurred during the ten months ended December 31, 2012:
| | | (iii) On December 20, 2012, the Company closed a private placement consisting of 1,829,300 units at a price of $0.65 per unit for gross proceeds of $1,189,045. Each unit consisted of one common share and one-half of one share purchase warrant. Each whole warrant entitled the holder to purchase one additional common share at the price of $0.90 until December 20, 2013. |
| | | |
| | | Using the residual value method to value the units, the fair value of the common shares is $1,115,873 and the remaining balance of $73,172 is allocated to the share purchase warrants. |
| | | |
| | | In conjunction with the closing of the private placement, $82,643 in finders’ fees and legal fees were paid and 114,191 finders’ warrants issued. Each warrant entitled the holder to purchase one common share at a price of $0.90 until December 20, 2013. |
| | | |
| | (iv) | The Company received $1,051,228 through the exercise of 1,752,047 share purchase warrants. Additionally, $1,250 was received through the exercise of 5,000 stock options. |
The following occurred during the year ended February 29, 2012:
(v)On April 29, 2011, the Company closed a private placement consisting of 2,575,350 units at a price of $0.40 per unit for gross proceeds of $1,030,140. Each unit consisted of one common share and one-half of one non-transferable share purchase warrant. Each whole warrant entitled the holder to purchase one additional common share at a price of $0.60 until October 29, 2012.
In the same private placement, the Company issued 1,380,000 flow-through units at a price of $0.45 per flow-through unit for gross proceeds of $621,000. Each flow-through unit consisted of one flow-through common share and one-half of one share purchase warrant. Each whole warrant entitled the holder to purchase one additional non-flow-through common share at a price of $0.60 until October 29, 2012.
The flow-through units were determined to be issued at a premium of $110,400 over the fair value of the shares. This was allocated to the warrant portion of the units, which were valued using the Black-Scholes option pricing model with the following weighted-average assumptions:
| | Expected life (years) | 1.5 |
| | Interest rate | 1.70% |
| | Volatility | 115.93% |
| | Dividend yield | 0.00% |
As part of the finders’ fee agreement, cash finders’ fees of $119,074 were paid in conjunction with the financing. Additionally, 240,247 share purchase warrants (“finders’ warrants”) were issued to the agents with each finders’ warrant having the same terms as the placement warrants described above. These finders’ warrants were valued at $36,638 using the Black-Scholes option pricing model with the following weighted-average assumptions:
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| | Expected life (years) | 1.5 |
| | Interest rate | 1.70% |
| | Volatility | 115.93% |
| | Dividend yield | 0.00% |
| | (vi) | On November 10, 2011, the Company closed a private placement consisting of 2,200,000 flow-through shares at a price of $0.65 per share for gross proceeds of $1,430,000. |
| | | |
| | | In conjunction with the closing of this private placement, $68,705 in finders’ fees was paid and 132,650 finder’s warrants issued. Each warrant entitled the holder to purchase one common share at a price of $0.80 until November 10, 2012. These finder’s warrants were valued at $9,924 using the Black-Scholes option pricing model with the following weighted-average assumptions: |
| | Expected life (years) | 1.0 |
| | Interest rate | 1.09% |
| | Volatility | 98.30% |
| | Dividend yield | 0.00% |
| | (vii) | On November 21, 2011, the Company closed the acquisition of an additional working interest in its Trutch property in northeast British Columbia. Total consideration for the acquisition was $250,000 in cash and issuance of 100,000 common shares (note 8). The common shares were issued at $0.35 per share, for total fair value of $35,000. |
| | | |
| | (viii) | On January 27, 2012, the Company closed a brokered private placement that consisted of 12,323,157 units at $0.70 each for aggregate subscription proceeds of $8,626,210. Each unit consisted of one common share and one-half of one transferable share purchase warrant, with each whole warrant entitling the holder to purchase one additional common share at a price of $0.95 until January 27, 2014. |
| | | |
| | | In conjunction with this brokered private placement, the Company paid commissions and fees of $603,835, and issued 862,620 agent warrants, each agent warrant entitling the holder to purchase one common share at a price of $0.70 each until January 27, 2014. These warrants were valued at $343,063 using the Black- Scholes option pricing model with the following weighted-average assumptions: |
| | Expected life (years) | 2 |
| | Interest rate | 0.95% |
| | Volatility | 112.93% |
| | Dividend yield | 0.00% |
Additionally, 172,512 corporate finance units were issued in conjunction with the brokered private placement, each having the same terms as the units sold pursuant to the brokered private placement. These units were issued at $0.70 each, for total fair value of $120,758. Share issuance costs in the same amount were recorded.
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| | (ix) | Throughout the year ended February 29, 2012, $1,666,815 was received through the exercise of 5,447,000 share purchase warrants; $25,175 was reallocated to capital stock from the share-based payment reserve to capital stock for these share purchase warrants. Additionally, $27,050 was received through the exercise of 105,000 stock options; $22,586 was reallocated to capital stock from the share-based payment reserve for these stock options. |
In conjunction with the private placements described above, the Company incurred $151,658 in other share issuance costs.
(b) Stock options
The Company has a stock option plan in place and is authorized to grant stock options to officers, directors, employees and consultants whereby the aggregate number of shares reserved for issuance may not exceed 10% of the issued shares at the time of grant and 5% of the issued shares to each optionee. Stock options are non-transferable, subject to a four-month holding period and have a maximum term of five years. Stock options terminate no later than 90 days (30 days for investor-related services) upon termination of employment/contract and one year in the case of retirement/death/disability. The grant price may not be less than the last closing price of the Company’s shares and not less than $0.10 per share.
Details of the Company’s stock options as at December 31, 2013 and 2012 are as follows:
| | | Changes in the Year | | |
| | | Balance | | | | Balance | Balance |
| | | Outstanding | | | | Outstanding | Exercisable |
| Exercise | Expiry | December 31, | | | Expired/ | December 31, | December 31, |
| Price | Date | 2012 | Granted | Exercised | Cancelled | 2013 | 2013 |
| $0.27 | 28-Sep-14 | 445,000 | - | - | - | 445,000 | 445,000 |
| $0.25 | 8-Mar-15 | 485,000 | - | - | - | 485,000 | 485,000 |
| $0.26 | 30-Sep-15 | 520,000 | - | - | - | 520,000 | 520,000 |
| $0.30 | 23-Dec-15 | 425,000 | - | - | - | 425,000 | 425,000 |
| $0.30 | 27-Jan-16 | 200,000 | - | - | - | 200,000 | 200,000 |
| $0.38 | 9-Feb-16 | 50,000 | - | - | - | 50,000 | 50,000 |
| $0.40 | 26-May-16 | 520,000 | - | - | - | 520,000 | 520,000 |
| $0.48 | 5-Jul-16 | 50,000 | - | - | - | 50,000 | 50,000 |
| $0.70 | 8-Feb-17 | 1,550,000 | - | - | - | 1,550,000 | 1,550,000 |
| $0.65 | 24-Apr-17 | 75,000 | - | - | - | 75,000 | 75,000 |
| $0.61 | 5-Jul-17 | 425,000 | - | - | - | 425,000 | 425,000 |
| $0.50 | 8-Mar-18 | - | 250,000 | - | - | 250,000 | 250,000 |
| $0.55 | 6-Jan-19 | - | 685,000 | - | - | 685,000 | 685,000 |
| | | 4,745,000 | 935,000 | - | - | 5,680,000 | 5,680,000 |
| Weighted-average exercise price | | $0.47 | $0.54 | - | - | $0.48 | $0.48 |
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| | | Changes in the Period | | |
| | | Balance | | | | Balance | Balance |
| | | Outstanding | | | | Outstanding | Exercisable |
| Exercise | Expiry | February 29, | | | Expired/ | December 31, | December 31, |
| Price | Date | 2012 | Granted | Exercised | Cancelled | 2012 | 2012 |
| $0.27 | 28-Sep-14 | 445,000 | - | - | - | 445,000 | 445,000 |
| $0.25 | 8-Mar-15 | 490,000 | - | (5,000) | - | 485,000 | 485,000 |
| $0.26 | 30-Sep-15 | 520,000 | - | - | - | 520,000 | 520,000 |
| $0.30 | 23-Dec-15 | 425,000 | - | - | - | 425,000 | 425,000 |
| $0.30 | 27-Jan-16 | 200,000 | - | - | - | 200,000 | 200,000 |
| $0.38 | 9-Feb-16 | 50,000 | - | - | - | 50,000 | 50,000 |
| $0.40 | 26-May-16 | 520,000 | - | - | - | 520,000 | 520,000 |
| $0.48 | 5-Jul-16 | 50,000 | - | - | - | 50,000 | 50,000 |
| $0.70 | 8-Feb-17 | 1,550,000 | - | - | - | 1,550,000 | 1,487,500 |
| $0.65 | 24-Apr-17 | - | 75,000 | - | - | 75,000 | 75,000 |
| $0.61 | 5-Jul-17 | - | 425,000 | - | - | 425,000 | 425,000 |
| | | 4,250,000 | 500,000 | (5,000) | - | 4,745,000 | 4,682,500 |
| Weighted-average exercise price | | $0.45 | $0.62 | $0.25 | - | $0.47 | $0.46 |
For the year ended December 31, 2013, the Company recognized $360,464 (ten months ended December 31, 2012 - $282,872, year ended February 29, 2012 - $1,089,738) in share-based payment expense from the granting of 935,000 (ten months ended December 31, 2012 – 500,000, year ended February 29, 2012 – 2,120,000) options to directors, officers, consultants and employees of the Company. The fair value was determined using the Black-Scholes option pricing model with the following weighted average assumptions:
| | | December 31, 2013 | December 31, 2012 | February 29, 2012 |
| | Expected life (years) | 5.00 | 5.00 | 5.00 |
| | Interest rate | 1.71% | 1.18% | 1.54% |
| | Volatility | 98% | 137% | 140% |
| | Dividend yield | 0.00% | 0.00% | 0.00% |
The weighted-average exercise price for stock options granted during the year ended December 31, 2013 was $0.54 (ten months ended December 31, 2012 - $0.62, year ended February 29, 2012 - $0.62) . The forfeiture rate has been estimated at 0% (December 31, 2012 – 0%, February 29, 2012 – 0%).
