MANAGEMENT'S DISCUSSION AND ANALYSIS
DECEMBER 31, 2020
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is management's discussion and analysis (MD&A) of Kolibri Global Energy Inc.'s ("KEI" or the "Company") operating and financial results for the year ended December 31, 2020, compared to the prior year, as well as information and expectations concerning the Company's outlook based on currently available information. The MD&A should be read in conjunction with the audited consolidated financial statements for the years ended December 31, 2020 and 2019. Unless otherwise noted, all financial data has been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board. The reporting and measurement currency is the United States dollar. Additional information relating to KEI including its Annual Information Form is filed on SEDAR at www.sedar.com on the Company's website at www.kolibrienergy.com.
This report is prepared as of March 11, 2021. Please read carefully the important cautionary notes regarding technical information, forward-looking statements and other matters set out in this report.
Currency
The Company's reporting currency for financial reporting purposes is U.S. dollars. All dollar amounts set forth in this report are expressed in United States dollars, except where otherwise indicated. The following table sets forth, for each of the years indicated, the high and low exchange rates, the average exchange rate and the year-end exchange rate of one United States dollar in exchange for Canadian dollars as reported by Bloomberg in 2020 and 2019 and Reuters for 2018.
| Year ended December 31 | ||
| 2020 | 2019 | 2018 |
High | CDN$1.27 | CDN$1.30 | CDN$1.23 |
Low | 1.44 | 1.36 | 1.36 |
Average | 1.34 | 1.33 | 1.30 |
Year End | 1.27 | 1.31 | 1.36 |
Description of Business
KEI is an international energy company focused on finding and exploiting energy projects in oil, gas and clean and sustainable energy. Through various subsidiaries, the Company owns and operates energy properties in the United States. The Company continues to utilize its technical and operational expertise to identify and acquire additional projects. . The common shares of the Company trade on the Toronto Stock Exchange ("TSX") under the symbol "KEI" and on the Over the Counter QB ("OTCQB") under the symbol "KGEIF".
Going Concern
The financial statements have been prepared on a going concern basis. The going concern basis of presentation assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business.
At December 31, 2020, the Company had a working capital deficiency of $3.5 million. The Company received its latest bank borrowing base redetermination on its credit facility in September 2020. As part of the redetermination, the Company will make principal payment reductions of $2.1 million by May 2021 to reduce the borrowing base to $18.6 million. These future principal payments are projected to be funded from cash on hand and adjusted funds flow from operations. The Company has no available undrawn debt capacity under its credit facility. See Note 14 for more information. The credit facility is subject to a semi-annual review and redetermination of the borrowing base. The next redetermination is expected in the second quarter of 2021. There can be no assurance that the borrowing base review will not result in a material reduction in the borrowing base, and that the necessary funds will be available to meet its obligations as they become due.
The Company's current forecast indicates that it will be able to fund the future principal payments from cash and cash equivalents and net cash from operating activities and that it will be in compliance with its debt covenants over the next year. These forecasts are based on current strip prices and the Company's current economic hedges and include a number of significant estimates and judgments that could change in the future.
In addition, the global impact of the COVID-19 virus pandemic has led to a high degree of volatility and uncertainty that continues to impact the energy industry and financial markets. While spot prices have started to recover in early 2021, there is still a great deal of uncertainty about the impact of the pandemic going forward which continues to have a continuing negative impact on the Company's ongoing operations and its ability to raise capital, if required, in the near future or on terms favorable to the Company.
The Company's ability to continue as a going concern is dependent upon the lender maintaining the borrowing base limit on the credit facility and the Company's ability to generate net cash from operating activities or raise additional financing to continue to fund its working capital deficiency, debt repayments and capital expenditures. These matters cause material uncertainty which may cast significant doubt on the Company's ability to continue as a going concern.
These financial statements do not reflect adjustments that would be necessary if the going concern assumption was not appropriate. If the going concern assumption were not appropriate, adjustments would be necessary in the carrying value of the Company's assets and liabilities, the reported revenues and expenses, and the balance sheet classifications used. These adjustments could be material.
Operating Summary
The Company's results of operations are dependent on production volumes of natural gas, crude oil and natural gas liquids and the prices received for the production. Prices for these commodities have shown significant volatility during recent years and are determined by supply and demand factors, including weather and general economic conditions.
OVERVIEW
Results at a Glance | |||||||||
Year Ended December 31, | 2020 | 2019 | 2018 | ||||||
Financial (US $000 except per share) | |||||||||
Oil and gas gross revenues | 12,251 | 22,179 | 30,364 | ||||||
Net operating income(1) | 6,825 | 13,639 | 19,156 | ||||||
Net income (loss) | (70,410 | ) | (177 | ) | 5,320 | ||||
Basic and diluted net income (loss) per share | (0.30 | ) | (0.00 | ) | 0.02 | ||||
Cash flow from operating activities | 6,111 | 6,771 | 11,777 | ||||||
Adjusted funds flow(2) | 7,196 | 9,006 | 13,223 | ||||||
Additions (adjustments) to property, plant and equipment | (16 | ) | 2,289 | 19,621 | |||||
Operating | |||||||||
Average production (Boepd) | 1,151 | 1,395 | 1,662 | ||||||
Average price ($/BOE) | 29.08 | 43.56 | 52.15 | ||||||
Netback from operations ($/BOE)(3) | 16.20 | 26.79 | 33.99 | ||||||
Netback including commodity contract ($/BOE)(3) | 23.86 | 25.30 | 30.12 | ||||||
Balance Sheet | |||||||||
Cash and cash equivalents | 920 | 3,089 | 1,456 | ||||||
Total assets | 82,184 | 161,208 | 164,559 | ||||||
Working capital (deficiency) | (3,456 | ) | (2,482 | ) | (2,393 | ) | |||
Total non-current liabilities | 19,978 | 26,891 | 30,687 |
(1) Net operating income is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
(2) Adjusted Funds Flow is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
(3) Netback from operations and netback including commodity contracts are considered non-GAAP measures. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
Highlights
The average production for 2020 was 1,151 BOEPD, a decrease of 17% compared to 2019 production of 1,395 BOEPD. The decrease is due to the normal production decline of existing wells.
