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Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark one)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2015

or

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File Number: 000-55301

 

 

Lynden Energy Corp.

(Exact name of registrant as specified in its charter)

 

 

 

British Columbia  

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification Number)

 

888 Dunsmuir Street

Suite 1200

Vancouver, British Columbia

  V6C 3K4
(Address of principal executive offices)   (Zip code)

(604) 629-2991

(Registrant’s telephone number, including area code)

 

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

 

 

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

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 Registration 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  x    No  ¨

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

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):    Yes  ¨    No  x

The registrant had 130,198,411 shares of common stock outstanding at November 13, 2015.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

         Page  

Glossary of Certain Terms and Conventions Used Herein

     1   

Cautionary Statement Concerning Forward-Looking Statements

     4   
PART I. FINANCIAL INFORMATION   

Item 1.

 

Financial Statements

  
            

Condensed Consolidated Interim Balance Sheets as of September 30, 2015 and June 30, 2015

     5   
 

Condensed Consolidated Interim Statements of Income (Loss) and Comprehensive Income (Loss) for the Three Months Ended September 30, 2015 and 2014

     6   
 

Condensed Consolidated Interim Statement of Changes in Equity for the Three Months Ended September  30, 2015 and 2014

     7   
 

Condensed Consolidated Interim Statements of Cash Flows for the Three Months Ended September  30, 2015 and 2014

     8   
 

Notes to Condensed Consolidated Interim Financial Statements

     9   

Item 2.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     15   

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

     23   

Item 4.

 

Controls and Procedures

     24   
PART II. OTHER INFORMATION   

Item 1.

 

Legal Proceedings

     25   

Item 1A.  

 

Risk Factors

     25   

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

     25   

Item 6.

 

Exhibits

     25   


Table of Contents

GLOSSARY OF CERTAIN TERMS AND CONVENTIONS USED HEREIN

Within this report, the following terms have these specific meanings:

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Bbl.” One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGL.

“Bbls/d.” Bbls per day.

“Boe.” A barrel of oil equivalent and is a standard convention used to express oil, NGL and natural gas volumes on a comparable oil equivalent basis. Natural gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or NGL.

“Boe/d.” One Boe per day.

“Btu” or “British Thermal Unit.” The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Differential.” An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

“Dry hole” or “Dry well.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“E&P.” Exploration and production of oil, NGL and natural gas.

“Exploitation.” A development or other project that may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

“Enhanced recovery.” The recovery of oil, NGL and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.

“Exploratory well.” A well drilled to find and produce oil, NGL or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil, NGL or natural gas in another reservoir or to extend a known reservoir.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.

“Gross acres” or “gross wells.” The total acres or wells, as the case may be, in which a working interest is owned. All gross acre figures in this Quarterly Report on Form 10-Q are approximates and estimated.

“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Hydraulic fracturing.” The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

“LIBOR.” London Interbank Offered Rate, which is a market rate of interest.

“MBbl.” One thousand barrels of crude oil, condensate or NGL.

“MBoe.” One thousand Boes.

 

1


Table of Contents

“Mcf.” One thousand cubic feet of natural gas.

“Mcf/d.” One Mcf per day.

“MGal.” One thousand gallons of NGL.

“MMBbl.” One million barrels of crude oil, condensate or NGL.

“MMBoe.” One million Boes.

“MMBtu.” One million British Thermal Units.

“MMcf.” One million cubic feet of natural gas.

“Net acres” or “net wells.” The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions thereof. A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. All net acre figures in this Quarterly Report on Form 10-Q are approximates and estimated.

“NGL.” Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as liquefied petroleum gas and natural gasoline.

“NYMEX.” The New York Mercantile Exchange.

“P&NG.” Petroleum and natural gas.

“PDP.” Proved developed producing reserves.

“Productive well.” A well that is not a dry well.

“Proved developed reserves.” Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and installed extraction equipment and infrastructure operation at the time of the reserve estimate if the extraction is by means not involving a well.

“Proved reserves.” The quantities of oil, NGL and natural gas, which, by analysis of geosciences 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.

“Proved undeveloped reserves” or “PUDs.” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

“Recompletion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of oil, NGL or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Realized price.” The cash market price less all expected quality, transportation and demand adjustments.

 

2


Table of Contents

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil, NGL and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“SEC.” The United States Securities and Exchange Commission.

“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Spot market price.” The cash market price without reduction for expected quality, transportation and demand adjustment.

“Standardized measure.” The year-end present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, without giving effect to non-property related expenses (such as certain general and administrative expenses, debt service and future federal income tax expenses) or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%.

“Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil, NGL and natural gas regardless of whether such acreage contains proved reserves.

“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Wellbore.” The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

“We,” “our,” “us” or like terms and “Lynden” and the “Company” refer to Lynden Energy Corp. and its subsidiaries, Lynden Exploration Ltd. and Lynden USA Inc.

“West Texas Intermediate Sweet.” A light, sweet blend of oil produced from the fields in West Texas.

“Working interest.” The right granted to the lessee of a property to explore for and to produce and own oil, NGL, natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“Workover.” Operations on a producing well to restore or increase production.

 

3


Table of Contents

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

 

    the volatility of commodity prices, product supply and demand;

 

    competition;

 

    access to and cost of capital;

 

    uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future;

 

    the assumptions underlying production forecasts;

 

    the quality of technical data;

 

    environmental and weather risks, including the possible impacts of climate change;

 

    the ability to obtain environmental and other permits and the timing thereof;

 

    government regulation or action;

 

    the costs and results of drilling and operations;

 

    the availability of equipment, services, resources and personnel required to complete the Company’s operating activities;

 

    access to and availability of transportation, processing and refining facilities;

 

    the financial strength of counterparties to the Company’s reducing revolving credit facility and the purchasers of the Company’s production; and

 

    acts of war or terrorism.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended June 30, 2015, which is also available under our profile at the SEDAR website (www.sedar.com).

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

 

4


Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Condensed Consolidated Interim Balance Sheets as of September 30, 2015 and June 30, 2015

(Presented in United States dollars, except where indicated)

(Unaudited)

 

     Notes    September 30,
2015
    June 30,
2015
 

ASSETS

       

Current assets

       

Cash and cash equivalents

      $ 7,955,949      $ 8,748,008   

Trade and other receivables, net of allowance for doubtful accounts

   3,8      1,768,304        1,660,135   

Income taxes receivable

        469,434        469,434   

Prepaid expenses

        17,672        50,613   
     

 

 

   

 

 

 

Total current assets

        10,211,359        10,928,190   
     

 

 

   

 

 

 

Non-current assets

       

Property, plant and equipment

   4      113,534,529        107,283,684   
     

 

 

   

 

 

 

Total assets

      $ 123,745,888      $ 118,211,874   
     

 

 

   

 

 

 

LIABILITIES AND SHAREHOLDERS’ EQUITY

       

Current liabilities

       

Trade and other payables

   8    $ 984,435      $ 1,646,846   

Credit facility

   5,8      37,150,165        —     
     

 

 

   

 

 

 

Total current liabilities

        38,134,600        1,646,846   
     

 

 

   

 

 

 

Non-current liabilities

       

Credit facility

   5,8      —          29,908,366   

Asset retirement liabilities

        292,916        278,790   

Deferred tax liabilities

        17,226,792        17,497,692   
     

 

 

   

 

 

 
        17,519,708        47,684,848   
     

 

 

   

 

 

 

Total liabilities

        55,654,308        49,331,694   
     

 

 

   

 

 

 

Shareholders’ equity

       

Share capital - authorized unlimited common shares, no par value

       

Issued and outstanding: September 30, 2015 - 130,198,411

       