Included in stock options granted for the year ended December 31, 2013 were nil (ten months ended December 31, 2012 – nil, year ended February 29, 2012 – 250,000) stock options granted to an individual performing investor relations services. The options vested at 25% at each three-month interval from the grant date. The total number of options that remain unvested at December 31, 2013 is nil (ten months ended December 31, 2012 – 62,500, year ended February 29, 2012 – 250,000).
Throughout the year ended December 31, 2013, the Company removed $nil (ten months ended December 31, 2012 - $nil, year ended February 29, 2012 - $7,425) from the share-based payment reserve and recorded a corresponding recovery in deficit for expired stock options.
Option pricing models require the input of highly subjective assumptions including the expected price volatility. Changes in the subjective input assumptions can materially affect the fair value estimate.
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(c) Share purchase warrants
Details of the Company’s share purchase warrants as at December 31, 2013 and 2012 are as follows:
| | | Changes in the Year | |
| | | Balance Outstanding | | | | Balance Outstanding |
| Exercise | Expiry | & Exercisable | | | Expired/ | & Exercisable |
| Price | Date | December 31, 2012 | Issued | Exercised | Cancelled | December 31, 2013 |
| $0.90 | 20-Dec-13 | 914,650 | - | - | (914,650) | - |
| $0.90 | 20-Dec-13 | 114,191 | - | - | (114,191) | - |
| $0.90 | 25-Jan-14 | - | 43,450 | - | - | 43,450 |
| $0.90 | 25-Jan-14 | - | 700 | - | - | 700 |
| $0.95 | 27-Jan-14 | 6,161,578 | - | - | - | 6,161,578 |
| $0.95 | 27-Jan-14 | 86,256 | - | - | - | 86,256 |
| $0.70 | 27-Jan-14 | 862,620 | - | - | - | 862,620 |
| $0.75 | 9-Dec-14 | - | 2,091,275 | - | - | 2,091,275 |
| | | 8,139,295 | 2,135,425 | - | (1,028,841) | 9,245,879 |
| Weighted-average exercise price | | $0.92 | $0.75 | - | $0.90 | $0.88 |
| | | Changes in the Period | |
| | | Balance Outstanding | | | | Balance Outstanding |
| Exercise | Expiry | & Exercisable | | | Expired/ | & Exercisable |
| Price | Date | February 29, 2012 | Issued | Exercised | Cancelled | December 31, 2012 |
| $0.60 | 29-Oct-12 | 2,108,872 | - | (1,752,047) | (356,825) | - |
| $0.80 | 10-Nov-12 | 132,650 | - | - | (132,650) | - |
| $0.90 | 20-Dec-13 | - | 914,650 | - | - | 914,650 |
| $0.90 | 20-Dec-13 | - | 114,191 | - | - | 114,191 |
| $0.95 | 27-Jan-14 | 6,161,578 | - | - | - | 6,161,578 |
| $0.95 | 27-Jan-14 | 86,256 | - | - | - | 86,256 |
| $0.70 | 27-Jan-14 | 862,620 | - | - | - | 862,620 |
| | | 9,351,976 | 1,028,841 | (1,752,047) | (489,475) | 8,139,295 |
| Weighted-average exercise price | | $0.85 | $0.90 | $0.60 | $0.65 | $0.92 |
Throughout the year ended December 31, 2013, the Company removed $73,172 (ten months ended December 31, 2012 - $nil, year ended February 29, 2012 - $nil) from the warrant reserve and recorded a corresponding recovery in deficit for expired warrants.
(d) Income (loss) per share
| | | | Year Ended | | | Ten Months Ended | | | Year Ended | |
| | | | December 31, 2013 | | | December 31, 2012 | | | February 29, 2012 | |
| | Net income (loss) for the period | $ | (3,832,078 | ) | $ | 61,361 | | $ | 942,665 | |
| | Weighted average number of common shares outstanding, basic | | 54,479,558 | | | 50,888,868 | | | 34,211,904 | |
| | Dilutive stock options and share purchase warrants | | - | | | 1,419,695 | | | 735,954 | |
| | Weighted average number of common shares outstanding, fully diluted | | 54,479,558 | | | 52,308,563 | | | 34,947,858 | |
| | Income per share, basic | $ | (0.07 | ) | $ | 0.00 | | $ | 0.03 | |
| | Income per share, fully diluted | $ | (0.07 | ) | $ | 0.00 | | $ | 0.03 | |
For the year ended December 31, 2013, the Company incurred a loss, therefore dilutive stock options and share purchase warrants were nil. For the ten months ended December 31, 2012, 1,625,000 stock options (year ended February 29, 2012 – 1,550,000) and 8,139,295 sharepurchase warrants (year ended February 29, 2012 – 9,351,976) were excluded from the fully diluted weighted-average common shares outstanding calculation because their exercise price was higher than the average market price for the period.
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13.Commitment
The Company will be relocating its office premises in June 2014 to accommodate its current and future expansion. The Company has a commitment to make monthly rental payments pursuant to the office rental agreement at its current location until July 31, 2014. Following the expiration of this agreement, the Company has entered into a rental agreement for the new office location, which expires May 30, 2018. The following table shows the Company’s rental commitment amounts for the next five fiscal years:
| | | 2014 | | | 2015 | | | 2016 | | | 2017 | | | 2018 | |
| Rental commitment | $ | 155,838 | | $ | 177,834 | | $ | 177,834 | | $ | 177,834 | | $ | 74,098 | |
14. Related Party Transactions
For the year ended December 31, 2013, the Company paid fees of $40,000 (ten months ended December 31, 2012 - $33,333, year ended February 29, 2012 - $115,000) to a director of the Company. These fees were charged for services provided by the Chairman of the Company’s Board of Directors.
Remuneration of key executive personnel, consisting of the Company’s officers and directors, were awarded as follows for the year ended December 31, 2013, ten months ended December 31, 2012 and year ended February 29, 2012:
| | | Year Ended | | | 10 Months Ended | | | Year Ended | |
| | | December 31, 2013 | | | December 31, 2012 | | | February 29, 2012 | |
| Short-term benefits | $ | 750,000 | | $ | 540,416 | | $ | 448,333 | |
| Share-based payments | $ | 125,808 | | $ | 196,386 | | $ | 649,537 | |
No long-term benefits were paid to related parties.
15.Supplemental Cash Flow Information
| | | Year Ended | | | 10 Months Ended | | | Year Ended | |
| | | December 31, 2013 | | | December 31, 2012 | | | February 29, 2012 | |
| Provided by (used in): | | | | | | | | | |
| Accounts receivable | $ | (137,953 | ) | $ | 347,931 | | $ | (1,227,432 | ) |
| Prepaid expenses | | 12,597 | | | (89,734 | ) | | (14,432 | ) |
| Accounts payable and accrued liabilities | | (936,332 | ) | | 2,814,444 | | | 849,072 | |
| Total changes in non-cash working capital | $ | (1,061,688 | ) | $ | 3,072,641 | | $ | (392,792 | ) |
| Provided by (used in): | | | | | | | | | |
| Operating activities | $ | (123,927 | ) | $ | 406,975 | | $ | (1,100,252 | ) |
| Investing activities | | (947,511 | ) | | 2,665,666 | | | 707,460 | |
| Financing activities | | 9,750 | | | - | | | - | |
| Total changes in non-cash working capital | $ | (1,061,688 | ) | $ | (3,072,641 | ) | $ | (392,792 | ) |
16.Subsequent Events
(a) On January 25, 2014, 43,450 share purchase warrants issued in conjunction with a private placement in January 2013 expired. An additional 700 finders’ warrants that were issued for the same private placement also expired.
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(b) On January 27, 2014, 7,110,454 share purchase warrants issued in conjunction with a private placement in January 2012 expired. Of these share purchase warrants, 86,256 were issued as corporate finance units and 862,620 were issued as finders’ warrants.
(c) On February 19, 2014, the Company received proceeds of $28,125 for the exercise of 37,500 share purchase warrants with an exercise price of $0.75.
(d) On March 31, 2014, 5,000 stock options were cancelled for an individual who no longer provides services to the Company.
17. Income Taxes
Effective April 1, 2013, the British Columbia provincial tax increased from 10% to 11% and the Canadian federal corporate tax rate remained unchanged at 15%. The overall increase in tax rates has resulted in an increase in the Company’s statutory tax rate from 25.00% to 25.75% .