In 2020, the Company had commodity contracts in place for over 80% of its production at an average oil price of $56.62/barrel and realized gains of over $3.2 million from these contracts. The Company has commodity contracts in place for almost 70% of its existing 2021 oil production at an average price of $47.96/barrel.
Gross revenues for 2020 decreased by 45% compared to 2019. Adjusted funds flow(1) was $7.2 million for 2020 compared to $9.0 million for 2019, a decrease of 20%. These decreases were primarily due to a 17% decrease in production in 2020 compared to 2019 and a 33% decrease in average prices in 2020 partially offset by the realized gains from commodity contracts in 2020.
General & administrative (G&A) expenses for 2020 was $2.9 million compared to $3.9 million in 2019, a decrease of 26%. The decrease is due to lower payroll and related costs due to employee terminations at the end of 2019, severance costs that were recorded in 2019 and management's continued efforts to reduce G&A costs throughout the Company.
Operating expense per barrel averaged $6.54 per BOE in 2020 compared to $7.39 per BOE in 2019, a decrease of 12%. The decrease was due to cost cutting measures taken in the field during 2020.
Interest expense has decreased by 34% in 2020 compared to the prior year due to principal payments on the credit facility which reduced the outstanding loan balance and lower interest rates.
Netback from operations(2) decreased to $16.20 per BOE in 2020 compared to $26.79 per BOE in 2019, a decrease of 40%. Netback including the impact of commodity contracts(2) for 2020 was $23.86 per BOE, a decrease of 6% from the prior year. The 2020 decrease compared to the same period in the prior year was due to the decrease in average prices and the decrease in average production which increases the fixed operating cost per barrel.
Adjusted funds flow(1) was $7.2 million for 2020 compared to $9.0 million for 2019, a decrease of 20%. The decreases were mainly due to lower revenue caused by lower average prices and production.
Due to industry and market conditions, especially the significant decline in forecasted oil and gas commodity prices and the global impact on demand from the COVID-19 pandemic, the Company identified indicators of impairment and performed a property, plant and equipment (PP&E) impairment test at March 31, 2020. The impairment test resulted in an impairment charge which totaled $71.9 million for the first quarter of 2020. In accordance with IFRS, an impairment charge can be reversed in future periods if there is an indicator of reversal that suggests that a previously recognized impairment charge has reversed because of a change in the estimates used to determine the impairment charge and the estimated recoverable amount of the impaired asset or CGU subsequently increases. The Company also identified indicators of impairment and performed a PP&E impairment test at December 31, 2020. There was no impairment charge or reversal of historic impairment charges as a result of the impairment test at December 31, 2020.
Net loss in 2020 was $70.4 million, compared to net income of $0.2 million in 2019, due to the impairment charge of $71.9 million related to the CGU for the year ended December 31, 2020.
In September 2020, the Company's credit facility was re-determined at a borrowing base of $22.0 million and subsequent to the redetermination, the Company made principal payments of $1.3 million to bring the outstanding balance to $20.67 million at December 31, 2020. In accordance with the redetermination, the Company has no available capacity on the credit facility and the borrowing base will be automatically reduced by the principal payments as they are paid. In addition, the Company will make additional principal payments to reduce the borrowing base to $18.6 million by May 2021. These future principal payments are projected to be funded from cash on hand and adjusted funds flow from operations. The next redetermination will be in the second quarter of 2021.
(1) Adjusted funds flow is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
(2) Netback from operations and netback including commodity contracts are considered non-GAAP measures. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
OPERATIONS UPDATE
Tishomingo Field, Ardmore Basin, Oklahoma
Average production for 2020 was 1,151 BOEPD, a decrease of 17% compared to the 2019 average production of 1,395 BOEPD. In 2020, the Company had commodity contracts in place for over 80% of its production at an average oil price of $56.62/barrel and realized gains of over $3.2 million from these contracts.
DISCUSSION OF OPERATING RESULTS | |||||||||
Production and Revenue | |||||||||
FY2020 | FY2019 | % | |||||||
Average oil production (BOPD) | 785 | 1,004 | (22 | ) | |||||
Average natural gas production (MCF/D) | 1,013 | 1,037 | (2 | ) | |||||
Average NGL production (BOEPD) | 197 | 218 | (10 | ) | |||||
Average production (BOEPD) | 1,151 | 1,395 | (17 | ) | |||||
Average oil price ($/bbl) | 36.85 | 54.99 | (33 | ) | |||||
Average natural gas price ($/mcf) | 1.96 | 2.52 | (22 | ) | |||||
Average NGL price ($/bbl) | 12.94 | 13.42 | (4 | ) | |||||
Average price ($/BOE) | 29.08 | 43.56 | (33 | ) | |||||
Oil revenue ($000) | 10,593 | 20,157 | (47 | ) | |||||
Natural gas revenue ($000) | 725 | 954 | (24 | ) | |||||
NGL revenue ($000) | 933 | 1,068 | (13 | ) |
Oil production for 2020 was 785 BOPD compared to 1,004 BOPD for 2019, a decrease of 22%. The production decrease is due to the natural decline of existing wells. Oil revenue decreased by 47% in 2020 versus 2019 due to a decrease in oil prices of 33% combined with the production decrease.
For 2020, average natural gas production was 1,013 MCFPD compared to 1,037 MCFPD in 2019, a decrease of 2%. The decrease in 2020 is due to the natural decline of existing wells. Natural gas revenue decreased by 24% in 2020 versus 2019 due to a decrease in natural gas prices of 22% combined with the decrease in natural gas production.