               June 30, 2015 - 130,198,411

   6      65,622,727        65,622,727   

Paid-in capital

   6      15,228,879        15,228,879   

Accumulated other comprehensive loss

        (4,335,969     (3,788,414

Deficit

        (8,424,057     (8,183,012
     

 

 

   

 

 

 

Total shareholders’ equity

        68,091,580        68,880,180   
     

 

 

   

 

 

 

Total liabilities and shareholders’ equity

      $ 123,745,888      $ 118,211,874   
     

 

 

   

 

 

 

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

 

5


Table of Contents

Condensed Consolidated Interim Statements of Income (Loss) and Comprehensive Income (Loss) for the three months ended September 30, 2015 and 2014

(Presented in United States dollars, except where indicated)

(Unaudited)

 

          Three months ended September 30,  
     Notes    2015     2014  

Revenue and other income

       

Petroleum and natural gas sales, net of royalties

      $ 3,393,456      $ 7,934,867   

Derivative financial instruments gain (loss)

        391,320        —     

Interest income

        27,421        37,826   
     

 

 

   

 

 

 

Total revenue and other income

        3,812,197        7,972,693   
     

 

 

   

 

 

 

Expenses

       

Production and operating expenses

        (1,538,851     (1,324,362

Depletion, depreciation and accretion

        (2,222,201     (2,679,020

Exploration and impairments

        (2,042     (451,109

General and administrative

        (351,364     (373,738

Interest

        (209,684     (189,995
     

 

 

   

 

 

 

Total expenses

        (4,324,142     (5,018,224
     

 

 

   

 

 

 

(Loss) income before income taxes

        (511,945     2,954,469   

Income tax recovery (expense)

        270,900        (1,319,000
     

 

 

   

 

 

 

Net (loss) income

        (241,045     1,635,469   
     

 

 

   

 

 

 

Other comprehensive (loss) income

       

Foreign currency translation adjustment

        (547,555     (537,227
     

 

 

   

 

 

 

Total comprehensive (loss) income for the period

      $ (788,600   $ 1,098,242   
     

 

 

   

 

 

 

Weighted average number of common shares outstanding

       

Basic

   6      130,198,411        129,609,199   

Diluted

   6      130,198,411        134,674,197   

Net earnings per common share

       

Basic

      $ (0.00   $ 0.01   

Diluted

      $ (0.00   $ 0.01   
     

 

 

   

 

 

 

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

 

6


Table of Contents

Condensed Consolidated Interim Statement of Changes in Equity for the three months ended September 30, 2015 and 2014

(Presented in United States dollars, except where indicated)

(Unaudited)

 

    Common Shares          

Accumulated

Other

             
    Number     Amount     Paid-in
Capital
    Comprehensive
Loss
    Deficit     Total  

Balance at June 30, 2015

    130,198,411      $ 65,622,727      $ 15,228,879      $ (3,788,414   $ (8,183,012   $ 68,880,180   

Foreign currency translation

    —          —          —          (547,555     —          (547,555

Net loss for the period

    —          —          —          —          (241,045     (241,045
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at September 30, 2015

    130,198,411      $ 65,622,727      $ 15,228,879      $ (4,335,969   $ (8,424,057   $ 68,091,580   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    Common Shares          

Accumulated

Other

             
    Number     Amount     Paid-in
Capital
    Comprehensive
Loss
    Deficit     Total  

Balance at June 30, 2014

    129,275,911      $ 65,160,387      $ 15,434,128      $ (212,663   $ (7,617,859   $ 72,763,993   

Common shares issued for cash:

           

Exercise of stock options

    472,500        243,724        (107,526     —          —          136,198   

Foreign currency translation

    —          —          —          (537,227     —          (537,227

Net income for the period

    —          —          —          —          1,635,469        1,635,469   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at September 30, 2014

    129,748,411      $ 65,404,111      $ 15,326,602      $ (749,890   $ (5,982,390   $ 73,998,433   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

 

7


Table of Contents

Condensed Consolidated Interim Statements of Cash Flows for the three months ended September 30, 2015 and 2014

(Presented in United States dollars, except where indicated)

(Unaudited)

 

        Three months ended
September 30,
 
    Notes   2015     2014  

Operating activities

     

Net (loss) income for the period

    $ (241,045   $ 1,635,469   

Adjustments for:

     

Accrued interest

      (8,201     —     

Unrealized gain on derivative financial instruments

      (382,455     —     

Depletion, depreciation and accretion

      2,222,201        2,679,020   

Impairments

      —          449,541   

Deferred income taxes

      (270,900     1,123,000   

Unrealized foreign exchange gain

      (140,862     (54,483

Changes in non-cash working capital items:

     

Trade and other receivables

      134,246        205,434   

Prepaid expenses

      32,941        —     

Trade and other payables

      18,941        (73,965

Income taxes payable

      —          71,000   
   

 

 

   

 

 

 

Cash generated by operating activities

      1,364,866        6,035,016   
   

 

 

   

 

 

 

Investing activities

     

Acquisition of property, plant and equipment

      (9,000,232     (11,724,501
   

 

 

   

 

 

 

Cash used in investing activities

      (9,000,232     (11,724,501
   

 

 

   

 

 

 

Financing activities

     

Drawings of credit facility

      7,250,000        5,550,000   

Common shares issued for cash, net of issue costs

      —          136,198   
   

 

 

   

 

 

 

Cash generated by financing activities

      7,250,000        5,686,198   
   

 

 

   

 

 

 

Effect of exchange rate on cash held in foreign currency

      (406,693     (482,744
   

 

 

   

 

 

 

Change in cash and cash equivalents during the period

      (792,059     (486,031

Cash and cash equivalents, beginning of period

      8,748,008        13,955,890   
   

 

 

   

 

 

 

Cash and cash equivalents, end of period

    $ 7,955,949      $ 13,469,859   
   

 

 

   

 

 

 

Cash and cash equivalents are composed of:

     

Cash

    $ 80,068      $ 2,641,321   

Guaranteed investment certificates

      7,875,881        10,828,538   
   

 

 

   

 

 

 
    $ 7,955,949      $ 13,469,859   
   

 

 

   

 

 

 

Supplemental cash flow information

  9    

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

 

8


Table of Contents

Notes to Condensed Consolidated Interim Financial Statements

1. Description of Business

Lynden Energy Corp. (the “Company”) is a public company continued under the Business Corporations Act (British Columbia). The Company’s business is to acquire, explore and develop petroleum and natural gas (“P&NG”) properties. The Company’s principal business activities are located in Texas, United States of America. The Company’s common shares trade on the TSX Venture Exchange (“TSX-V”) under the symbol LVL. The head office is located in Vancouver, British Columbia, Canada.

2. Significant Accounting Policies

a) Basis of presentation

These condensed consolidated interim financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“US GAAP”) as at September 30, 2015 and for the three months ended September 30, 2015 and the 2014 comparative period. These condensed consolidated interim financial statements do not include all the necessary annual disclosures as prescribed under U.S. GAAP and should be read in conjunction with the Company’s audited consolidated financial statements as of and for the year ended June 30, 2015.

In management’s opinion, the condensed consolidated financial statements reflect all adjustments (including normal recurring adjustments) which are necessary to present fairly the financial position as at September 30, 2015 and results of operations and cash flows for all periods presented.

b) Use of estimates

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the amount and timing of recording of assets, liabilities, revenues and expenses since the determination of these amounts may be dependent on future events. Significant estimates made by management include: oil and natural gas reserves and related present value of future cash flows, depreciation, depletion, amortization and accretion (“DDA&A”), impairment, asset retirement obligations, income taxes, and share-based compensation. The Company uses the most current information available and exercises judgment in making these estimates and assumptions. There have been no significant changes in the estimates or judgments between these condensed consolidated interim financial statements and the audited consolidated financial statements for the year ended June 30, 2015.

c) Recent accounting pronouncements

As of July 1, 2015, the Company adopted the following Financial Accounting Standards Board (“FASB”) accounting standards updates. The adoption of these standards did not have a material impact on the Company’s condensed consolidated interim financial statements.