The reconciliation of income tax computed at the statutory tax rate of 25.75% (ten months ended December 31, 2012 – 25.0%, year ended February 29, 2012 – 26.5%) to income tax (recovery) expense is:
| | | Year Ended | | | Ten Months Ended | | | Year Ended | |
| | | December 31, 2013 | | | December 31, 2012 | | | February 29, 2012 | |
| Income (loss) before income taxes | $ | (5,307,312 | ) | $ | 543,818 | | $ | (451,879 | ) |
| Statutory income tax rate | | 25.75% | | | 25.0% | | | 26.5% | |
| Expected income tax expense (recovery) | | (1,366,633 | ) | | 135,955 | | | (119,748 | ) |
| Non-deductible items | | 94,497 | | | 74,299 | | | 288,781 | |
| Over (under) provided in prior periods | | 26,036 | | | - | | | (79,721 | ) |
| Temporary differences of property and equipment and evaluation and exploration assets | | (176,391 | ) | | 272,203 | | | 101,942 | |
| Effect of change in tax rate | | (52,743 | ) | | - | | | 9,351 | |
| Recognized tax benefits | | - | | | - | | | (1,595,149 | ) |
| Deferred tax expense (recovery) | $ | (1,475,234 | ) | $ | 482,457 | | $ | (1,394,544 | ) |
The tax affected items that give rise to significant portions of the deferred tax asset at December 31, 2013 and December 31, 2012 are presented below:
| | | December 31, 2013 | | | December 31, 2012 | |
| Deferred tax assets | | | | | | |
| Non-capital losses | $ | 1,839,139 | | $ | 1,133,375 | |
| Exploration and evaluation assets | | 4,801,435 | | | 3,795,028 | |
| Share issue costs | | 241,943 | | | 183,126 | |
| Other | | 348,705 | | | 146,658 | |
| | | 7,231,222 | | | 5,258,187 | |
| Deferred income tax liability | | | | | | |
| Property and equipment | | (4,843,901 | ) | | (4,346,100 | ) |
| | $ | 2,387,321 | | $ | 912,087 | |
The Company has begun recognizing its deferred tax assets since the year ended February 29, 2012, as it is probable that future taxable profits will be available.
The Company does not have any remaining unrecognized deductible temporary differences and unused tax losses for which no deferred tax assets are recognized.
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As at December 31, 2013, the Company has non-capital losses of approximately $7,074,000 that may be applied to reduce future Canadian taxable income, expiring as follows:
| Available to | | | |
| 2014 | $ | 502,000 | |
| 2025 | | 547,000 | |
| 2026 | | 341,000 | |
| 2027 | | 216,000 | |
| 2028 | | 312,000 | |
| 2029 | | 323,000 | |
| 2030 | | 557,000 | |
| 2031 | | 623,000 | |
| 2032 | | 1,113,000 | |
| 2033 | | 2,540,000 | |
| | $ | 7,074,000 | |
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SUPPLEMENTARY OIL AND GAS RESERVE ESTIMATION AND DISCLOSURES – ASC 932 (UNAUDITED)
Select supplementary oil and gas reserve estimation and disclosure are provided in accordance with U.S. disclosure requirements. The standards of the SEC require that proved reserves be estimated using existing economic conditions (constant pricing). Based on this methodology, our results have been calculated using the 12-month average price for each of the years presented within this supplementary disclosure.
(a) Net proved oil and gas reserves
As at December 31, 2013, all of our oil and gas reserves are located in Canada.
McDaniel & Associates Consultants (“McDaniel”) of Calgary, Alberta, independent petroleum engineering consultants, were retained to evaluate our properties. Their report, titled “Evaluation of Oil and Gas Reserves, Hemisphere Energy Corporation”, was completed May 27, 2014 and has an effective date of December 31, 2013.
Sproule Associates Limited (“Sproule”) of Calgary, Alberta, independent petroleum engineering consultants were also retained to evaluate our properties as of February 29, 2012 and December 31, 2012. Their reports titled “Evaluation of the P&NG Reserves of Hemisphere Energy Corporation (As of February 29, 2012) Constant Dollars” and “Evaluation of the P&NG Reserves of Hemisphere Energy Corporation (As of December 31, 2012) Constant Dollars” were completed on September 12, 2014 and have effective dates of February 29, 2012 and December 31, 2012, respectively.
In accordance with the US Securities and Exchange Commission’s (“SEC”) definitions and guidelines, McDaniel and Sproule, have used constant prices and costs in estimating the reserves and future net cash flows contained in their reports. Actual future net cash flows will be affected by other factors, such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.
The tables in this section set forth oil and gas information prepared in accordance with U.S. disclosure standards, including Accounting Standards Codification 932 (“ASC 932”). Reserves have been estimated in accordance with the US Securities and Exchange Commission’s (“SEC”) definitions and guidelines. The changes in our net proved reserve quantities are outlined below.
Net reserves are our royalty and working interest remaining reserves, less all Crown, freehold, and overriding royalties and interests that are not owned by us.
Proved reserves are those estimated quantities of crude oil, natural gas and natural gas liquids that can be estimated with a high degree of certainty to be economically recoverable under existing economic and operating conditions. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Proved developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. Developed reserves may be subdivided into producing and non-producing.
Proved undeveloped reserves are those reserves that are expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production.
Users of the information are cautioned as the process of estimating crude oil and natural gas reserves is subject to a level of uncertainty. The reserves are based on economic and operating conditions; therefore, changes can be made to future assessments as a result of a number of factors, which can include new technology, changing economic conditions and development activity.
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| Quantity Information |
| For the Year Ended December 31, 2013 |
| | | | | | Total Canada, North America | | | | |
| | | Heavy Oil | | | Natural Gas | | | Natural Gas | | | Barrel of Oil | |
| | | (Mbbl) | | | (MMcf) | | | Liquids | | | Equivalent | |
| | | | | | | | | (Mbbl) | | | (Mboe) | |
| December 31, 2012 | | | | | | | | | | | | |
| Beginning of year | | 639 | | | 67 | | | 2 | | | 651 | |
| Revision of Previous estimates | | 71 | | | 272 | | | 0 | | | 117 | |
| Improved Recovery | | | | | | | | | | | | |
| Purchases of mineral in place | | 222 | | | 252 | | | | | | 264 | |
| Extensions and discoveries | | 181 | | | 117 | | | 0 | | | 201 | |
| Production | | -121 | | | -155 | | | -1 | | | -147 | |
| Sales of minerals in place | | | | | | | | | | | | |
| End of year | | 992 | | | 554 | | | 1 | | | 1,085 | |
| December 31, 2013 | | | | | | | | | | | | |
| Developed Producing | | 448 | | | 406 | | | 1 | | | 517 | |
| Developed Non-Producing | | 21 | | | 2 | | | 0 | | | 21 | |
| Undeveloped | | 523 | | | 145 | | | 0 | | | 547 | |
| Total | | 992 | | | 554 | | | 1 | | | 1,085 | |
Quantity Information For the Year Ended December 31, 2012
| | | | | | Total Canada, North America | | | | |
| | | Heavy Oil | | | Natural Gas | | | Natural Gas | | | Barrel of Oil | |
| | | (Mbbl) | | | (MMcf) | | | Liquids | | | Equivalent | |
| | | | | | | | | (Mbbl) | | | (Mboe) | |
| February 29, 2012 | | | | | | | | | | | | |
| Beginning of year | | 277 | | | 293 | | | 5 | | | 331 | |
| Revisions of Previous estimates | | 118 | | | -178 | | | -3 | | | 85 | |
| Improved Recovery | | | | | | | | | | | | |
| Purchases of mineral in place | | | | | | | | | | | | |
| Extensions and discoveries | | 349 | | | | | | | | | 349 | |
| Production | | -105 | | | -48 | | | -1 | | | -114 | |
| Sales of minerals in place | | | | | | | | | | | | |
| End of year | | 639 | | | 67 | | | 2 | | | 651 | |
| December 31, 2012 | | | | | | | | | | | | |
| Developed Producing | | 401 | | | 67 | | | 2 | | | 414 | |
| Developed Non-Producing | | 21 | | | 0 | | | 0 | | | 21 | |
| Undeveloped | | 217 | | | 0 | | | 0 | | | 217 | |
| Total | | 639 | | | 67 | | | 2 | | | 651 | |
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(b)Capitalized Costs
| Capitalized Costs Relating to Oil and Gas Producing Activities |
| At December 31, 2013, December 31, 2012 and February 29, 2012 (CA$) |
| | | Entity’s Share of Equity Method Investees | |
| | | 12 Months Ended | | | 10 Months Ended | | | 12 Months Ended | |
| | | December 31, 2013 | | | December 31, 2012 | | | February 29, 2012 | |
| Unproved oil and gas properties | $ | 1,894,498 | | $ | 3,189,762 | | $ | 2,161,743 | |
| Proved oil and gas properties | | 38,614,429 | | | 26,496,155 | | | 15,662,173 | |
| Total capital costs | | 40,508,927 | | | 29,685,917 | | | 17,823,916 | |
| Accumulated depletion and depreciation | | 7,479,356 | | | 4,390,392 | | | 2,150,696 | |
| Impairment | | 7,593,507 | | | 1,952,936 | | | 1,767,988 | |
| Net capitalized costs | $ | 25,436,064 | | $ | 23,342,589 | | $ | 13,905,232 | |
(c) Costs Incurred
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
For the Year Ended December 31, 2013, Ten Months Ended December 31, 2012 and Year Ended February 29, 2012 (CA$)
| | | Total Canada, North America | |
| | | 12 Months Ended | | | 10 Months Ended | | | 12 Months Ended | |
| | | December 31, 2013 | | | December 31, 2012 | | | February 29, 2012 | |
| | | | | | | | | | |
| Acquisition of properties: | | | | | | | | | |
| Proved oil and gas properties | $ | 3,092,055 | | $ | - | | $ | 7,128,866 | |
| Unproved oil and gas properties | | 132,582 | | | 211,292 | | | 350,109 | |
| Exploration costs(1) | | 352,808 | | | 251,605 | | | 203,987 | |
| Development costs(2) | | 6,391,729 | | | 11,425,501 | | | 6,124,875 | |
| Capital expenditures | $ | 9,969,174 | | $ | 11,888,398 | | $ | 13,807,837 | |
Notes:
| | (1) | Geological and geophysical capital expenditures and preliminary drill costs for exploration wells |
| | (2) | Includes equipping and facilities capital expenditures |
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(d) Results of Operations of Producing Activities
Results of Operations for Oil and Gas Producing Activities
For the Year Ended December 31, 2013, Ten Months Ended December 31, 2012 and Year Ended February 29, 2012 (CA$)
| | | Total Canada, North America | |
| | | 12 Months Ended | | | 10 Months Ended | | | 12 Months Ended | |
| | | December 31, 2013 | | | December 31, 2012 | | | February 29, 2012 | |
| | | | | | | | | | |
| Revenues: | | | | | | | | | |
| Oil and gas sales, net of royalties | $ | 8,674,667 | | $ | 6,503,839 | | $ | 3,888,263 | |
| Transfers | | - | | | - | | | | |
| Total | | 8,674,667 | | | 6,503,839 | | | 3,888,263 | |
| Production and operating expense | | 3,067,174 | | | 1,846,532 | | | 945,719 | |
| Exploration and evaluation expense | | 116,006 | | | 120,882 | | | - | |
| Depreciation, depletion, accretion amortization and valuation allowances | | 8,736,048 | | | 2,438,967 | | | 1,325,647 | |
| Income tax (expense) recovery | | 1,475,234 | | | (482,457 | ) | | 1,394,544 | |
| Results of operations from producing activities (excluding corporate overhead and interest costs) | $ | (1,769,328 | ) | $ | 1,615,002 | | $ | 3,011,441 | |
(e) Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
The standardized measure of discounted future net cash flows is based on estimates made by McDaniel and Sproule of net proved reserves. Future cash inflows are computed based on the average of the first day constant prices in each of the 12 months for the year ended December 31, 2013 and cost assumptions applied against annual future production from proved crude oil and natural gas reserves. Future development and production costs are computed based on the average of the first day constant prices in each of the 12 months for the year ended December 31, 2013 and assume the continuation of existing economic conditions. Future income taxes are calculated by applying statutory income tax rates. We are currently not taxable. The standardized measure of discounted future net cash flows is computed using a 10 percent discount factor.