Natural gas liquids (NGL) production in 2020 decreased to 197 BOEPD from 218 BOEPD in 2019, a decrease of 10%. NGL revenue decreased by 13% in 2020 compared to 2019 due to a decrease in NGL prices of 4% combined with the production decrease.
Average production on a per BOE basis was 1,151 BOEPD in 2020 compared to 1,395 BOEPD in 2019, a decrease of 17%. The decrease is due to the factors discussed above. Gross revenue for 2020 decreased by 45% compared to 2019 due to decreases in average prices and production.
Royalties, Operating Expenses and Netbacks | |||||||||
($/BOE) | FY2020 | FY2019 | % | ||||||
Average price | 29.08 | 43.56 | (33 | ) | |||||
Less: Royalties | 6.34 | 9.38 | (32 | ) | |||||
Less: Operating expenses | 6.54 | 7.39 | (12 | ) | |||||
Netback from operations(1) | 16.20 | 26.79 | (40 | ) | |||||
Price adjustment from commodity contracts(2) | 7.66 | (1.49 | ) | - | |||||
Netback including commodity contracts(1) | 23.86 | 25.30 | (6 | ) |
(1) Netback from operations and netback including commodity contracts are considered non-GAAP measures. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
(2) Price adjustment from commodity contracts includes the positive or negative adjustment to the average price per barrel that the Company realized from its commodity contracts. See the listing of commodity contracts below.
The average price decrease in 2020 was due to price decreases in oil, gas and NGLs. Oil made up 68% of the production mix in 2020 compared to 72% of the production mix in 2019.
Royalties on Tishomingo production averaged approximately 21.8% for 2020 versus 21.5% in 2019. The percentages differences are due to different royalty burdens on the wells produced by the Company.
Major operating expenses are related to the gathering and processing of natural gas and NGLs as well as periodic well repairs and maintenance. Operating expenses for 2020 were $2.8 million compared to $3.8 million in 2019. Operating expenses averaged $6.54 per BOE for 2020 compared to $7.39 per BOE for 2019. The decrease was due to cost cutting measures taken in the field during the current year including decreases in field personnel and new chemical contracts that decreased costs.
Realized and Unrealized Gains and Losses from Risk Management Contracts
The Company has entered into financial commodity contracts which are summarized in the table below. Total Volume Hedged in the table is the annual volumes and Price is the fixed price specified in the financial commodity contracts.
At December 31, 2020 the following financial commodity contracts were outstanding and recorded at estimated fair value:
|
| Total Volume Hedged (BBLS) | Price |
Commodity | Period | ($/BBL) | |
Oil - WTI | January 1, 2021 to December 31, 2021 | 72,000 | $52.66 |
Oil - WTI | January 1, 2021 to December 31, 2021 | 60,000 | $42.32 |
The estimated fair value results in a $0.04 million liability as of December 31, 2020 (December 31, 2019: $0.4 million liability) for the financial oil and gas contracts which has been determined based on the prospective amounts that the Company would receive or pay to terminate the contracts, consisting of a current liability of $0.04 million (December 31, 2019: current liability of $0.3 million and a long term liability of $0.1 million).
In February 2021, the Company entered into the following additional financial commodity contract:
|
| Total Volume | Price |
Commodity | Period | ($/BBL or | |
Oil - WTI(1) | January 1, 2022 to September 30, 2022 | 54,000 | $55.92 |
The realized and unrealized gains/losses from the financial commodity contracts are as follows:
($000s) | December 31, | |||||
2020 | 2019 | |||||
Realized gain (loss) on financial commodity contracts | $ | 3,228 | (759 | ) | ||
Unrealized gain (loss) on financial commodity contracts | $ | 313 | (749 | ) |
General and Administrative Expenses
G&A expense for 2020 was $2.9 million compared to $3.9 million in 2019, a decrease of 26%. The decrease is due to lower payroll and related costs due to employee terminations at the end of 2019, severance costs that were recorded in 2019 and management's continued efforts to reduce G&A costs throughout the Company.
Impairment of Property, Plant and Equipment
The Company identified indicators of impairment, due to industry and market conditions, especially the global impact of the COVID-19 pandemic, and performed a PP&E impairment test at March 31, 2020. The estimated recoverable amount under the impairment test was $80.8 million which resulted in an impairment charge of $71.9 million as at March 31, 2020. In accordance with IFRS, an impairment charge can generally be reversed in future periods if there is an indication of reversal that suggests that a previously recognized impairment charge has reversed because of a change in the estimates used to determine the impairment charge and the estimated recoverable amount of the impaired asset or CGU subsequently increases. An impairment charge 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 charge had been recognized. The Company also performed a PP&E impairment test at December 31, 2020. There was no impairment charge or reversal of historic impairment charges as a result of the impairment test at December 31, 2020.
Depletion and Depreciation
Depletion and depreciation expense for 2020 was $4.6 million compared to $6.2 million in 2019. The decrease in the period is due to decreased production and a lower PP&E balance due to the impairment charge. Depletion and depreciation expense on a per barrel basis was $10.95 for 2020 compared to $12.26 for 2019.
Share based compensation
Share based compensation decreased from $149,000 in 2019 to $21,000 in 2020. The decrease is due to prior year stock option grants where the vesting provisions were front loaded.
Interest on loans and borrowings
Interest on loans and borrowings decreased from $2.0 million in 2019 to $1.3 million for the same period of 2020. The decrease was due to principal payments on the credit facility which reduced the outstanding loan balance and lower interest rates.