 

    Accounting Standards Update 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (effective for annual periods beginning on or after December 15, 2014)

The FASB has issued the following accounting standards updates which are not yet effective:

 

    Accounting Standards Update 2014-09, Revenue From Contracts With Customers (effective for annual periods beginning after December 15, 2017)

 

    Accounting Standards Update 2014-12, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved After the Requisite Service Period (effective for annual periods beginning after December 15, 2015)

 

    Accounting Standards Update 2014-15, Disclosure of Uncertainties About an Entity’s Ability to Continue as a Going Concern (effective for annual periods ending after December 15, 2016)

 

    Accounting Standards Update 2015-03, Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs (effective for annual periods beginning after December 15, 2015)

 

    Accounting Standards Update 2015-15, Imputation of Interest: Simplifying the Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements (effective for annual periods beginning after December 15, 2015)

 

    Accounting Standards Update 2015-16, Business Combinations: Simplifying the Accounting for Measurement – Period Adjustments (effective for annual periods beginning after December 15, 2015)

 

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The Company has not early adopted these accounting standards updates and is currently assessing the application of these standards on the results and financial position of the Company.

3. Trade and Other Receivables

 

     September 30, 2015      June 30, 2015  

Accounts receivable – trade

   $ 9,121       $ 1,340,803   

Accrued receivables

     1,436,664         237,430   

Other receivable

     242,415         —     

Sales taxes receivable

     80,104         81,902   
  

 

 

    

 

 

 
   $ 1,768,304       $ 1,660,135   
  

 

 

    

 

 

 

The Company did not have any allowance for doubtful accounts as at September 30, 2015 and June 30, 2015. As at September 30, 2015, $1,436,664 (June 30, 2015 - $1,532,382) is owing from one counterparty.

Other receivable consists of a fair valued derivative financial instrument (note 8).

4. Property, Plant and Equipment

 

     September 30, 2015  
     Cost      Accumulated
Depletion,
Depreciation
and Impairment
     Net Book Value  

Petroleum and natural gas properties

        

Proved

   $ 130,935,258       $ (25,311,932    $ 105,623,326   

Exploratory well costs

     36,961,009         (29,050,534      7,910,475   
  

 

 

    

 

 

    

 

 

 
     167,896,267         (54,362,466      113,533,801   

Computer equipment

     1,948         (1,220      728   
  

 

 

    

 

 

    

 

 

 

Total property, plant and equipment

   $ 167,898,215       $ (54,363,686    $ 113,534,529   
  

 

 

    

 

 

    

 

 

 

 

     June 30, 2015  
     Cost      Accumulated
Depletion,
Depreciation
and Impairment
     Net Book
Value
 

Petroleum and natural gas properties

        

Proved

   $ 122,491,540       $ (23,096,935    $ 99,394,605   

Exploratory well costs

     36,938,662         (29,050,534      7,888,128   
  

 

 

    

 

 

    

 

 

 
     159,430,202         (52,147,469      107,282,733   

Computer equipment

     2,081         (1,130      951   
  

 

 

    

 

 

    

 

 

 

Total property, plant and equipment

   $ 159,432,283       $ (52,148,599    $ 107,283,684   
  

 

 

    

 

 

    

 

 

 

Proved petroleum and natural gas assets

Proved petroleum and natural gas assets consist of lease acquisition costs, costs of drilling and equipping development wells, and construction of related production facilities all relating to the Company’s Midland Basin property.

Exploratory well costs

Exploratory well costs consist of costs associated with the drilling and equipping of exploratory wells relating to 1) the Mitchell Ranch Project; and 2) three vertical well locations in the Midland Basin. The Company is performing economic evaluations including, but not limited to, results of additional appraisal drilling, well test analysis, additional geological and geophysical data, facilities and infrastructure development options, development plan approval, and permitting.

 

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5. Credit Facility

The Company has a reducing revolving line of credit (the “Credit Facility”) in an amount up to $100 million. As at September 30, 2015, the Credit Facility has a borrowing base of $37.5 million, of which $37.0 million has been drawn down. The Credit Facility bears interest determined by the percent of the borrowing base utilized and by elections made by the Company. Amounts drawn down under the Credit Facility will bear interest at a rate of LIBOR plus a range of 3.00% to 3.50% or at a rate of U.S. prime plus a range of 2.00% to 2.50%. A minimum interest rate of 3.5% is required on borrowings under the Credit Facility. Payments under the Credit Facility will be required to the extent that outstanding principal and interest exceed the borrowing base. Other fees may also apply pursuant to the bank’s re-determinations of the borrowing base. Changes in borrowing base are made based on the bank’s engineering valuation of the Company’s oil and gas reserves. The borrowing base is re-determined semi-annually; however, the Company may request two additional re-determinations of the borrowing base annually. The bank is in the process of its review of the Company’s borrowing base and has indicated to the Company, subject to additional internal bank approvals and the completion of customary documentation, that the borrowing base is expected to remain the same or to be increased by an amount not yet finalized.

The Credit Facility contains certain mandatory covenants, including minimum current ratio and cash flow requirements, and other standard business operating covenants. The Company has complied with all of these covenants as at and during the three months ended September 30, 2015. The Company has pledged its interest in its P&NG and other assets as security for liabilities pursuant to the Credit Facility. Amounts owing on the Credit Facility are payable when the Credit Facility expires in August 2016, unless otherwise extended by the parties, or payable on demand on the event of default. As a result of the Credit Facility expiring in less than one year, the amount due under the Credit Facility has been classified as a current liability. The providers of the Credit Facility have advised that an extension, for an additional two years, of the Credit Facility has been approved, subject to documentation acceptable to the providers. The Company is currently evaluating various options for funding its development plan prior to committing to an extension of the Credit Facility.

6. Shareholders’ Equity

a) Authorized

An unlimited number of common shares without par value.

An unlimited number of preference shares without par value.

b) Earnings per share:

Diluted earnings per share computation

 

     Three months ended September 30,  
     2015      2014  

Numerator:

     

Net (loss) earnings

   $ (241,045    $ 1,635,469   
  

 

 

    

 

 

 

Denominator:

     

Weighted average number of common shares (basic)

     130,198,411         129,609,199   

Dilutive effect of share options

     —           2,353,504   

Dilutive effect of warrants

     —           2,711,494   
  

 

 

    

 

 

 

Weighted average number of common shares (diluted)

     130,198,411         134,674,197   
  

 

 

    

 

 

 

Diluted earnings per common share

   $ 0.00       $ 0.01   
  

 

 

    

 

 

 

For the three months ended September 30, 2015, 4,010,000 (2014 – nil) share options are not dilutive and have been excluded from the dilutive earnings per share calculation.

c) Stock option plan

The Company has a stock option plan whereby a maximum of 10% of the issued and outstanding common shares of the Company may be reserved for issuance pursuant to the exercise of stock options. The term of the stock options granted are fixed by the board of directors and are not to exceed ten years. The exercise prices of the stock options are determined by the board of directors but shall not be less than the closing price of the Company’s common shares on the day preceding the day on which the directors grant the stock options, less any discount permitted by the TSX-V. Subject to any vesting schedule imposed by the Company’s board of directors in respect of any specific stock option grants, the stock options vest immediately on the date of grant except for stock options granted to investor relations consultants which vest over a twelve month period.