Users of the information are cautioned that the discounted future net cash flows relating to proved oil and gas reserves are neither an indication of the fair market value of our oil and gas properties, nor of the future net cash flows expected to be generated from such properties. The discounted future cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent is arbitrary and may not appropriately reflect future interest rates.
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| Standardized Measure of Discounted Future Net Cash Flows |
| At December 31, 2013 (CA$ thousands) |
| | | | | | | |
| | | Canada | | | Total | |
| Future cash inflows after royalties | $ | 72,176 | | $ | 72,176 | |
| Future production, abandonment and salvage costs | $ | (30,576 | ) | $ | (30,576 | ) |
| Future development costs | $ | (10,490 | ) | $ | (10,490 | ) |
| Future income tax expenses | $ | (1,277 | ) | $ | (1,277 | ) |
| Future net cash flows | $ | 29,833 | | $ | 29,833 | |
| 10% annual discount for estimated timing of cash flows | $ | (7,745 | ) | $ | (7,745 | ) |
| Standardized measure of discounted future net cash flows | $ | 22,088 | | $ | 22,088 | |
| Standardized Measure of Discounted Future Net Cash Flows |
| At December 31, 2012 (CA$ thousands) |
| | | Canada | | | Total | |
| Future cash inflows after royalties | $ | 46,253 | | $ | 46,253 | |
| Future production, abandonment and salvage costs | $ | (16,830 | ) | $ | (16,830 | ) |
| Future development costs | $ | (5,720 | ) | $ | (5,720 | ) |
| Future income tax expenses | $ | (1,740 | ) | $ | (1,740 | ) |
| Future net cash flows | $ | 21,963 | | $ | 21,963 | |
| 10% annual discount for estimated timing of cash flows | $ | (4,821 | ) | $ | (4,821 | ) |
| Standardized measure of discounted future net cash flows | $ | 17,142 | | $ | 17,142 | |
(f) Changes in Standardized Measure of Discounted Net Cash Flows
For the Year Ended December 31, 2013 (CA$ thousands)
| | | Total | |
| Beginning Balance, January 1, 2013 | $ | 17,142 | |
| | | | |
| Sales and transfers of oil and gas produced during the period | | (5,437 | ) |
| Net change in sales and transfer prices and in production (lifting) costs | | (247 | ) |
| Change in estimated future development costs | | (8,123 | ) |
| Net change due to extension, discoveries, and improved recovery | | 3,971 | |
| Net change due to purchase and sale of minerals in place | | 3,838 | |
| Development costs incurred during the period | | 6,400 | |
| Net change due to revisions in quantity estimates and timing | | 2,184 | |
| Accretion of discount | | 1,853 | |
| Other-unspecified | | - | |
| Net change in income taxes | | 507 | |
| | | | |
| Ending Balance, December 31, 2013 | $ | 22,088 | |
130
For the Year Ended December 31, 2012 (CA$ thousands)
| | | Total | |
| Beginning Balance, February 29, 2012 | $ | 10,282 | |
| | | | |
| Sales and transfers of oil and gas produced during the period | | (4,657 | ) |
| Net change in sales and transfer prices and in production (lifting) costs | | (1,043 | ) |
| Change in estimated future development costs | | (10,167 | ) |
| Net change due to extension, discoveries, and improved recovery | | 9,589 | |
| Net change due to purchase and sale of minerals in place | | - | |
| Development costs incurred during the period | | 11,400 | |
| Net change due to revisions in quantity estimates and timing | | 2,098 | |
| Accretion of discount | | 1,028 | |
| Other-unspecified | | - | |
| Net change in income taxes | | (1,388 | ) |
| | | | |
| Ending Balance, December 31, 2012 | $ | 17,142 | |
131
| CONDENSED STATEMENTS OF FINANCIAL POSITION |
| (Expressed in Canadian dollars) |
| (Unaudited) |
| | | Note | | | June 30, 2014 | | | December 31, 2013 | |
| Assets | | | | | | | | | |
| Current assets | | | | | | | | | |
| Cash | | | | $ | 1,352,978 | | $ | - | |
| Accounts receivable | | | | | 1,132,770 | | | 1,042,407 | |
| Prepaid expenses | | | | | 88,152 | | | 103,172 | |
| | | | | | 2,573,900 | | | 1,145,579 | |
| | | | | | | | | | |
| Non-current assets | | | | | | | | | |
| Reclamation deposits | | 9 | | | 105,535 | | | 105,535 | |
| Exploration and evaluation assets | | 7 | | | 3,614,805 | | | 1,894,497 | |
| Property and equipment | | 8 | | | 28,371,393 | | | 23,541,568 | |
| Deferred tax asset | | 17 | | | 2,387,321 | | | 2,387,321 | |
| Total assets | | | | $ | 37,052,954 | | $ | 29,074,500 | |
| | | | | | | | | | |
| Liabilities | | | | | | | | | |
| Current liabilities | | | | | | | | | |
| Accounts payable and accrued liabilities | | | | $ | 4,485,503 | | $ | 2,976,486 | |
| Bank indebtedness | | 11 | | | - | | | 4,500,000 | |
| Flow-through premium liability | | | | | 369,240 | | | 369,240 | |
| Total current liabilities | | | | | 4,854,743 | | | 7,845,726 | |
| | | | | | | | | | |
| Non-current liabilities | | | | | | | | | |
| Decommissioning obligations | | 9 | | | 1,371,609 | | | 1,323,446 | |
| | | | | | 6,226,352 | | | 9,169,172 | |
| | | | | | | | | | |
| Shareholders’ Equity | | | | | | | | | |
| Capital stock | | 12 | | | 51,370,717 | | | 42,127,674 | |
| Share-based payment reserve | | 12 (c) | | | 2,134,495 | | | 2,574,789 | |
| Warrant reserve | | 12 (d) | | | 83,651 | | | 204,479 | |
| Deficit | | | | | (22,762,261 | ) | | (25,001,614 | ) |
| Total shareholders’ equity | | | | | 30,826,602 | | | 19,905,328 | |
| Total liabilities and shareholders’ equity | | | | $ | 37,052,954 | | $ | 29,074,500 | |
The accompanying notes are an integral part of these financial statements.
| On Behalf of the Board of Directors | | |
| | | |
| (signed) “Bruce McIntyre” | | (signed) “Don Simmons” |
| Bruce McIntyre, Director | | Don Simmons, Director |
132
| CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) |
| (Expressed in Canadian dollars) |
| (Unaudited) |
| | | | | | Three Months Ended | | | Six Months Ended | |
| | | Note | | | June 30, 2014 | | | June 30, 2013 | | | June 30, 2014 | | | June 30, 2013 | |
| Oil and natural gas revenue | | | | $ | 3,799,461 | | $ | 2,375,912 | | $ | 7,363,497 | | $ | 4,449,530 | |
| Royalties | | | | | (777,349 | ) | | (402,299 | ) | | (1,329,017 | ) | | (697,290 | ) |
| Net oil and natural gas revenue | | | | | 3,022,112 | | | 1,973,613 | | | 6,034,480 | | | 3,752,240 | |
| | | | | | | | | | | | | | | | |
| Expenses | | | | | | | | | | | | | | | |
| Production and operating | | | | | 1,011,000 | | | 698,869 | | | 2,145,365 | | | 1,361,939 | |
| Exploration and evaluation | | 7 | | | 12,513 | | | 12,262 | | | 41,666 | | | 24,669 | |
| Depletion and depreciation | | 8 | | | 711,586 | | | 604,801 | | | 1,365,974 | | | 1,195,245 | |
| General and administrative | | | | | 378,580 | | | 367,645 | | | 652,320 | | | 713,218 | |
| | | | | | 2,113,679 | | | 1,683,577 | | | 4,205,325 | | | 3,295,071 | |
| Results from operating activities | | | | | 908,433 | | | 290,036 | | | 1,829,155 | | | 457,168 | |
| Finance expense | | 10 | | | (78,111 | ) | | (49,006 | ) | | (153,866 | ) | | (81,714 | ) |
| Gain on disposition | | | | | - | | | - | | | 2,942 | | | - | |
| Net income and comprehensive | | | | | | | | | | | | | | | |
| income for the period | | | | $ | 830,322 | | $ | 241,029 | | $ | 1,678,231 | | $ | 375,454 | |
| Income per share | | | | | | | | | | | | | | | |
| Basic and diluted | | 12 (e) | | $ | 0.01 | | $ | 0.00 | | $ | 0.03 | | $ | 0.01 | |
The accompanying notes are an integral part of these financial statements.