Net loss
The Company had net loss of $70.4 million ($0.30 per share) for 2020 compared to net loss of $0.2 million ($0.00 per share) for 2019. The increase in net loss for 2020 is due to an impairment charge of $71.9 million, and a decrease in revenue net of royalties of $7.8 million, partially offset by realized and unrealized gains in financial commodity contracts in 2020 totaling $3.5 million versus losses of $1.5 million in 2019, a decrease in depletion, depreciation and accretion of $1.6 million, a decrease in operating expenses of $1.0 million, a decrease in G&A expense of $1.0 million, a decrease in interest on loans and borrowings of $0.7 million, and a decrease in share based compensation of $0.1 million.
Cash from continuing operating activities
Cash flows from continuing operating activities for 2020 was $6.1 million compared to cash flows from continuing operating activities of $6.8 million in 2019.
CAPITAL EXPENDITURES
For 2020, there was a true-up of estimated costs to actual costs on the non-operated Anderson 1-15H10X3 well resulting in a reduction of capital expenditures. Capital expenditures for 2019 were for the Anderson 1-15H10X3 well (non-operated, KEI 33% working interest) and workovers on four operated wells in the Tishomingo field located in Oklahoma.
($000) | ||||||
2020 | 2019 | |||||
Additions (adjustments) to oil and gas properties | $ | (16 | ) | $ | 2,289 | |
$ | (16 | ) | $ | 2,289 |
LIQUIDITY AND CAPITAL RESOURCES | ||||||
At December 31, | ||||||
(000s) | 2020 | 2019 | ||||
Working Capital Deficiency (US$)(1) | $ | (3,456 | ) | $ | (2,482 | ) |
Loans and Borrowings (US$) | $ | 20,667 | $ | 27,500 | ||
Shares Outstanding, end of year | 232,922.6 | 232,922.6 | ||||
Market Price per share, end of year (in Canadian $) | $ | 0.06 | $ | 0.11 | ||
Market Value of Shares (in Canadian $) | $ | 13,975 | $ | 25,621 |
(1) Includes current portion of loans of borrowings.
In June 2017, the Company's US subsidiary obtained a new credit facility from BOK Financial, which is secured by the US subsidiary's interests in the Tishomingo Field. The credit facility expires in June 2022 and is intended to fund the drilling of the Caney wells in the Tishomingo Field.
In September 2020, the credit facility was redetermined at a borrowing base of $22.0 million. Subsequent to the redetermination, the Company made principal payments to reduce the outstanding balance to $20.7 million on December 31, 2020. In accordance with the redetermination, the Company has no available capacity on the credit facility and the borrowing base is automatically reduced by the principal payments as they are paid. In addition, the Company is required to make additional principal payments to reduce the borrowing base to $18.6 million by May 2021. These future principal payments are projected to be funded from cash on hand and adjusted funds flow from operations. The credit facility is subject to a semi-annual review and redetermination of the borrowing base. The next redetermination will be in the second quarter of 2021. Future commitment amounts will be subject to new reserve evaluations and there is no guarantee that the size and terms of the credit facility will remain the same after the borrowing base redetermination. Any redetermination of the borrowing base is effective immediately and if the borrowing base is reduced, the Company has six months to repay any shortfall.
The credit facility has two primary debt covenants. One covenant requires the US subsidiary to maintain a positive working capital balance which includes any unused excess borrowing capacity and excludes the fair value of commodity contracts, the current portion of long-term debt (the "Current Ratio") and certain payables to an operator that are being reduced by the revenue earned from the non-operated well. The second covenant ensures the ratio of outstanding debt and long-term liabilities to an annualized quarterly adjusted EBITDA amount (the "Maximum Leverage Ratio") be no greater than 4 to 1 at any quarter end. Adjusted EBITDA is defined as net income excluding interest expense, depreciation, depletion and amortization expense, and other non-cash and non-recurring charges including severance, stock based compensation expense and unrealized gains or losses on commodity contracts.
The Company was in compliance with both covenants for the quarter ended December 31, 2020. At December 31, 2020, the Current Ratio of the US Subsidiary was 1.97 to 1.0 and the Maximum Leverage Ratio was 2.84 to 1.0 for the three months ended December 31, 2020.
The current global and market volatility, including the continuing uncertainty due to the impact of the COVID-19 pandemic, impacts the ability to prepare financial forecasts. The Company's current forecast indicates that it will be able to fund the future principal payments from cash on hand and funds flow from operations and that it will be in compliance with its debt covenants over the next twelve months. These forecasts are based on current strip prices and the Company's current hedges and they include a significant amount of estimates and judgments that could change in the future. If circumstances change and a covenant violation does occur and the Company does not obtain a waiver, this will represent an event of default under the facility and the lender will have the right to demand repayment of all amounts owed under the facility.
In April 2020, the Company's US subsidiary obtained a loan under the Paycheck Protection Program ("PPP") which is being administered by the Small Business Administration ("SBA"). The loan amount is $0.3 million with a 5-year term at an annual interest rate of 1 percent. All interest payments are deferred for the first ten months after the end of the loan forgiveness period, which is twenty-four weeks from the initiation of the loan. The loan amount may be forgiven if the proceeds are used for eligible expenditures, which include payroll costs, rent expense and utilities, in the twenty-four week forgiveness period. The Company has applied for loan forgiveness for the entire portion of the PPP loan and is awaiting a response from the SBA. In February 2021, the US subsidiary obtained a loan under the PPP2 loan program for an additional $0.3 million. The PPP2 loan has the same terms as the original PPP loan and may also be forgiven if the proceeds are used for eligible expenditures.
At December 31, 2020, loans and borrowings of $20.7 million (December 31, 2019: $27.5 million) are presented net of loan acquisition costs of $0.2 million (December 31, 2019: $0.3 million).
At December 31, 2020, the Company had negative working capital of $3.5 million, versus negative working capital of $2.5 million at December 31, 2019. The Company does not have any drilling commitments and closely monitors its working capital and borrowing capacity to ensure adequate funds are available to finance its administrative and operating requirements.