 

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The changes in stock options issued during the three months ended September 30, 2015 and the year ended June 30, 2015 are as follows:

 

     Three months ended
September 30, 2015
     Year ended
June 30, 2015
 
     Number of
options
     Weighted
average
exercise price
(CDN$)
     Number of
options
     Weighted
average
exercise price
(CDN$)
 

Balance, beginning of period

     4,270,000       $ 0.69         6,632,500       $ 0.61   

Exercised

     —         $ —           (922,500    $ 0.31   

Expired

     (260,000    $ 0.60         (1,440,000    $ 0.55   
  

 

 

    

 

 

    

 

 

    

 

 

 

Balance, end of period

     4,010,000       $ 0.70         4,270,000       $ 0.69   
  

 

 

    

 

 

    

 

 

    

 

 

 

The following table summarizes information about stock options outstanding and exercisable at September 30, 2015:

 

     Options outstanding      Options exercisable  

Exercise price (CDN$)

   Number of
options
     Weighted
average
remaining life
(years)
     Number of
options
     Weighted
average
remaining life
(years)
 

$0.50 to $0.60

     1,397,500         1.76         1,397,500         1.76   

$0.80

     2,612,500         0.81         2,612,500         0.81   
  

 

 

    

 

 

    

 

 

    

 

 

 
     4,010,000         1.14         4,010,000         1.14   
  

 

 

    

 

 

    

 

 

    

 

 

 

7. Related Party Transactions

The Company incurred the following fees and expenses in the normal course of operations at amounts agreed upon between the parties to companies owned by key management and directors. The legal fees are paid to a law firm in which a director is a shareholder and the transportation and marketing costs are paid to Abajo Gas Transmission Company, LLC, the Company’s investment in associate.

 

     Three months ended
September 30,
 
     2015      2014  

Legal fees

   $ 13,415       $ 15,069   

Transportation and marketing costs

     10,599         9,380   
  

 

 

    

 

 

 

Total

   $ 24,014       $ 24,449   
  

 

 

    

 

 

 

As at September 30, 2015, trade and other payables include $21,121 (June 30, 2015—$33,320) owing to related parties. Amounts due to or from related parties are unsecured, non-interest bearing and are due on demand.

 

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8. Financial Instruments

As at September 30, 2015, the Company’s financial instruments are cash and cash equivalents, trade and other receivables, credit facility, and trade and other payables. These financial instruments are classified as follows:

Cash and cash equivalents – loans and receivables

Trade and other receivables – loans and receivables

Credit facility – other financial liabilities

Trade and other payables – other financial liabilities

Derivative asset/liability – fair value through profit or loss

The following fair value hierarchy is used to categorize and disclose the Company’s financial assets and liabilities held at fair value for which a valuation technique is used:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

Level 2: All inputs which have a significant effect on the fair value are observable, either directly or indirectly, for substantially the full contractual term.

Level 3: Inputs which have a significant effect on the fair value are not based on observable market data.

The Company’s commodity derivative asset/liability was classified as a level 2 in accordance with the above hierarchy.

The amounts reported in the condensed consolidated interim balance sheet for the Company’s cash and cash equivalents, trade and other receivables, credit facility, and trade and other payables are carrying amounts and approximate their fair values due to their short-term nature.

The Company has exposure to credit risk, liquidity risk, and market risk from its use of financial instruments. There have not been any changes to the Company’s exposure to risks, or the objectives, policies and processes to manage these since from June 30, 2015.

a) Credit risk

The aging of trade and other receivables are as follows:

 

     September 30, 2015      June 30, 2015  

Trade and other receivables

     

0 to 60 days

   $ 1,694,598       $ 1,592,126   

61 to 120 days

     5,697         8,357   

> 120 days1

     68,009         59,652   
  

 

 

    

 

 

 
   $ 1,768,304       $ 1,660,135   
  

 

 

    

 

 

 

 

1  Utah State withholding taxes on P&NG sales.

b) Liquidity Risk

The following table details the Company’s expected remaining contractual maturities for its financial liabilities and other obligations. The table is based on the undiscounted cash flows of financial liabilities based on the earliest date on which the Company is required to satisfy the liabilities.

 

     Total      Less than
1 year
     One to two
years
     More than
two years
 

Credit facility1

   $ 37,150,165       $ 37,150,165       $ —         $ —     

Trade and other payables

     984,435         984,435         —           —     

Asset retirement liabilities

     4,389,000         —           —           4,389,000  
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ 42,523,600       $ 38,134,600       $ —         $ 4,389,000   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

1  Includes accrued interest of $150,165.

 

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c) Currency Risk

As at September 30, 2015, a 10% depreciation or appreciation of the Canadian dollar against the United States dollar would result in an increase or decrease, respectively, in the Company’s earnings or loss by $791,335, based on the net exposures presented below:

 

     Cash      Trade and
other
receivables
     Trade
and other
payables
    Net assets
exposure
     Effect of +/-
10% change
in currency
 

Canadian dollar denomination

   $ 7,928,333       $ 5,337       $ (20,324   $ 7,913,346       $ 791,335   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

d) Price Risk

The Company’s P&NG production is marketed and sold on the spot market to area aggregators based on daily spot prices that are adjusted for product quality and transportation costs. The Company’s cash flow from product sales will therefore be impacted by fluctuations in commodity prices.

To protect future cash flows for planned capital expenditures, the Company periodically enters into commodity derivative contracts. In April 2015, the Company entered into a NYMEX based oil price put contract for 9,000 barrels of oil per month from September 2015 until August 2016 (12 months) with a strike price of $50 per barrel. Fair value changes on this contract are recognized in the statement of income. During the quarter ended September 30, 2015, the Company reported a realized gain of $8,865 (2014 - $0) and reported an unrealized gain of $382,455 (2014 - $0). As at September 30, 2015, the contract has a fair value of $242,415 included in accounts receivable-trade.

9. Supplemental Cash Flow Information

 

     Three months ended
September 30,
 
     2015      2014  

Non-cash financing activities:

     

Fair value of stock options transferred to common shares on exercise of stock options

   $ —         $ 107,537  

10. Segmented Information

At September 30, 2015 the Company has one reportable operating segment, being the acquisition, exploration and development of petroleum and natural gas properties. The Company operates in two reportable geographic areas, being Canada and the United States of America.

An operating segment is defined as a component of the Company:

 

    that engages in business activities from which it may earn revenues and incur expenses;

 

    whose operating results are reviewed regularly by the entity’s chief operating decision maker; and

 

    for which discrete financial information is available.

The Company’s revenues and capital assets in each of the geographic areas are as follows:

 

     Canada      USA      Consolidated Total  
Three months ended September 30,    2015      2014      2015      2014      2015      2014  

Revenue and other income

                 

Interest income, net of royalties

   $ 27,421       $ 37,826       $ —         $ —         $ 27,421       $ 37,826   

Petroleum sales, net of royalties

     —           —           2,654,712         6,248,076         2,654,712         6,248,076   

Natural gas sales, net of royalties

     —           —           402,717         683,538         402,717         683,538   

Natural gas liquids sales, net of royalties

     —           —           336,027         1,003,253         336,027         1,003,253   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
   $ 27,421       $ 37,826       $ 3,393,456       $ 7,934,867       $ 3,420,877       $ 7,972,693   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

     Canada      USA      Consolidated Total  
     September 30,
2015
     June 30,
2015
     September 30,
2015
     June 30,
2015
     September 30,
2015
     June 30,
2015
 

Property, plant and equipment

   $ 728       $ 951       $ 113,533,801       $ 107,282,733       $ 113,534,529       $ 107,283,684   

 

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated interim financial statements and related notes in “Part I, Item 1. Financial Statements” presented in this Quarterly Report on Form 10-Q, and in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K for the year ended June 30, 2015. The following discussion and analysis contains forward-looking statements, including, without limitation, statements relating to our plans, strategies, objectives, expectations, intentions and resources. Please see “Cautionary Note Regarding Forward-Looking Information” elsewhere in this Quarterly Report on Form 10-Q and “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended June 30, 2015. All references to dollar amounts in this section are in U.S. dollars unless expressly stated otherwise.