133
| CONDENSED STATEMENTS OF CASH FLOWS |
| (Expressed in Canadian dollars) |
| (Unaudited) |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, 2014 | | | June 30, 2013 | | | June 30, 2014 | | | June 30, 2013 | |
| Operating activities | | | | | | | | | | | | |
| Net income for the period | $ | 830,322 | | $ | 241,029 | | $ | 1,678,231 | | $ | 375,454 | |
| Items not affecting cash: | | | | | | | | | | | | |
| Depletion, depreciation and accretion | | 720,339 | | | 606,430 | | | 1,383,479 | | | 1,198,502 | |
| Gain on disposition | | - | | | - | | | (2,942 | ) | | - | |
| Share-based payments | | - | | | - | | | - | | | 65,070 | |
| Funds flow from operating activities | | 1,550,661 | | | 847,459 | | | 3,058,768 | | | 1,639,026 | |
| | | | | | | | | | | | | |
| Changes in non-cash working capital | | 495,387 | | | (253,364 | ) | | (212,187 | ) | | (58,439 | ) |
| Cash provided by operating activities | | 2,046,048 | | | 594,094 | | | 2,846,582 | | | 1,580,586 | |
| Investing activities | | | | | | | | | | | | |
| Property and equipment expenditures | | (1,362,310 | ) | | (1,546,808 | ) | | (5,130,528 | ) | | (2,203,473 | ) |
| Exploration and evaluation expenditures | | (2,152,881 | ) | | 774,157 | | | (2,801,980 | ) | | (202,315 | ) |
| Proceeds from disposition of equipment | | - | | | - | | | 50,000 | | | - | |
| Reclamation deposits | | - | | | - | | | - | | | (5,000 | ) |
| Changes in non-cash working capital | | 1,257,203 | | | (793,943 | ) | | 1,645,861 | | | (2,578,079 | ) |
| Cash used in investing activities | | (2,257,988 | ) | | (1,566,594 | ) | | (6,236,647 | ) | | (4,988,868 | ) |
| Financing activities | | | | | | | | | | | | |
| Shares issued for cash, net of issue costs | | 9,214,919 | | | - | | | 9,243,044 | | | 56,029 | |
| Proceeds from bank indebtedness | | (7,650,000 | ) | | 972,500 | | | (4,500,000 | ) | | 3,342,500 | |
| Changes in non-cash working capital | | - | | | - | | | - | | | 9,750 | |
| Cash provided by financing activities | | 1,564,919 | | | 972,500 | | | 4,743,044 | | | 3,408,279 | |
| | | | | | | | | | | | | |
| Inflow (outflow) of cash | | 1,352,978 | | | - | | | 1,352,978 | | | - | |
| Cash, beginning of period | | - | | | - | | | - | | | - | |
| Cash, end of period | $ | 1,352,978 | | $ | - | | $ | 1,352,978 | | $ | - | |
| The accompanying notes are an integral part of these financial statements. |
| |
| Supplemental cash flow information (Note 15) |
134
| CONDENSED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY |
| (Expressed in Canadian dollars) |
| (Unaudited) |
| | | | | | Number of | | | | | | Share-based | | | | | | | | | | |
| | | | | | common | | | | | | payment | | | Warrant | | | | | | | |
| | | Note | | | shares | | | Capital stock | | | reserve | | | reserve | | | Deficit | | | Total Equity | |
| Balance, December 31, 2012 | | | | | 53,961,048 | | $ | 38,805,193 | | $ | 2,214,325 | | $ | 183,572 | | $ | (21,242,708 | ) | $ | 19,960,382 | |
| Non-flow- through share issuance | | | | | 4,269,450 | | | 2,262,808 | | | - | | | 94,079 | | | - | | | 2,356,887 | |
| Flow-through share issuance | | | | | 3,077,000 | | | 2,000,050 | | | - | | | - | | | - | | | 2,000,050 | |
| Share-based payments | | | | | - | | | - | | | 360,464 | | | - | | | - | | | 360,464 | |
| Share issuance costs | | | | | - | | | (571,137 | ) | | - | | | - | | | - | | | (571,137 | ) |
| Premium on issuance of flow-through shares | | | | | - | | | (369,240 | ) | | - | | | - | | | - | | | (369,240 | ) |
| Expiry of warrants | | | | | - | | | - | | | - | | | (73,172 | ) | | 73,172 | | | - | |
| Net loss for the year | | | | | - | | | - | | | - | | | - | | | (3,832,078 | ) | | (3,832,078 | ) |
| Balance, December 31, 2013 | | | | | 61,307,498 | | $ | 42,127,674 | | $ | 2,574,789 | | $ | 204,479 | | $ | (25,001,614 | ) | $ | 19,905,328 | |
| | | | | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2013 | | | | | 61,307,498 | | $ | 42,127,674 | | $ | 2,574,789 | | $ | 204,479 | | $ | (25,001,614 | ) | $ | 19,905,328 | |
| Non-flow- through share issuance | | 12 | (c) | | 13,333,500 | | | 10,000,125 | | | - | | | - | | | - | | | 10,000,125 | |
| Share issuance costs | | 12 | (c) | | - | | | (921,007 | ) | | - | | | - | | | - | | | (921,007 | ) |
| Warrant exercise | | 12 | (b) | | 37,500 | | | 28,125 | | | - | | | - | | | - | | | 28,125 | |
| Stock option exercise | | 12 | (c) | | 375,000 | | | 135,800 | | | (111,100 | ) | | - | | | 111,100 | | | 135,800 | |
| Expiry of warrants | | 12 | (d) | | - | | | - | | | (329,194 | ) | | (120,828 | ) | | 450,022 | | | - | |
| Net income for the period | | | | | - | | | - | | | - | | | - | | | 1,678,231 | | | 1,678,231 | |
| Balance, June 30, 2014 | | | | | 75,053,498 | | $ | 51,370,717 | | $ | 2,134,495 | | $ | 83,651 | | $ | (22,762,261 | ) | $ | 30,826,602 | |
135
Comparison with six months ended June 30, 2013
| | | Number of | | | | | | Share-based | | | | | | | | | | |
| | | common | | | | | | payment | | | Warrant | | | | | | | |
| | | shares | | | Capital stock | | | reserve | | | reserve | | | Deficit | | | Total Equity | |
| Balance, December 31, 2012 | | 53,961,048 | | $ | 38,805,193 | | $ | 2,214,325 | | $ | 183,572 | | $ | (21,242,708 | ) | $ | 19,960,382 | |
| Share-based payments | | - | | | - | | | 65,070 | | | - | | | - | | | 65,070 | |
| Share issuance | | 86,900 | | | 56,485 | | | - | | | - | | | - | | | 56,485 | |
| Share issuance costs | | - | | | (456 | ) | | - | | | - | | | - | | | (456 | ) |
| Net income for the period | | - | | | - | | | - | | | - | | | 375,454 | | | 375,454 | |
| Balance, June 30, 2013 | | 54,047,948 | | $ | 38,861,222 | | $ | 2,279,395 | | $ | 183,572 | | $ | (20,867,254 | ) | $ | 20,456,937 | |
The accompanying notes are an integral part of these financial statements.
136
| NOTES TO THE CONDENSED INTERIM FINANCIAL STATEMENTS |
| For the three and six months ended June 30, 2014 and 2013 |
| (Expressed in Canadian dollars) |
| (Unaudited) |
| 1. | Nature and Continuance of Operations |
Hemisphere Energy Corporation (the "Company") was incorporated under the laws of British Columbia on March 6, 1978. The Company’s principal business is the acquisition, exploration, development and production of petroleum and natural gas interests. It is a publicly traded company listed on the TSX Venture Exchange under the symbol "HME". The Company’s head office is located at 2000-1055 West Hastings Street, Vancouver, British Columbia, Canada V6E 2E9.
| | (a) | Statement of compliance |
| | | |
| | | These unaudited condensed interim financial statements ("Financial Statements") have been prepared in accordance with International Accounting Standard (“IAS”) 34 – Interim Financial Reporting using accounting policies consistent with the International Financial Reporting Standards ("IFRS"), as issued by the International Accounting Standards Board ("IASB"). These Financial Statements do not include all of the information required for full annual financial statements and should be read in conjunction with the Company’s audited annual financial statements for the twelve months ended December 31, 2013. |
| | | |
| | | These Financial Statements were authorized for issuance by the Board of Directors on August 26, 2014. |
| | | |
| | (b) | Basis of presentation |
| | | |
| | | These Financial Statements have been prepared on a historical cost basis, except for financial instruments, which are stated at their fair values. In addition, these Financial Statements have been prepared using the accrual basis of accounting, except for cash flow information. |
| | | |
| | (c) | Functional and presentation currency |
| | | |
| | | These Financial Statements are presented in Canadian dollars, which is the Company’s functional currency. |
| | | |
| | (d) | Use of estimates and judgments |
| | | |
| | | The preparation of these Financial Statements in conformity with IFRS requires management to make judgments, estimates and assumptions that may affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates. |
Following are the accounting policies subject to such judgments and the key sources of estimation uncertainty that the Company believes could have the most significant impact on the reported results and financial position.