The Company has entered into financial commodity contracts as part of its risk management strategy to manage its cash flow for future activity and to offset commodity price fluctuations. The Company believes that the combination of cash on hand and cash flow from operations will be sufficient to finance the Company's cash requirements through the next twelve months. Other potential sources of cash flow include proceeds from additional debt or equity offerings but there is no guarantee that additional financing will be available when needed.
CONTRACTUAL OBLIGATIONS
The following are the contractual maturities of financial liabilities, excluding estimated interest payments at December 31, 2020:
($000) | Total | 2021 | 2022 | 2023 | 2024 | 2025 | ||||||||||||
Loans and borrowings * | $ | 20,749 | $ | 2,084 | $ | 18,362 | - | - | $ | 303 | ||||||||
Trade and other payables | 4,371 | 4,371 | - | - | - | - | ||||||||||||
Lease payable | 110 | 66 | 44 | - | - | - | ||||||||||||
$ | 25,230 | $ | 6,521 | $ | 18,406 | - | - | $ | 303 |
* The Credit Facility provides for interest only payments until the June 2022 maturity date. The Company is required to repay amounts owing under the Credit Facility in full on the June 2022 maturity date. See "Liquidity and Capital Resources" and "Principal Business Risks" for discussion of events that would require early repayment of the Credit Facility.
QUARTERLY SUMMARY
Below is a summary of the Company's performance over the last eight quarters:
2020 | 2019 | |||||||||||||||||||||||
($000, except as noted) | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||
Daily Production | ||||||||||||||||||||||||
Oil (BOPD) | 735 | 761 | 804 | 842 | 923 | 968 | 1,016 | 1,113 | ||||||||||||||||
Natural gas (MCFPD) | 924 | 1,027 | 1,033 | 1,067 | 1,063 | 995 | 1,052 | 1,039 | ||||||||||||||||
NGL's (BOEPD) | 193 | 202 | 187 | 205 | 246 | 223 | 177 | 227 | ||||||||||||||||
Average production (BOEPD) | 1,082 | 1,134 | 1,163 | 1,225 | 1,346 | 1,357 | 1,368 | 1,513 | ||||||||||||||||
2020 | 2019 | |||||||||||||||||||||||
($000, except as noted) | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||
Average Price | ||||||||||||||||||||||||
Oil ($/bbl) | 40.42 | 38.7 | 23.35 | 44.88 | 55.13 | 54.38 | 58.05 | 52.59 | ||||||||||||||||
Natural gas ($/mcf) | 2.52 | 1.79 | 1.63 | 1.95 | 2.24 | 1.97 | 2.61 | 3.26 | ||||||||||||||||
NGL ($/bbl) | 14.39 | 14.50 | 7.00 | 15.43 | 15.61 | 10.20 | 16.04 | 12.16 | ||||||||||||||||
Average price ($/bbl) | 32.19 | 30.16 | 18.72 | 35.15 | 42.41 | 41.91 | 47.19 | 42.76 |
2020 | 2019 | |||||||||||||||||||||||
($000, except as noted) | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||
Netback(1) | ||||||||||||||||||||||||
Average price ($/BOE) | 32.19 | 30.16 | 18.72 | 35.15 | 42.41 | 41.91 | 47.19 | 42.76 | ||||||||||||||||
Royalties | 6.97 | 6.53 | 4.24 | 7.60 | 9.13 | 9.04 | 10.22 | 9.15 | ||||||||||||||||
Operating expenses | 6.84 | 6.46 | 6.07 | 6.80 | 7.71 | 7.48 | 7.59 | 6.82 | ||||||||||||||||
Netback from operations(1) | 18.38 | 17.17 | 8.41 | 20.75 | 25.57 | 25.39 | 29.38 | 26.79 | ||||||||||||||||
Price adjustment from commodity contracts | 7.02 | 7.73 | 12.74 | 3.35 | -1.21 | -1.04 | -2.45 | -1.27 | ||||||||||||||||
Netback including commodity contracts(1) | 25.4 | 24.9 | 21.15 | 24.1 | 24.36 | 24.35 | 26.93 | 25.52 | ||||||||||||||||
2020 | 2019 | |||||||||||||||||||||||
($000, except as noted) | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||
Net operating income(2) | ||||||||||||||||||||||||
Oil and gas revenue | 3,204 | 3,147 | 1,981 | 3,918 | 5,252 | 5,232 | 5,875 | 5,823 | ||||||||||||||||
Royalties | 694 | 680 | 449 | 847 | 1,131 | 1,129 | 1,272 | 1,246 | ||||||||||||||||
Operating expenses | 681 | 674 | 642 | 758 | 955 | 934 | 945 | 929 | ||||||||||||||||
1,829 | 1,793 | 890 | 2,313 | 3,166 | 3,169 | 3,658 | 3,648 | |||||||||||||||||
2020 | 2019 | |||||||||||||||||||||||
($000, except as noted) | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||
Net earnings (loss) | (1,078 | ) | (616 | ) | (2,369 | ) | (66,492 | ) | (1,650 | ) | 1,420 | 1,531 | (1,477 | ) | ||||||||||
Basic and Fully Diluted Earnings (loss) per $/share | 0.00 | - | (0.01 | ) | (0.29 | ) | (0.01 | ) | 0.01 | 0.01 | (0.01 | ) | ||||||||||||
Adjusted funds flow(3) | 1,737 | 1,893 | 1,601 | 1,952 | 1,674 | 2,233 | 2,525 | 2,574 | ||||||||||||||||
Bank debt | 20,749 | 21,552 | 22,720 | 26,190 | 27,164 | 27,134 | 29,606 | 29,580 | ||||||||||||||||
Total assets | 82,184 | 85,034 | 86,411 | 92,782 | 161,208 | 161,598 | 163,185 | 163,118 |
(1) Netback from operations and netback including commodity contracts are considered non-GAAP measures. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
(2) Net operating income is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
(3) Adjusted funds flow is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
(4) Prior period adjustments reflects adjustments for natural gas and NGL volumes sold and processing costs related to prior years due to the purchaser re-measuring prior volumes and reassessing prior gathering and processing costs.