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of petroleum and natural gas (“P&NG”) rights and properties. We have various working interests in the Midland Basin (including the Wolfberry play) and Eastern Shelf (including our Mitchell Ranch Project), located in the Permian Basin in West Texas, U.S.A.

Lynden Energy Corp. is a public company continued under the Business Corporations Act (British Columbia).

The common shares of the Company are listed on the TSX Venture Exchange under the symbol LVL, and the Company is a reporting issuer in British Columbia, Ontario and Alberta. At December 31, 2013, the Company no longer met the definition of a “foreign private issuer” under the U.S. Securities Exchange Act of 1934 (the “Exchange Act”), and as of June 30, 2014 (our fiscal year end), we met the registration requirements under Section 12(g) of the Exchange Act and subsequently became a reporting company in the United States. We have two wholly owned subsidiaries, Lynden Exploration Ltd. and Lynden USA Inc.

Highlights

The Company’s financial and operating performance for the three months ended September 30, 2015 included the following highlights:

 

    Primarily as a result of a significant drop in commodity prices, petroleum and natural gas sales decreased by 57% as compared to the three months ended September 30, 2014;

 

    Realized prices decreased 49% per Bbl of oil, 36% per Mcf of gas and 63% per Bbl of NGL compared to the three months ended September 31, 2014; and

 

    Average daily production was 1,227 Boe/d in the three months ended September 30, 2015 compared to 1,424 Boe/d in the three months ended September 30, 2014.

Recent Developments

During the three months ended September 30, 2015, our average daily production was 650 barrels per day, or Bbls/d, of oil, 1,694 thousand cubic feet per day, or Mcf/d, of natural gas and 295 Bbls/d of NGL, which totaled 1,227 Boe/d. During the three months ended June 30, 2015, our average daily production was 771 Bbls/d of oil, 2,008 Mcf/d of natural gas, and 329 Bbls/d of NGL, which totaled 1,434 Boe/d. Production decreased by 207 Boe/d or 14% in the three months ended September 30, 2015 compared to the three months ended June 30, 2015.

During the three months ended September 30, 2015, we incurred approximately $9.0 million of capital expenditures in connection with our Permian Basin properties. Principal activities undertaken during the three months ended September 30, 2015 included:

 

    The tie-into production of one gross Wolfberry well and the spudding of four additional gross Wolfberry wells;

 

    The completion and tie-into production in late August of one gross Midland Basin horizontal well;

 

    The drilling, completion and tie-into production in mid-September of a second Midland Basin horizontal well; and

 

    The drilling of one gross Mitchell Ranch Project well.

 

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How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

 

    production volumes;

 

    realized prices on the sale of oil, natural gas and NGL; and

 

    lease operating expenses.

Sources of Our Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGL. For the three months ended September 30, 2015 and 2014, our revenues derived from oil sales were 78% and 79% respectively. Natural gas sales accounted for approximately 12% and 9% of total sales for the three months ended September 30, 2015 and 2014, respectively. Our revenues from NGL sales for the three months ended September 30, 2015 and 2014 were 10% and 12%, respectively. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Production Volumes

The following table presents production volumes for the Company’s properties for the three months ended September 30, 2015 and 2014.

 

     Three Months Ended
September 30,
     % Change  
     2015      2014     

Oil (Bbls)

     59,795         72,402         (17 %) 

Natural gas (Mcf)

     155,869         169,821         (8 %) 

NGL (Bbls)

     27,100         30,305         (11 %) 
  

 

 

    

 

 

    

 

 

 

Total (Boe)

     112,873         131,010         (14 %) 

Average net daily production (Boe/d)

     1,227         1,424         (14 %) 

The primary factors affecting our production levels are capital availability, the success of our drilling plan, property sales and our inventory of drilling prospects. In addition, as is typical for businesses engaged in the exploration and production of crude oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, crude oil and natural gas production from a given well decreases. We attempt to overcome this natural decline primarily through drilling our existing undeveloped reserves. Our future growth will depend in part on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals.

Production declines compared to the year-ago period are attributable in part to a shift towards horizontal well development and the timing of the drilling of such horizontal wells.

As the Company directs a greater portion of its capital budget towards horizontal well development, the timing of the drilling of the horizontal wells may result in more variable production volumes from quarter to quarter, as compared to the historically smoother pace of less costly vertical Wolfberry well drilling.

In addition, a lower amount of capital expenditures in a given period will generally result in smaller additions to production volumes, which additions may or may not exceed the natural decline of the Company’s existing wells. The comparability of capital expenditures between periods is however an imperfect measure as result of, among other things, changes in well drilling and completion costs (which have decreased over the last 12 months) and the geological and reservoir characteristics in the areas in which wells are being drilled.

Realized Prices on the Sale of Oil, Natural Gas and NGL

Our results of operations are heavily influenced by commodity prices. Factors that may affect commodity prices, including the price of oil, NGL and natural gas, include the level of consumer demand, domestic and worldwide, for oil, NGL and natural gas; the domestic and worldwide supply of oil, NGL and natural gas; inventory levels at Cushing, Oklahoma, the benchmark for WTI oil prices; natural gas inventory levels in the United States; commodity processing, gathering and transportation availability, and the availability of refining capacity; the price and level of imports of foreign oil, NGL and natural gas; the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; domestic and foreign

 

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governmental regulations and taxation; the price and availability of alternative fuel sources; weather conditions; political conditions or hostilities in oil, NGL and natural gas producing regions, including the Middle East, Africa and South America; technological advances affecting energy consumption and energy supply; variations between product prices at sales points and applicable index prices; and worldwide economic conditions.

Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production. From time to time, we expect that we may economically hedge a portion of our commodity price risk to mitigate the effect of price volatility on our business.

Oil and natural gas prices have been subject to significant fluctuations during the past several years. Recently, oil and natural gas prices have declined significantly. During the twelve months ended September 30, 2015, the West Texas Intermediate posted price had declined from a high of $91.02 per Bbl to a low of $38.22 per Bbl. In addition, the Henry Hub spot market price had declined from a high of $4.41 per MMBtu to a low of $2.47 per MMBtu. Likewise, NGL prices have recently suffered significant declines in realized prices. NGL are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics.

If commodity prices continue to decline, a significant portion of our exploitation, development and exploration projects could become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. Lower oil and natural gas prices may also reduce the borrowing base under our credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders.

Factors Affecting the Comparability of Our Financial Condition and Results of Operations

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Public Company Expenses

We incur direct, incremental general and administrative expenses as a result of being a U.S. registered company, including, but not limited to, increased costs associated with increased reporting and compliance requirements, accounting costs and legal fees. These additional direct, incremental general and administrative expenses are not included in our historical results of operations prior to our U.S. registration, during which time we were only a reporting issuer in certain provinces of Canada.

Changes in Drilling Activity

Our capital budget for fiscal 2016 was originally established at approximately $18.9 million. Our original fiscal 2016 capital budget contemplated the participation in the drilling of 8 gross Wolfberry wells, 3 gross horizontal wells in the Midland Basin, and 3 gross vertical wells on the Mitchell Ranch Project. The Company’s fiscal 2016 capital budget has been revised downwards to approximately $14.8 million principally as a result of a decrease, from 3 to 2, in the number of gross horizontal wells in the Midland Basin currently scheduled in fiscal 2016. The ultimate amount of capital that we expend may fluctuate materially based on market conditions and our drilling results. See “Capital Requirements and Sources of Liquidity” for additional information.