Reserves
The estimate of oil and natural gas reserves is integral to the calculation of the amount of depletion charged to the statements of loss and comprehensive loss and is also a key determinant in assessing whether the carrying value of any of the Company’s development and production assets have been impaired. Changes in reported reserves can impact asset carrying values and the decommissioning provision due to changes in expected future cash flows. The Company’s reserves are evaluated and reported on by independent reserve engineers at least annually in accordance with Canadian Securities Administrators’ National Instrument 51-101 Standards of Disclosure of Oil and Gas Activities. Reserve estimation is based on a variety of factors including engineering data, geological and geophysical data, projected future rates of production, commodity pricing and timing of future expenditures, all of which are subject to significant judgment and interpretation.
137
Carrying value of property and equipment and exploration and evaluation assets
The Company assesses at each reporting date whether there is an indication that an asset or cash-generating unit ("CGU") may be impaired. A CGU is defined as the lowest grouping of assets that generate identifiable cash inflows that are largely independent of cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires significant judgment and interpretation with respect to the way in which management monitors operations. If any indication exists that an asset or CGU may be impaired, the Company estimates the recoverable amount. The recoverable amounts of individual assets and CGUs have been determined based on the higher of value-in-use calculations and fair value less costs to sell. These calculations require the use of estimates and assumptions, such as estimates of proved plus probable reserves, future production rates, oil and natural gas prices, future costs and other relevant assumptions, all of which are subject to change.
A material adjustment to the carrying value of the Company’s property and equipment and exploration and evaluation assets could arise as a result of changes to these estimates and assumptions.
Critical accounting estimates
Decommissioning obligations
Amounts recorded for decommissioning obligations require the use of management’s best estimates of future decommissioning expenditures, expected timing of expenditures and future inflation rates. The estimates are based on internal and third party information and calculations are subject to change over time and may have a material impact on profit and loss or financial position. For more information on the Company’s decommissioning obligations see note 9.
Share-based payments
The Company measures the cost of its share-based payments to directors, officers, employees and certain consultants by reference to the fair value of the equity instruments using the Black-Scholes option pricing model at the date they are granted. The assumptions used in determining fair value include: expected lives of options, risk-free rates of return and stock price volatility. Changes to assumptions may have a material impact on the amounts presented. For more information on the Company’s share-based payments see note 12(b).
Income taxes
Related assets and liabilities are recognized for the estimated tax consequences between amounts included in the financial statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly, affect the amount of the deferred tax asset or liability calculated at a point in time. These differences could materially impact earnings.
| 3. | Summary of Significant Accounting Policies |
These Financial Statements have been prepared in accordance with IFRS and follow the same accounting policies as described in Note 3 of the Company’s audited annual financial statements for the twelve months ended December 31, 2013. There have been no changes to the Company’s accounting policies since these Financial Statements were issued.
138
Fair value estimates of financial instruments are made at a specific point in time, based on relevant information about financial markets and specific financial instruments. As these estimates are subjective in nature, involving uncertainties and matters of significant judgment, they may be subject to future adjustment. Changes in assumptions can significantly affect estimated fair values. At June 30, 2014, the Company's financial instruments include cash, accounts receivable, reclamation deposits, bank indebtedness, and accounts payable and accrued liabilities.
The fair values of accounts receivable, reclamation deposits, accounts payable and accrued liabilities, and bank indebtedness approximate their carrying values due to the short-term maturity of these financial instruments.
| 5. | Financial Risk Management |
The Company’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production and financing activities such as credit risk, liquidity risk and market risk. This note presents information about the Company’s exposure to each of these risks. Management sets controls to manage such risks and monitors them on an ongoing basis pertaining to market conditions and the Company’s activities.
| | (a) | Credit risk |
| | | |
| | | Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its payment obligations. This risk arises principally from the Company’s receivables from joint venture partners and oil and natural gas marketers, and reclamation deposits. The credit risk associated with reclamation deposits is minimized substantially by ensuring this financial asset is placed with major financial institutions with strong investment-grade ratings by a primary ratings agency. The credit risk associated with accounts receivable is mitigated as the Company monitors monthly balances to limit the risk associated with collections. The Company does not anticipate any default. The maximum exposure to credit risk is as follows: |
| | | | June 30, 2014 | | | December 31, | |
| | | | | | | 2013 | |
| | Cash | $ | 1,352,978 | | $ | - | |
| | Accounts receivable | | 1,132,770 | | | 1,042,407 | |
| | Reclamation deposits | | 105,535 | | | 105,535 | |
| | | $ | 2,591,283 | | $ | 1,147,942 | |
| | (b) | Liquidity risk |
| | | |
| | | Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company’s approach to managing liquidity risk is to ensure, as far as possible, that it will have sufficient liquidity to meet its liabilities when they become due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company. |
| | | |
| | | At June 30, 2014, the Company had net debt of $1,911,603 (December 31, 2013 - $6,330,907), which includes bank indebtedness of $nil (December 31, 2013 - $4,500,000). The Company funds its operations through production revenue and a demand operating credit facility (Note 11). All of the Company’s financial liabilities have contractual maturities of less than 90 days. |
| | | |
| | (c) | Market risk |
| | | |
| | | Market risk is the risk that changes in market prices, such as foreign exchange rates, other prices and interest rates will affect the value of the financial instruments. Market risk is comprised of three types of risk: interest rate risk, foreign currency risk and other price risk. |
139
| | (i) | Interest rate risk |
| | | |
| | | Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. Borrowings under the Company’s credit facilities are subject to variable interest rates. A one percent change in interest rates would not have a material effect on net income (loss) and comprehensive income (loss). |
| | | |
| | (ii) | Foreign currency risk |
| | | |
| | | The Company is not exposed to significant foreign currency risk. |
| | | |
| | (iii) | Other price risk |
| | | |
| | | Other price risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate due to changes in market prices, other than those arising from interest rate risk or foreign currency risk. The Company is not exposed to significant other price risk. |
The Company manages its capital with the following objectives:
| | (a) | To ensure sufficient financial flexibility to achieve the Company’s ongoing business objectives including the replacement of production, funding of future growth opportunities and pursuit of accretive acquisitions; and |
| | | |
| | (b) | To maximize shareholder return through enhancing the Company’s share value. |
The Company monitors its capital structure and makes adjustments according to market conditions in an effort to meet its objectives given the current outlook of the Company and industry in general. The capital structure of the Company is composed of shareholders’ equity and the undrawn component of the Company’s credit facilities. The Company may manage its capital structure by issuing new shares, repurchasing outstanding shares, obtaining additional financing from the Company’s credit facilities, issuing new debt instruments or other financial or equity-based instruments, adjusting capital spending or disposing of assets. The capital structure is reviewed on an ongoing basis.
The Company’s capital structure as at June 30, 2014 and December 31, 2013 are as follows:
| | | June 30, 2014 | | | December 31, | |
| | | | | | 2013 | |
| Shareholders’ equity | $ | 30,826,602 | | $ | 19,905,328 | |
| Undrawn component of bank credit facilities | | 10,500,000 | | | 6,000,000 | |
| Total capital | $ | 41,326,602 | | $ | 25,905,328 | |
As at June 30, 2014, the Company had total available credit facilities of $10,500,000 (December 31, 2013 - $10,500,000) of which the Company had drawn $nil (December 31, 2013 - $4,500,000) (Note 11).
| 7. | Exploration and Evaluation Assets |
Exploration and evaluation assets consist of the Company’s exploration projects, which are pending the determination of proved reserves. A transfer from exploration and evaluation assets to property and equipment is made when the well has come on production or the exploration project has been completed. For the period ended June 30, 2014, the Company transferred $1,081,673 (fiscal year ended December 31, 2013 - $2,353,078) to property and equipment.
140
| Cost | | | |
| Balance, December 31, 2013 | $ | 1,894,498 | |
| Additions | | 2,843,646 | |
| Exploration and evaluation expense | | (41,666 | ) |
| Transfer to property and equipment | | (1,081,673 | ) |
| Balance, June 30, 2014 | $ | 3,614,805 | |
| | | Petroleum and | | | | | | | |
| | | Natural Gas | | | Other Equipment | | | Total | |
| Cost | | | | | | | | | |
| Balance, December 31, 2013 | $ | 38,546,910 | | $ | 67,522 | | $ | 38,614,432 | |
| Additions | | 5,090,544 | | | 23,584 | | | 5,114,128 | |
| Transfer from exploration and evaluation assets | | 1,081,673 | | | - | | | 1,081,673 | |
| Balance, June 30, 2014 | $ | 44,719,127 | | $ | 91,106 | | $ | 44,810,233 | |
| Accumulated Depletion, Depreciation, | | | | | | | | | |
| Amortization | | | | | | | | | |
| and Impairment Losses | | | | | | | | | |
| Balance, December 31, 2013 | $ | 15,018,360 | | $ | 54,504 | | $ | 15,072,864 | |
| Charge for year | | 1,363,373 | | | 2,603 | | | 1,365,975 | |
| Balance, June 30, 2014 | $ | 16,381,733 | | $ | 57,107 | | $ | 16,438,840 | |
| Net Book Value | | | | | | | | | |
| December 31, 2013 | $ | 23,528,550 | | $ | 13,018 | | $ | 23,541,568 | |
| June 30, 2014 | $ | 28,337,394 | | $ | 33,999 | | $ | 28,371,393 | |
| 9. | Decommissioning Obligations |
The Company’s decommissioning obligations result from its ownership interest in petroleum and natural gas assets including well sites and gathering systems. The total decommissioning obligation is estimated 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 years.