Quarterly Variability
Fluctuations in quarterly results are due to a number of factors, some of which are not within the Company's control such as:
Oil, gas and NGL price changes due to market conditions.
Changes in production resulting from fluctuations in drilling and completions and shut-in of wells.
The changes in G&A from quarter to quarter reflect changes in operations, changes in personnel, and non-recurring charges related to specific transactions or events.
FOURTH QUARTER 2020
Average total production during the fourth quarter of 2020 was 1,082 BOEPD compared to 1,346 BOEPD in the fourth quarter of 2019, a decrease of 20%. During the fourth quarter of 2020, oil production decreased by 20% to 735 BOEPD from 923 BOEPD for the same quarter of 2019. The Company's natural gas production decreased 13% to 924 MCFPD from 1,063 MCFPD in the same quarter of 2019. NGL production decreased during the quarter by 21% to 193 BOEPD from 246 BOEPD in the same quarter of 2019.
Oil and NGL prices for the fourth quarters of 2020 and 2019 are shown in the following table:
Q4-2020 | Q4-2019 | % Change | |||||||
Oil ($/bbls) | 40.42 | 55.13 | (27 | ) | |||||
Natural gas ($/mcf) | 2.52 | 2.24 | 13 | ||||||
NGL ($/bbls) | 14.39 | 15.61 | (8 | ) | |||||
Total average price ($/boe) | 32.19 | 42.41 | (24 | ) |
The Company's netback(1) were as follows:
Q4-2020 | Q4-2019 | % Change | |||||||
Average price ($/boe) | �� | 32.19 | 42.41 | (24 | ) | ||||
Less: Royalties | 6.97 | 9.13 | (24 | ) | |||||
Less: Operating expenses | 6.84 | 7.71 | (11 | ) | |||||
Netback from operations(1) | 18.38 | 25.57 | (28 | ) | |||||
Price adjustment from commodity contracts(2) | 7.02 | (1.21 | ) | 7 | |||||
Netback including commodity contracts(1) | 25.40 | 24.36 | 4 |
(1) Netback from operations and netback including commodity contracts are considered non-GAAP measures. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
(2) Net operating income is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this MD&A.
Oil and gas gross revenue during the fourth quarter of 2020 decreased 40% to $3.2 million compared to $5.3 million for the same quarter in 2019 and net operating income(1) decreased to $1.8 million during the fourth quarter of 2020 compared to $3.2 million in the fourth quarter of 2019. Adjusted funds flow was $1.7 million in the fourth quarter of 2020 compared to $1.7 million in the fourth quarter of 2019.
The Company had a net loss of $1.1 million during the fourth quarter of 2020 compared to a net loss of $1.7 million for the fourth quarter of 2019 primarily due to realized gains from commodity contracts of $0.7 million in the fourth quarter of 2020 compared to realized losses of $0.2 million in the fourth quarter of 2019.
(1) Net operating income is considered a non-GAAP measure. Refer to the section entitled "Non-GAAP Measures" at the end of this
MD&A.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the consolidated financial statements requires management to make estimates and use judgment regarding the reported amounts of assets and liabilities, the disclosures of contingencies at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future years could require a material change in the financial statements. Accordingly, actual results may differ from the estimated amounts. Significant estimates and judgments made by management in the preparation of the consolidated financial statements are as follows:
Oil and gas assets
Development and production assets are assessed for recoverability at cash generating unit ("CGU") level. The determination of CGUs is subject to management judgments. Recoverability is assessed by comparing the carrying value of the asset to its estimated recoverable amount, which is based on the higher of fair value of the assets less the cost to sell ("FVLCS") or value in use ("VIU"). The significant estimates used in the determination of the estimated recoverable amount include the following:
- Proved and probable oil and gas reserves and the related cash flows - Significant assumptions that are valid at the time of oil and gas reserve estimation may change significantly when additional information becomes available. Estimates of economically recoverable proved and probable oil and gas reserves and the related cash flows are based upon a number of significant assumptions, such as forecasted production, forecasted oil and gas commodity prices, forecasted operating costs, forecasted royalty costs, and forecasted future development costs. Changes in forecasted oil and gas commodity price assumptions, costs or recovery rates may change the economic status of proved and probable oil and gas reserves and may ultimately result in a restatement of proved and probable oil and gas reserves. Independent third-party reserve evaluators are engaged at least annually to estimate proved and probable oil and gas reserves and the related cash flows from the Company's interest in oil and gas properties
- Discount rate - The discount rate used to calculate the net present value of cash flows is based on estimates of an industry peer group weighted average cost of capital. Changes in the economic environment could result in significant changes to this estimate.
Depletion of oil and gas assets
Depletion of oil and gas assets is determined based on total proved and probable oil and gas reserve volumes and includes future development costs as estimated by the Company's independent third-party reserve evaluators. By their nature, the estimates of proved and probable oil and gas reserves and the related cash flows are subject to measurement uncertainty. Accordingly, the impact to the consolidated financial statements in future periods could be material.
Asset retirement obligations
The provisions for site restoration and abandonment is based on current legal requirements, technology, price levels and expected plans and are based on significant assumptions such as inflation rate and discount rate. Actual costs and cash outflows can differ from estimates because of changes in laws or regulations, market conditions and changes in technology.
Derivative instruments
The estimated fair value of derivative financial instruments resulting in financial assets and liabilities, by their very nature is subject to estimation, due to the use of future oil and natural gas prices and the volatility in these prices.
Compensation costs
Compensation costs recognized for share based compensation plans are subject to the estimation of what the ultimate payout will be using pricing models such as Black-Scholes model which is based on assumptions such as volatility, forfeiture rate, interest rate and expected term.