 

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Table of Contents

Results of Operations

Oil, natural gas and NGL sales revenues. The following table provides summary information regarding oil, natural gas and NGL revenues, production, average product prices and average production costs and expenses for the three months ended September 30, 2015 and 2014. We determine a barrel of oil equivalent using the ratio of six Mcf of natural gas to one Boe, and one barrel of NGL to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel NGL to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas or NGL may differ significantly from the price for a barrel of oil.

 

     Three months Ended
September 30,
 
     2015      2014  

Net Revenues

     

Oil

   $ 2,654,712       $ 6,248,076   

Natural gas

     402,717         683,538   

NGL

     336,027         1,003,253   
  

 

 

    

 

 

 
     3,393,456         7,934,867   

Production and operating expenses

     (1,538,851      (1,324,362
  

 

 

    

 

 

 

Net back

   $ 1,854,605       $ 6,610,505   
  

 

 

    

 

 

 

Production

     

Oil (Bbl)

     59,795         72,402   

Natural gas (Mcf)

     155,869         169,821   

NGL (Bbl)

     27,100         30,305   

Total barrel of oil equivalent (Boe)

     112,873         131,010   

Daily production averages

     

Oil (Bbls/d)

     650         787   

Natural gas (Mcf/d)

     1,694         1,846   

NGL (Bbl/d)

     295         329   

Total barrel of oil equivalent (Boe/d)

     1,227         1,424   

Average prices

     

Oil (per Bbl)

   $ 44.40       $ 86.30   

Natural gas (per Mcf)

   $ 2.58       $ 4.03   

NGL (per Bbl/d)

   $ 12.40       $ 33.11   

Total barrel of oil equivalent (per Boe)

   $ 30.09       $ 60.57   

Costs and expenses (per Boe)

     

Lease operating

   $ 12.19       $ 7.16   

Production and ad valorem taxes

   $ 1.45       $ 2.95   

Depletion, depreciation and accretion

   $ 19.69       $ 20.45   

Impairments

   $ 0.02       $ 3.44   

General and administrative

   $ 2.42       $ 2.85   

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014

Net Income. Net loss for the three months ended September 30, 2015 was ($241,045) and ($0.00) per share and diluted share, compared to net income of $1,635,469 and $0.01 per share and diluted share for the three months ended September 30, 2014. Net income decreased by $1,876,514 for the three months ended September 30, 2015 compared to September 30, 2014 primarily due to lower oil and gas revenues of $4,541,411, higher production and operating expenses of $214,489, lower depletion, depreciation and accretion of $456,819, lower general and administrative expenses of $22,374, lower exploration and impairment charges of $449,067, and lower income tax expense of $1,589,900 in the three months ended September 30, 2015.

 

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Oil, natural gas and NGL revenues. The following table provides the components of our revenues for the periods indicated, as well as each period’s respective average prices and production volumes.

 

     Three Months Ended
September 30,
     Change      % Change  
     2015      2014        

Revenues

           

Oil

   $ 2,654,712       $ 6,248,076       $ (3,593,364      (58 %) 

Natural gas

     402,717         683,538         (280,821      (41 %) 

NGL

     336,027         1,003,253         (667,226      (67 %) 
  

 

 

    

 

 

    

 

 

    

 

 

 

Total revenues

   $ 3,393,456       $ 7,934,867       $ (4,541,411      (57 %) 
  

 

 

    

 

 

    

 

 

    

 

 

 

Production

           

Oil (Bbl)

     59,795         72,402         (12,607      (17 %) 

Natural gas (Mcf)

     155,869         169,821         (13,952      (8 %) 

NGL (Bbl)

     27,100         30,305         (3,205      (11 %) 

Total barrel of oil equivalent (Boe)

     112,873         131,010         (18,137      (14 %) 

Daily production averages

           

Oil (Bbls/d)

     650         787         (137      (17 %) 

Natural gas (Mcf/d)

     1,694         1,846         (152      (8 %) 

NGL (Bbls/d)

     295         329         (34      (10 %) 

Total barrel of oil equivalent (Boe/d)

     1,227         1,424         (197      (14 %) 

Average prices

           

Oil (per Bbl)

   $ 44.40       $ 86.30       $ (41.90      (49 %) 

Natural gas (per Mcf)

   $ 2.58       $ 4.03       $ (1.45      (36 %) 

NGL (per Bbl)

   $ 12.40       $ 33.11       $ (20.71      (63 %) 

Total barrel of oil equivalent (per Boe)

   $ 30.09       $ 60.57       $ (30.48      (50 %) 

Oil revenues. Oil revenues decreased 58% from $6,248,076 for the three months ended September 30, 2014 to $2,654,712 for the three months ended September 30, 2015 as a result of a $41.90 per Bbl decrease in our average realized price for oil and a decrease in oil production volumes of 12,607 Bbls.

Natural gas revenues. Natural gas revenues decreased 41% from $683,538 for the three months ended September 30, 2014 to $402,717 for the three months ended September 30, 2015 as a result of a $1.45 per Mcf decrease in our average realized natural gas price and a decrease in natural gas production volumes of 13,952 Mcf.

NGL revenues. NGL revenues decreased 67% from $1,003,253 for the three months ended September 30, 2014 to $336,027 for the three months ended September 30, 2015 as a result of a $20.71 per Bbl decrease in our average realized NGL price and a decrease in NGL production volumes of 3,205 Bbls.

Effects of derivatives. In April 2015, the Company entered into a NYMEX-based oil price put contract for 9,000 barrels of oil per month from September 2015 until August 2016 (12 months) with a strike price of $50 per barrel. For the three months ended September 30, 2015, we reported an unrealized gain of $382,455 and a realized gain of $8,865. As at and for the three months ended September 30, 2014, all of our production was unhedged.

 

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Operating expenses. The following table summarizes our operating expenses for the periods indicated.

 

     Three months ended
September 30,
     Change      % Change  
     2015      2014        

Operating expenses

           

Lease operating

   $ 1,375,434       $ 938,418       $ 437,016         47

Production and ad valorem taxes

     163,417         385,944         (222,527      (58 %) 

Depletion, depreciation and accretion

     2,222,201         2,679,020         (456,819      (17 %) 

Exploration and impairments

     2,042         451,109         (449,067      (100 %) 

General and administrative

     351,364         373,738         (22,374      (6 %) 
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating expenses

   $ 4,114,458       $ 4,828,229       $ (713,771      (15 %) 
  

 

 

    

 

 

    

 

 

    

 

 

 

 

     Three months ended
September 30,
     Change      % Change  
     2015      2014        

Operating expenses per boe

           

Lease operating

   $ 12.19       $ 7.16       $ 5.02         70

Production and ad valorem taxes

     1.45         2.95         (1.50      (51 %) 

Depletion, depreciation and accretion

     19.69         20.45         (0.76      (4 %) 

Exploration and impairments

     0.02         3.44         (3.43      (99 %) 

General and administrative

     2.42         2.85         (0.44      (15 %) 
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating expenses

   $        35.77       $        36.85       $       (1.10      (3 %) 
  

 

 

    

 

 

    

 

 

    

 

 

 

Lease operating expenses. Lease operating expenses increased 47% from $938,418 for the three months ended September 30, 2014 to $1,375,434 for the three months ended September 30, 2015. The increase in our lease operating expenses was primarily attributable to the increased number of operating wells and to the mix of old wells compared to new wells. Older wells generally require more maintenance per Boe produced. Newer wells generally have higher salt water disposal costs per Boe produced. During the three months ended September 30, 2015, there was also a more active program of repair and production optimization work on the Company’s wells, which contributed to higher lease operating expenses per Boe.