The Company estimates the total undiscounted amount of cash flows required to settle its decommissioning obligations as at June 30, 2014 is $2,336,800 (December 31, 2013 - $2,246,800). These payments are expected to be made over the next 24 years with the majority of costs to be incurred between 2019 and 2039. The discount factor, being the risk-free rate related to the liability, is 3.09% (December 31, 2013 - 3.09%) . Inflation of 1.10% (December 31, 2013 - 1.10%) has also been factored into the calculation. The Company also has $105,535 (December 31, 2013 - $105,535) in various reclamation bonds for its properties held by the British Columbia Ministry of Energy, Mines and Petroleum Resources.
| | | June 30, 2014 | | | December 31, | |
| | | | | | 2013 | |
| Decommissioning obligations, beginning of period | $ | 1,323,446 | | $ | 467,235 | |
| Increase in estimated future obligations | | 30,658 | | | 849,698 | |
| Accretion expense | | 17,505 | | | 6,513 | |
| Decommissioning obligations, end of period | $ | 1,371,609 | | $ | 1,323,446 | |
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| 10. | Finance Income and Expenses |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | | | June 30, | | | June 30, | |
| | | 2014 | | | 2013 | | | 2014 | | | 2013 | |
| Finance expense: | | | | | | | | | | | | |
| Interest expense | $ | 64,918 | | $ | 47,378 | | $ | 128,861 | | $ | 78,457 | |
| Part XII.6 tax | | 4,440 | | | - | | | 7,500 | | | - | |
| Accretion expense | | 8,753 | | | 1,628 | | | 17,506 | | | 3,257 | |
| Net finance expenses | $ | 78,111 | | $ | 49,006 | | $ | 153,866 | | $ | 81,714 | |
The Company has a demand operating credit facility in the amount of $10,500,000 with Alberta Treasury Branches under commitment letter as of September 25, 2013. The facility is secured by a general security agreement and a floating charge on all lands of the Company. The facility bears interest at the bank’s prime rate plus 1.75% as well as a standby charge for any undrawn funds.
Pursuant to the terms of the credit facility, the Company has provided a covenant that at all times its working capital ratio shall not be less than 1.0 to 1.0. The working capital ratio is defined under the terms of the credit facilities as current assets including the undrawn portion of the revolving operating demand line credit facility, to current liabilities, excluding any current bank indebtedness.
At June 30, 2014, the Company has drawn a total of $nil from the credit facility (December 31, 2013 - $4,500,000).
| | (a) | Authorized |
| | | |
| | | Unlimited number of common shares without par value. |
| | | |
| | (b) | Issued and outstanding |
| | | |
| | | On May 14, 2014, the Company closed a bought-deal equity financing consisting of 13,333,500 common shares at a price of $0.75 per common share for aggregate gross proceeds of $10,000,125. In conjunction with the closing of the bought-deal equity financing, the Company paid $700,009 in finders’ fees. The net proceeds of the financing will be used to accelerate the Company’s capital program focused on continuing development of the Atlee Buffalo and Jenner properties, as well as for general corporate purposes and reducing the current indebtedness under the credit facility. |
| | | |
| | | For the six months ended June 30, 2014, the Company issued 37,500 common shares for the exercise of share purchase warrants at a price of $0.75 for gross proceeds of $28,125. The Company also issued 375,000 common shares for the exercise of incentive stock options at various exercise prices for gross proceeds of $135,800. |
| | | |
| | (c) | Stock options |
| | | |
| | | The Company has a stock option plan in place and is authorized to grant stock options to officers, directors, employees and consultants whereby the aggregate number of shares reserved for issuance may not exceed 10% of the issued shares at the time of grant and 5% of the issued shares to each optionee. |
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Stock options are non-transferable and have a maximum term of five years. Stock options terminate no later than 90 days (30 days for investor-related services) upon termination of employment or employment contract and one year in the case of retirement, death or disability. The grant price may not be less than the last closing price of the Company’s shares and not less than $0.10 per share.
For the six months ended June 30, 2014, the Company received gross proceeds of $135,800 for the exercise of 375,000 stock options at various exercise prices.
Details of the Company’s stock options for the six months ended June 30, 2014 are as follows:
| | | | Balance | | | | Balance |
| | | | Outstanding & | | | | Outstanding & |
| | | | December 31, | | | Expired/ | Exercisable |
| | Exercise Price | Expiry Date | 2013 | Granted | Exercised | Cancelled | June 30, 2014 |
| | $0.27 | 28-Sep-14 | 445,000 | - | (125,000) | (5,000) | 315,000 |
| | $0.25 | 8-Mar-15 | 485,000 | - | (50,000) | - | 435,000 |
| | $0.26 | 30-Sep-15 | 520,000 | - | (30,000) | - | 490,000 |
| | $0.30 | 23-Dec-15 | 425,000 | - | (50,000) | - | 375,000 |
| | $0.30 | 27-Jan-16 | 200,000 | - | - | - | 200,000 |
| | $0.38 | 9-Feb-16 | 50,000 | - | - | - | 50,000 |
| | $0.40 | 26-May-16 | 520,000 | - | (45,000) | - | 475,000 |
| | $0.48 | 5-Jul-16 | 50,000 | - | - | - | 50,000 |
| | $0.70 | 8-Feb-17 | 1,550,000 | - | (50,000) | - | 1,500,000 |
| | $0.65 | 24-Apr-17 | 75,000 | - | - | - | 75,000 |
| | $0.61 | 5-Jul-17 | 425,000 | - | - | - | 425,000 |
| | $0.50 | 8-Mar-18 | 250,000 | - | - | - | 250,000 |
| | $0.55 | 6-Jan-19 | 685,000 | - | (25,000) | - | 660,000 |
| | | | 5,680,000 | - | (375,000) | (5,000) | 5,300,000 |
| | | | | | | | |
| | Weighted-average exercise price | | $0.48 | - | $0.36 | $0.27 | $0.49 |
Share based payments were nil for the three months ended June 30, 2014 and 2013 as the Company did not issue any stock options. For the six months ended June 30, 2014 and 2013, the Company recognized $nil and $65,070, respectively, in share-based payments. The fair value was determined using the Black-Scholes option pricing model with the following weighted-average assumptions:
| | | | June 30, 2014 | | | June 30, 2013 | |
| | Expected life (years) | | - | | | 5.00 | |
| | Interest rate | | - | | | 1.25% | |
| | Volatility | | - | | | 79.24% | |
| | Dividend yield | | - | | | 0.00% | |
| | Forfeiture rate | | - | | | 0.00% | |
The weighted-average grant date fair value for stock options granted during the six months ended June 30, 2014 was $nil (June 30, 2013 - $0.50).
Option pricing models require the input of highly subjective assumptions including the expected price volatility. Changes in the subjective input assumptions can materially affect the fair value estimate.
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| | (d) | Share purchase warrants |
On February 19, 2014, the Company received proceeds of $28,125 for the exercise of 37,500 share purchase warrants with an exercise price of $0.75.
Details of the Company’s share purchase warrants for the six months ended June 30, 2014 are as follows:
| | | | Balance Outstanding | | | | Balance |
| | | | & Exercisable | | | Expired/ | Outstanding |
| | Exercise | Expiry | December 31, 2013 | Issued | Exercised | Cancelled | & Exercisable |
| | Price | Date | | | | | June 30, 2014 |
| | $0.90 | 25-Jan-14 | 43,450 | - | - | (43,450) | - |
| | $0.90 | 25-Jan-14 | 700 | - | - | (700) | - |
| | $0.95 | 27-Jan-14 | 6,161,578 | - | - | (6,161,578 | - |
| | | | | | | ) | |
| | $0.95 | 27-Jan-14 | 86,256 | - | - | (86,256) | - |
| | $0.70 | 27-Jan-14 | 862,620 | - | - | (862,620) | - |
| | $0.75 | 10-Dec-14 | 2,091,275 | - | (37,500) | - | 2,053,775 |
| | | | 9,245,879 | - | (37,500) | (7,154,604 | 2,053,775 |
| | | | | | | ) | |
| | Weighted-average | | | | | |
| | exercise price | | $0.88 | - | $0.75 | $0.92 | $0.75 |
For the six months ended June 30, 2014, the Company removed $120,828 from the warrant reserve (twelve months ended December 31, 2013 - $73,172) and $440,294 from the share based payment reserve (twelve months ended December 31, 2013 - $nil) and recorded a corresponding recovery in deficit for expired warrants.
| | (e) | Income (loss) per share |
| | | | Three Months Ended | | | Six Months Ended | |
| | | | June 30, 2014 | | | June 30, | | | June 30, 2014 | | | June 30, | |
| | | | | | | 2013 | | | | | | 2013 | |
| | Net income for the period | $ | 830,322 | | $ | 241,029 | | $ | 1,678,231 | | $ | 375,454 | |
| | Weighted average number of common shares outstanding, basic | | 68,335,652 | | | 54,047,948 | | | 64,849,484 | | | 54,035,945 | |
| | Dilutive stock options and share purchase warrants | | 1,763,450 | | | 936,245 | | | 1,691,806 | | | 1,021,146 | |
| | Weighted average number of common shares outstanding, fully diluted | | 70,099,102 | | | 54,984,193 | | | 66,541,290 | | | 55,057,091 | |
| | Income per share, basic | $ | 0.01 | | $ | 0.00 | | $ | 0.03 | | $ | 0.01 | |
| | Income per share, fully diluted | $ | 0.01 | | $ | 0.00 | | $ | 0.03 | | $ | 0.01 | |
For the three and six months ended June 30, 2014, 2,053,775 share purchase warrants were excluded from the fully diluted weighted-average common shares outstanding calculation because their exercise price was higher than the average market price for the quarter.