Income taxes
Tax interpretations, regulations and legislation in the various jurisdictions in which the Company operates are subject to change. As such income taxes are subject to measurement uncertainty. Deferred income tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings.
Liquidity
The Company's approach to managing liquidity is to ensure, as far as possible, that it will always have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company's reputation.
Typically the Company ensures that it has sufficient cash on demand and cash flow from operations to meet expected operational expenses for a one-year period, including the servicing of financial obligations; this excludes the potential impact of extreme circumstances that cannot reasonably be predicted, such as natural disasters. To achieve this objective, the Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditure. The Company also attempts to match its payment cycle with collection of oil revenue on the 20th of each month.
The Company monitors its expected cash inflows from trade and other receivables and its expected cash outflows on trade and other payables and principal debt payments. The Company will make principal debt payments of $2.1 million by May 1, 2021 and will utilize its cash on hand and cash inflows to fund these principal payments as well as its trade payables. The current challenging economic climate may lead to adverse changes in cash flow, working capital levels or debt balances, which may also have a direct impact on the Company's results and financial position. These and other factors may adversely affect the Company's liquidity and the Company's ability to generate profits in the future.
OUTSTANDING SHARE DATA
There were 232,922,625 common shares outstanding as of both March 11, 2021 and December 31, 2020. The Company had 3,125,000 and 4,655,000 stock options outstanding as of March 11, 2021 and December 31, 2020, respectively.
PRINCIPAL BUSINESS RISKS
KEI's business and results of operations are subject to a number of risks and uncertainties, including but not limited to the following:
- the uncertainty of finding oil and gas in commercial quantities
- securing markets for existing and future production
- commodity price fluctuations due to market forces including the impact of COVID-19
- financial risk due to foreign exchange rates and interest rate exposure
- changes to government regulations in the United States, including regulations relating to prices, taxes, royalties and environmental protection
- changing government policies and regulations, social instability and other political, economic or diplomatic developments in the countries in which the Company operates
- the ability to fund wells drilled in non-operated sections of the Tishomingo field
- the uncertainty of pipeline repairs leading to temporary shutting-in of wells
- availability of equity or debt financing is affected by many factors many of which are beyond the control of the Company
- uncertainties inherent in estimating quantities of oil and natural gas reserves and cash flows to be derived therefrom
- the oil and gas industry is intensely competitive and the Company competes with a large number of companies with greater resources
- risks related to the Credit Facility, including the risk that the Company could be required under the terms of the Credit Facility to prepay the outstanding principal amount and other amounts owing under the Credit Facility in certain circumstances, some of which are out of the Company's control, including failure to comply with financial ratio tests, borrowing base redeterminations, Mr. Wolf Regener ceasing to be the President of BNK Petroleum (US) Inc., certain changes to the board of directors of the Company and the acquisition by any person or persons acting jointly or in concert of 25% or more of the Company's shares. The Company is required to repay amounts owing under the Credit Facility in full on the June 2022 maturity date. There can be no assurance that the Company will be able to obtain sufficient capital to repay the Credit Facility or that the Company will be able to extend or refinance the Credit Facility. A failure by the Company to perform its obligations under the Credit Facility could result in, among other adverse effects, the loss of the Company's Tishomingo Field assets. A copy of the Amended and Restated Credit Agreement was filed on SEDAR on June 26, 2017. See "Liquidity and Capital Resources" and "Contractual Obligations" above and the "Risk Factors" section in the Company's most recent Annual Information Form.
- the other risks identified in the Company's most recent Annual Information Form under the "Risk Factors" section and the Company's other public disclosure, available under the Company's profile on SEDAR at www.sedar.com.
The Company seeks to mitigate these risks by:
- maintaining product mix to manage exposure to commodity price risk
- monitoring production trends to maximize the potential of its capital spending program
- from time to time, entering into financial commodity contracts to hedge against commodity price risk
- ensuring strong third-party operators for non-operated properties
- transacting with creditworthy counterparties
- monitoring commodity prices and capital programs to manage cash flow
- reviewing proposed changes in applicable government regulations and laws to assess the impact on the Company's operations
DISCLOSURE CONTROLS AND PROCEDURES
The Chief Executive Officer ("CEO") and the Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P") and internal controls over financial reporting ("ICOFR") as defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements in accordance with IFRS.
The DC&P have been designed to provide reasonable assurance that material information relating to KEI is made known to the CEO and CFO by others and that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by KEI under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation. The Company's CEO and CFO have concluded, based on their evaluation that the Company's disclosure controls and procedures and ICOFR are effective at December 31, 2020 to provide reasonable assurance that material information related to the Company, is made known to them by others within the Company.
The CEO and CFO are required to cause the Company to disclose any change in the Company's ICOFR that occurred during the most recent interim period that has materially affected, or is reasonably likely to materially affect, the Company's ICOFR. No changes in ICOFR were identified during such period that have materially affected, or are reasonably likely to materially affect, the Company's ICOFR. There were no changes to ICOFR during the quarter ended December 31, 2020.
It should be noted that a control system, including the Company's DC&P and ICOFR, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system will be met and it should not be expected that DC&P and ICOFR will prevent all errors or fraud.
OUTLOOK
In the United States, the Company intends to drill and complete additional wells in the Caney/Sycamore formations on its Oklahoma lands as financing becomes available and the economic environment changes. In addition, the Company continues to utilize its technical and operational expertise to identify and acquire additional oil, gas and clean energy projects.
NON-GAAP MEASURES
Netback from operations, netback including commodity contracts, net operating income and adjusted funds flow (collectively, the "Company's Non-GAAP Measures") are not measures recognized under Canadian generally accepted accounting principles ("GAAP") and do not have any standardized meanings prescribed by GAAP. Management of the Company believes that such measures are relevant for evaluating returns on each of the Company's projects as well as the performance of the enterprise as a whole. The Company's Non-GAAP Measures may differ from similar computations as reported by other similar organizations and, accordingly, may not be comparable to similar non-GAAP measures as reported by such organizations. The Company's Non-GAAP Measures should not be construed as alternatives to net income, cash flows related to operating activities, working capital or other financial measures determined in accordance with GAAP, as an indicator of the Company's performance.