Production and ad valorem taxes. Production and ad valorem taxes decreased 58% from $385,944 for the three months ended September 30, 2014 to $163,417 for the three months ended September 30, 2015. The decrease in our production and ad valorem taxes was attributable to lower revenues from falling commodity prices and lower production during the three months ended September 30, 2015.

Depletion, depreciation and accretion. Depletion, depreciation and accretion decreased 17% from $2,679,020 for the three months ended September 30, 2014, to $2,222,201 for the three months ended September 30, 2015 principally as a result of a 14% decrease in production of Boe.

General and administrative expenses. General and administrative (“G&A”) expenses decreased 6% from $373,738 for the three months ended September 30, 2014 to $351,364 for the three months ended September 30, 2015. The decrease in G&A was due to (1) higher professional fees incurred for the registration of the Company’s securities with the U.S. Securities and Exchange Commission in fiscal 2015; (2) higher promotion and travel incurred in fiscal 2015; and (3) offset by higher office, miscellaneous and other costs in 2016 principally from higher insurance costs and filing fees. The following table summarizes G&A for the period indicated.

 

     Three months ended
September 30,
     Change      % Change  
     2015      2014        

General and administrative expenses

           

Administrative, consulting, and directors’ fees

   $ 192,048       $ 183,687       $ 8,361         5

Office, miscellaneous and other

     65,972         26,041         39,931         153

Professional fees

     74,374         120,281         (45,907      (38 %) 

Promotion and travel

     18,970         43,729         (24,759      (57 %) 
  

 

 

    

 

 

    

 

 

    

 

 

 

Total general and administrative expenses

   $ 351,364       $ 373,738       $ (22,374      (6 %) 
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Exploration and impairments. Exploration and impairments decreased by $449,067 for the three months ended September 30, 2015 due to the $449,541 write-off of the Paradox Basin Project suspended exploratory well costs. After revisiting the criteria for the capitalization of the costs related to the Paradox Basin Project exploratory well costs in the quarter ended September 30, 2014, including the lack of substantial activities to assess the reserves for more than one year following the drilling of the exploratory wells, and future completion operations were not being planned, management determined that the costs should no longer be capitalized. The Company expensed the remaining costs of $449,541 in the three months ended September 30, 2014.

Foreign currency translation adjustment. Foreign currency translation loss of $547,555 was included in other comprehensive income for the three months ended September 30, 2015, compared to $537,227 for the three months ended September 30, 2014. Foreign currency translation loss relates primarily to translating Lynden Energy Corp.’s and Lynden Exploration Ltd.’s net assets denominated in Canadian dollars into United States dollars. Lynden Energy Corp.’s and Lynden Exploration Ltd.’s functional currency is the Canadian dollar.

Interest expense. During the three months ended September 30, 2015, we recorded $209,684 of interest expense as compared to $189,995 in the three months ended September 30, 2014. The increase is primarily the result of having drawn more funds under our reducing revolving line of credit (the “Credit Facility”) during the three months ended September 30, 2015 compared to the three months ended September 30, 2014. Interest expense also includes fees paid pursuant to the Credit Facility.

Income taxes. We reported an income tax recovery of $270,900 for the three months ended September 30, 2015 compared to an income tax expense of $1,319,000 for the three months ended September 30, 2014. The higher income tax expenses for the three months ended September 30, 2014 relate to $3,466,414 more in income before income taxes reported in the three months ended September 30, 2014.

Capital Requirements and Sources of Liquidity

The Company’s primary sources of liquidity have been available cash on hand, cash generated from operations, borrowings under our Credit Facility, and proceeds from asset dispositions. To date, the Company’s primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties.

During the three months ended September 30, 2015, we spent approximately $9.0 million on capital expenditures on property, plant and equipment.

Our fiscal 2016 (July 1, 2015 to June 30, 2016) capital budget for drilling, completion, recompletion and infrastructure was originally established at approximately $18.9 million, and has since been revised downwards to approximately $14.8 million, for the following:

 

    $6.1 million, or 41%, for the participation in the drilling and completion of 8 gross vertical Midland Basin wells;

 

    $7.0 million, or 47% for the participation in the drilling and completion of 2 gross horizontal Midland Basin wells; and

 

    $1.7 million, or 12%, for the participation in the drilling and completion of 3 gross vertical Mitchell Ranch Project wells.

Details of the revised fiscal 2016 capital budget expenditures are as follows:

 

    We continue to carry out the Wolfberry vertical well development program on our Midland Basin acreage. Our revised fiscal 2016 budget contemplates a gross cost of an upcoming Wolfberry well of $1.6 million. Our plans call for 8 gross (3.25 net) Wolfberry wells to spud in fiscal 2016 at an estimated cost to the Company of approximately $6.1 million. Pursuant to the terms of the Midland Basin Participation Agreement with CrownRock L.P. (“CrownRock”), our funding amount for the 3.25 net wells is equivalent to 3.71 wells.

 

    Our revised fiscal 2016 capital budget contemplates 2 CrownQuest Operating, LLC (“CrownQuest”) operated horizontal wells in Glasscock County. The first well has been budgeted at a gross cost of $8.3 million, with the second well budgeted at a gross cost of $7.0 million. Well design, in particular well length and completion approach, will be significant variables in the cost of these wells. The first of these wells has now been drilled, completed and tied-into production and the second well is not scheduled to be spud until the fourth quarter of fiscal 2016. Pursuant to the terms of a Participation Agreement with CrownRock, our primary working interest partner in the acreage operated by CrownQuest, the Company is funding approximately 50% of the cost of the wells.

 

    Our fiscal 2016 capital budget contemplates 3 gross (1.5 net) vertical wells being spud on the Mitchell Ranch Project. The gross cost of the first of the three wells is expected to be $1.4 million, with subsequent wells expected to be $1.0 million.

 

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Based upon current oil and natural gas price expectations for fiscal 2016, we believe that our cash and cash equivalents on hand, our cash flow from operations and additional borrowings under our Credit Facility will provide us with sufficient liquidity to execute our current capital program excluding any acquisitions we may enter into. The Company is not contractually bound to drill any wells to which it has not first consented. In April 2015, we entered into a NYMEX-based oil price put contract for 9,000 bbls of oil per month from September 2015 until August 2016 (12 months) with a strike price of $50 per bbl as a hedge against some of the effects of commodity volatility during the period of the contract.

However, future cash flows are subject to a number of variables, including but not limited to the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure that additional capital will be available on acceptable terms or at all. If we require additional capital for that or other reasons, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. We cannot assure you that needed capital will be available on acceptable terms or at all. If we are unable to obtain capital when needed or on acceptable terms, we may be required to curtail our current drilling program, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or replace our reserves. See “1A. Risk Factors” for additional information.

Liquidity

We define liquidity as cash and cash equivalents and funds available under our Credit Facility. The table below summarizes our liquidity position at September 30, 2015 and June 30, 2015.

 

     Liquidity at
September 30
     Liquidity at
June 30
 
     2015      2015  

Borrowing base

   $ 37,500,000       $ 37,500,000   

Cash and cash equivalents

     7,955,949         8,748,008   

Credit Facility

     (37,150,165      (29,908,366
  

 

 

    

 

 

 

Liquidity

   $ 8,305,784       $ 16,339,642   
  

 

 

    

 

 

 

Working Capital

Our working capital, which we define as current assets minus current liabilities, was in a deficit balance of $27,923,241 as at September 30, 2015 compared to $9,281,344 at June 30, 2015. The Credit Facility matures in August 2016 and has been classified as a current liability as at September 30, 2015 compared to a non-current liability as at June 30, 2015. Our collection of receivables has historically been timely, and we have had no losses associated with uncollectible receivables. Our cash balances totaled $7,955,949 and $8,748,008 at September 30, 2015 and June 30, 2015, respectively. Due to the amounts that accrue related to our drilling program, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our Credit Facility will be sufficient to fund our working capital needs excluding any acquisitions we may enter into. We expect that our pace of development, production volumes and commodity prices will be the largest variables affecting our working capital. The Company’s cash and cash equivalents at September 30, 2015 includes $7,928,333 of cash denominated in Canadian dollars, which is subject to fluctuations in the foreign exchange rates.