144
The Company has a commitment to make monthly rental payments pursuant to the office rental agreement at its current location until July 31, 2014. Following the expiration of this agreement, the Company has entered into a rental agreement for its new office location, which expires May 30, 2018. The following table shows the Company’s rental commitment amounts for the next five fiscal years:
| | | 2014 | | | 2015 | | | 2016 | | | 2017 | | | 2018 | |
| Rental commitment | $ | 101,481 | | $ | 187,875 | | $ | 187,875 | | $ | 187,875 | | $ | 78,281 | |
| 14. | Related Party Transactions |
For the three and six months ended June 30, 2014, the Company paid fees of $10,000 and $20,000, respectively, to a director of the Company. These fees were charged for services provided by the Chairman of the Company’s Board of Directors.
Remuneration of key executive personnel, consisting of the Company’s officers and directors, were awarded as follows for the three and six months ended June 30, 2014 and 2013:
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | | | June 30, 2014 | | | June 30, 2013 | |
| | | 2014 | | | 2013 | | | | | | | |
| Short-term benefits | $ | 157,500 | | $ | 145,000 | | $ | 315,000 | | $ | 290,000 | |
| Share-based payments | $ | - | | $ | - | | $ | - | | $ | - | |
| No long-term benefits were paid to related parties. |
| 15. | Supplemental Cash Flow Information |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30, | | | June 30, | | | June 30, 2014 | | | June 30, 2013 | |
| | | 2014 | | | 2013 | | | | | | | |
| Provided by (used in): | | | | | | | | | | | | |
| Accounts receivable | $ | 434,568 | | $ | (46,530 | ) | $ | (90,363 | ) | $ | 107,326 | |
| Prepaid expenses | | 15,061 | | | 18,378 | | | 15,020 | | | 38,209 | |
| Accounts payable and accrued liabilities | | 1,302,961 | | | (1,019,15 5 | ) | | 1,509,017 | | | (2,772,303 | ) |
| | | | | | | | | | | | | |
| Total changes in non-cash working capital | $ | 1,752,590 | | $ | (1,047,307 | ) | $ | 1,433,674 | | $ | (2,626,768 | ) |
| Provided by (used in): | | | | | | | | | | | | |
| Operating activities | $ | 495,387 | | $ | (253,364 | ) | $ | (212,187 | ) | $ | (58,439 | ) |
| Investing activities | | 1,257,203 | | | (793,943 | ) | | 1,645,861 | | | (2,578,079 | ) |
| Financing activities | | - | | | - | | | - | | | 9,750 | |
| Total changes in non-cash working capital | $ | 1,752,590 | | $ | (1,047,307 | ) | $ | 1,433,674 | | $ | (2,626,768 | ) |
In July 2014, the Company closed an acquisition of certain pertroleum and natural gas leases in the Atlee Buffalo area. The property includes an 85% working interest in 1.75 sections (1,120 acres) of land adjacent to the Company’s existing landbase. Total consideration for the acquisition was $510,000.
145
In August 2014 the Company announced it completed its summer drilling program in the Atlee Buffalo area consisting of five development horizontal wells. Two of the five horizontal wells were on production for over 30 days producing within Hemisphere’s internal forecasted range at rates of approximately 100 boe/d (93% oil) and 65 boe/d (88% oil) respectively.
Effective April 1, 2013, the British Columbia provincial tax increased from 10% to 11% and the Canadian federal corporate tax rate remained unchanged at 15%. The overall increase in tax rates has resulted in an increase in the Company’s statutory tax rate from 25.00% to 25.75% .
The reconciliation of income tax computed at the statutory tax rate of 25.75% (ten months ended December 31, 2012 – 25.0%, year ended February 29, 2012 – 26.5%) to income tax (recovery) expense is:
| | | Year Ended | | | Ten Months Ended | |
| | | December 31, | | | December 31, 2012 | |
| | | 2013 | | | | |
| Income (loss) before income taxes | $ | (5,307,312 | ) | $ | 543,818 | |
| Statutory income tax rate | | 25.75% | | | 25.0% | |
| Expected income tax expense (recovery) | | (1,366,633 | ) | | 135,955 | |
| Non-deductible items | | 94,497 | | | 74,299 | |
| Over (under) provided in prior periods | | 26,036 | | | - | |
| Temporary differences of property and equipment and evaluation and exploration assets | | (176,391 | ) | | 272,203 | |
| Effect of change in tax rate | | (52,743 | ) | | - | |
| Recognized tax benefits | | - | | | - | |
| Deferred tax expense (recovery) | $ | (1,475,234 | ) | $ | 482,457 | |
The tax affected items that give rise to significant portions of the deferred tax asset at December 31, 2013 and December 31, 2012 are presented below:
| | | December 31, | | | December 31, 2012 | |
| | | 2013 | | | | |
| Deferred tax assets | | | | | | |
| Non-capital losses | $ | 1,839,139 | | $ | 1,133,375 | |
| Exploration and evaluation assets | | 4,801,435 | | | 3,795,028 | |
| Share issue costs | | 241,943 | | | 183,126 | |
| Other | | 348,705 | | | 146,658 | |
| | | 7,231,222 | | | 5,258,187 | |
| Deferred income tax liability | | | | | | |
| Property and equipment | | (4,843,901 | ) | | (4,346,100 | ) |
| | $ | 2,387,321 | | $ | 912,087 | |
The Company has begun recognizing its deferred tax assets since the year ended February 29, 2012, as it is probable that future taxable profits will be available.
The Company does not have any remaining unrecognized deductible temporary differences and unused tax losses for which no deferred tax assets are recognized.
As at December 31, 2013, the Company has non-capital losses of approximately $7,074,000 that may be applied to reduce future Canadian taxable income, expiring as follows:
| Available to | | | |
| 2014 | $ | 502,000 | |
| 2025 | | 547,000 | |
| 2026 | | 341,000 | |
| 2027 | | 216,000 | |
| 2028 | | 312,000 | |
| 2029 | | 323,000 | |
| 2030 | | 557,000 | |
| 2031 | | 623,000 | |
| 2032 | | 1,113,000 | |
| 2033 | | 2,540,000 | |
| $ | 7,074,000 | |
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SIGNATURES
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this registration statement on its behalf.
HEMISPHERE ENERGY CORP.
| Date: October 3, 2014 | By: | /s/ DORLYN EVANCIC |
| | | Dorlyn Evancic |
| | | Chief Financial Officer |
147
EXHIBIT INDEX
| Exhibit | | |
| Number | | Description |
| 1.1 | | Articles* |
| 1.2 | | Notice of Articles* |
| 1.3 | | Certificate of change of name to Hemisphere Energy Corporation dated April 24, 2009* |
| 1.4 | | Certificate of change of name to Northern Hemisphere Development Corp. dated January 14, 2000* |
| 1.5 | | Certificate of change of name to Hemisphere Development Corp. dated May 18, 1978* |
| 2.1 | | Shareholders Rights Plan Agreement between Hemisphere and Computershare Investor Services Inc. dated March 9, 2010, as amended* |
| 4.1 | | McDaniel & Associates - Report of Third Party for the Evaluation of Oil and Gas Resources attributed to selected Hemisphere Energy Corporation's interests in Western Canada |
4.2 | | Sproule Associates Limited – Evaluation of the P&NG Reserves of Hemisphere Energy Corporation (As of December 31, 2012) Constant Dollars |
4.3 | | Sproule Associates Limited – Evaluation of the P&NG Reserves of Hemisphere Energy Corporation (As of February 29, 2012) Constant Dollars |
| 10.1 | | Stock Option Plan* |
| 10.2 | | Executive employment agreement between Hemisphere Energy Corporation and Don Simmons* |
| 10.3 | | Executive employment agreement between Hemisphere Energy Corporation and Dorlyn Evancic* |
| 10.4 | | Executive employment agreement between Hemisphere Energy Corporation and Ian Duncan* |
| 10.5 | | Executive employment agreement between Hemisphere Energy Corporation and Andrew Arthur* |
| 10.6 | | Commitment letter between Hemisphere Energy Corporation and Alberta Treasury Branches dated September 19, 2013* |
| 10.7 | | First Amending Agreement to the Commitment Letter dated September 19, 2013 between Hemisphere Energy Corporation and Alberta Treasury Branches effective June 23, 2014* |
| 10.8 | | Executive employment agreement between Hemisphere Energy Corporation and Ashley Ramsden-Wood
|
| 14.1 | | Advance Notice Policy of Hemisphere Energy Corporation* |
| 99.1 | | Consent of Smythe Ratcliffe LLP |
| 99.2 | | Consent of McDaniel Associates & Consultants Ltd. (included with Exhibit 4.1) |
| 99.3 | | Consent of Sproule Associates Limited |
*Previously filed