The following table summarizes our cash flows for the periods indicated:

 

     Three months Ended September 30,  
     2015      2014  

Net cash generated by operating activities

   $ 1,364,866       $ 6,035,016   

Net cash used in investing activities

   $ (9,000,232    $ (11,724,501

Net cash generated by financing activities

   $ 7,250,000       $ 5,686,198   

 

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Net cash generated by operating activities decreased by 77%, or $4,670,150, to $1,364,866 during the three months ended September 30, 2015 compared to the prior period. The decrease in our cash flows generated by operating activities was primarily due to decreases in P&NG revenues from lower commodity prices and lower production volumes.

Net cash used in investing activities decreased by 23%, or $2,724,269, to $9,000,232 during the three months ended September 30, 2015 compared to the prior period. The decrease in our cash flows used in investing activities was primarily due to more drilling and completion activity during the three months ended September 30, 2014.

Net cash generated by financing activities increased by 27%, or $1,563,802, to $7,250,000 during the three months ended September 30, 2015 compared to the prior period. The increase in our cash flows generated by financing activities was all due to drawings on the Credit Facility of $7,250,000 during the three months ended September 30, 2015 compared to drawings of $5,550,000 on the Credit Facility during the three months ended September 30, 2014.

Debt

Our Credit Facility is a reducing revolving line of credit of up to $100 million. As at September 30, 2015, the Credit Facility has a borrowing base of $37.5 million, of which $37.0 million has been drawn down. The Credit Facility will bear interest determined by the percent of the borrowing base utilized and by elections made by the Company. Amounts drawn down under the Credit Facility will bear interest at a rate of LIBOR plus a range of 3.00% to 3.50% or at a rate of U.S. prime plus a range of 2.00% to 2.50%. A minimum interest rate of 3.5% is required on borrowings under the Credit Facility. Payments under the Credit Facility will be required to the extent that outstanding principal and interest exceed the borrowing base. Other fees may also apply pursuant to the bank’s re-determinations of the borrowing base. Changes in the borrowing base are made based on the bank’s engineering valuation of the Company’s oil and gas reserves. The borrowing base is re-determined semi-annually; however, the Company may request two additional re-determinations of the borrowing base annually. The bank is in the process of its review of the Company’s borrowing base and has indicated to the Company, subject to additional internal bank approvals and the completion of customary documentation, that the borrowing base is expected to remain the same or to be increased by an amount not yet finalized. The bank’s next engineering valuation of the Company’s oil and gas reserves and re-determination of the borrowing base is anticipated to be completed in the third quarter of fiscal 2016.

The Credit Facility contains certain mandatory covenants, including minimum current ratio and cash flow requirements, and other standard business operating covenants. The Company has complied with all of these covenants as at and during the three months ended September 30, 2015. The Company has pledged its interest in its P&NG and other assets as security for liabilities pursuant to the Credit Facility. Amounts owing on the Credit Facility are payable when the Credit Facility expires in August 2016, unless otherwise extended by the parties, or payable on demand on the event of default. As a result of the Credit Facility expiring in less than one year, the amount due under the Credit Facility has been classified as a current liability. The providers of the Credit Facility have advised that an extension, for an additional two years, of the Credit Facility has been approved, subject to documentation acceptable to the providers. The Company is currently evaluating various options for funding its development plan prior to committing to an extension of the Credit Facility.

Critical Accounting Policies and Estimates

Please refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K for our fiscal year ended June 30, 2015 for a description of the Company’s critical accounting policies.

Off-Balance Sheet Arrangements

The Company has not engaged in any off-balance sheet arrangements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

As of September 30, 2015, there was no material change in the information provided under Item 7A in the Company’s Annual Report on Form 10-K for the fiscal year ended June 30, 2015.

 

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management has evaluated, with the participation of our principal executive officer (Chief Executive Officer) and principal financial officer (Chief Financial Officer), as required by Rule 13a-15(b) under the U.S. Securities Exchange Act of 1934 (the “Exchange Act”), the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission’s rules and forms, and includes, without limitation, controls and procedures designed to ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Based upon the evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of September 30, 2015, at a reasonable level of assurance.

Changes in Internal Control over Financial Reporting

As disclosed and described in our amended Registration Statement on Form 10, after the issuance of our consolidated financial statements for the year ended June 30, 2014, management identified a material error with regards to the determination of its deferred income tax expense for the years ended June 30, 2014, and June 30, 2013, which caused us to restate our previously issued annual consolidated financial statements to correct the error. In connection with this restatement, we determined that we had a material weakness as of June 30, 2015, namely that our controls over the evaluation and review of our deferred income taxes were not effective.

In the first quarter of fiscal 2016, management engaged consultants to assist in the determination of deferred income taxes for the year ended June 30, 2015 and enhanced our internal controls by including those consultants in our review process in order to remediate the material weakness. Management believes that the above changes to our internal controls over financial reporting, implemented in the first quarter of fiscal 2016, correct the material weakness.

Other than as described above, there has been no change in our internal control over financial reporting during the fiscal quarter ended September 30, 2015, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

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Table of Contents

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are not currently a party to any legal proceedings. From time to time, we may become party to ongoing legal proceedings in the ordinary course of business, including workers’ compensation claims and employment related disputes. While the outcome of these proceedings cannot be predicted with certainty, we do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the factors discussed in “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended June 30, 2015, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

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

Unregistered sales of equity securities

None

Item 6. Exhibits

See Exhibit Index on page 27 of this Quarterly Report on Form 10-Q.

 

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Table of Contents

SIGNATURES

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

 

  LYNDEN ENERGY CORP.
Date: November 13, 2015   By:  

/s/ Colin Watt

    Colin Watt
    President, Chief Executive Officer, Corporate Secretary and Director
Date: November 13, 2015   By:  

/s/ Laurie Sadler

    Laurie Sadler
   

Chief Financial Officer

(Principal Financial Officer)

 

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Table of Contents

EXHIBIT INDEX

 

Exhibit No.

  

Description

    3.1    Certificate of Continuation of Lynden Ventures, Ltd., dated February 2, 2006 (incorporated by reference to Exhibit 3.1 of our Registration Statement on Form 10-12G initially filed on October 29, 2014).
    3.2    Certificate of Change of Name of the Company, dated January 16, 2008 (incorporated by reference to Exhibit 3.2 of our Registration Statement on Form 10-12G initially filed on October 29, 2014).
    3.3    Notice of Articles of the Company (incorporated by reference to Exhibit 3.3 of our Registration Statement on Form 10-12G initially filed on October 29, 2014).
    3.4    Articles of the Company, dated December 5, 2005 (incorporated by reference to Exhibit 3.4 of our Registration Statement on Form 10-12G initially filed on October 29, 2014).
  31.1*    Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
  31.2*    Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
  32.1**    Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
  32.2**    Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS+    XBRL Instance Document.
101.SCH+    XBRL Taxonomy Extension Schema Document.
101.CAL+    XBRL Taxonomy Extension Schema Document.
101.DEF+    XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB+    XBRL Taxonomy Extension Label Linkbase Document.
101.PRE+    XBRL Taxonomy Extension Presentation Linkbase Document.

 

* Filed herewith.
** Furnished herewith.
+ Filed electronically herewith.

 

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