Netback from operations per barrel and its components are calculated by dividing revenue, less royalties and operating expenses by the Company's sales volume during the period. Netback including commodity contracts is calculated by adjusting netback from operations by the realized gains or losses received from commodity contracts during the period. Netback is a non-GAAP measure but it is commonly used by oil and gas companies to illustrate the unit contribution of each barrel produced. The Company believes that the netback is a useful supplemental measure of the cash flow generated on each barrel of oil equivalent that is produced in its operations. However, non-GAAP measures do not have any standardized meaning prescribed by GAAP and therefore, may not be comparable to similar measures used by other companies and should not be used to make comparisons.
The following is the reconciliation of the non-GAAP measure netback from operations to net income (loss) from continuing operations:
(US $000) | Year ended December 31, | |||||
2020 | 2019 | |||||
Net loss from continuing operations | (70,410 | ) | (177 | ) | ||
Adjustments: | ||||||
Finance income | (3,542 | ) | - | |||
Finance expense | 1,362 | 3,557 | ||||
Stock based compensation | 21 | 149 | ||||
General and administrative expenses | 2,859 | 3,879 | ||||
Impairment of property, plant and equipment | 71,923 | 0 | ||||
Depletion, depreciation and amortization | 4,614 | 6,240 | ||||
Exploration and evaluation expenses | - | - | ||||
Other income | (2 | ) | (9 | ) | ||
Operating netback | 6,825 | 13,639 | ||||
Netback from operations | $ | 16.20 | $ | 26.79 |
Net operating income is similarly a non-GAAP measure that represents revenue net of royalties and operating expenses. The Company believes that net operating income is a useful supplemental measure to analyze operating performance and provides an indication of the results generated by the Company's principal business activities prior to the consideration of other income and expenses.
The following is the reconciliation of the non-GAAP measure net operating income:
(US $000) | Year ended December 31, | |||||
2020 | 2019 | |||||
Oil and gas revenue, net of royalties | 9,580 | 17,402 | ||||
Less: production and operating expenses | 2,755 | 3,763 | ||||
Net operating income | 6,825 | 13,639 |
Adjusted funds flow is calculated as cash from operating activities excluding changes in non-cash operating working capital and interest expense. The Company considers this a key measure as it demonstrates its ability to generate funds from operations necessary for future growth excluding the impact from short-term fluctuations in the collection of accounts receivable and the payment of accounts payable and financing costs. The following is the reconciliation of the non-GAAP measure adjusted funds flow:
(US $000) | Year ended December 31, | |||||
2020 | 2019 | |||||
Cash flow from continuing operations | 6,111 | 6,771 | ||||
Change in non-cash working capital | (128 | ) | 355 | |||
Interest expense(a) | 1,213 | 1,880 | ||||
Adjusted funds flow | 7,196 | 9,006 |
(a) Interest expense on long-term debt excluding the amortization of debt issuance costs
CAUTIONARY STATEMENTS
(a) The Company's natural gas production is reported in thousands of cubic feet ("Mcfs"). The Company also uses references to barrels ("Bbls") and barrels of oil equivalent ("BOEs") to reflect natural gas liquids and oil production and sales. BOEs 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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
(b) Discounted and undiscounted net present value of future net revenues attributable to reserves do not represent fair market value.
(c) Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
(d) This MD&A and the Company's other public disclosure contains peak and 30-day initial production rates and other short-term production rates. Readers are cautioned that initial production rates are preliminary in nature and are not necessarily indicative of long-term performance or of ultimate recovery.
CAUTION REGARDING FORWARD-LOOKING INFORMATION
This MD&A contains forward-looking information including expectations regarding the Company's reserve-based loan facility, including scheduled repayments, proposed timing and expected results of exploratory and development work in the Company's Tishomingo Field, expected productivity from current and future wells, planned capital expenditure programs and cost estimates, the effect of design and performance improvements on future productivity, planned use and sufficiency of proceeds from the Company's debt and equity financings, cash on hand and cash flow from operations and the Company's strategy and objectives. The use of any of the words "target", "plans", "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe","intend" and similar expressions are intended to identify forward-looking statements.
Such forward-looking information is based on management's expectations and assumptions, including that the Company's geologic and reservoir models and analysis will be validated, that indications of early results are reasonably accurate predictors of the prospectiveness of the shale intervals, that previous exploration results are indicative of future results and success, that expected production from future wells can be achieved as modeled, declines will match the modeling, future well production rates will be improved over existing wells, that rates of return as modeled can be achieved, that recoveries are consistent with management's expectations, that additional wells are actually drilled and completed, that design and performance improvements will reduce development time and expense and improve productivity, that discoveries will prove to be economic, that well shut-ins will not materially reduce production or adversely affect future productivity, that anticipated results and estimated costs will be consistent with managements' expectations, that all required permits and approvals and the necessary labor and equipment will be obtained, provided or available, as applicable, on terms that are acceptable to the Company, when required, that no unforeseen delays, unexpected geological or other effects, equipment failures, permitting delays or labor or contract disputes are encountered, that the development plans of the Company and its co-venturers will not change, that the demand for oil and gas will be sustained, that the combination of cash on hand and cash flow from operations will be sufficient to finance the Company's cash requirements through 2020, that the Company will continue to be able to access sufficient capital through financings, credit facilities, farm-ins or other participation arrangements to maintain its projects, that the Company will continue in compliance with the covenants under its reserve-based loan facility and that the borrowing base will not be reduced, that the Company will not be adversely affected by changing government policies and regulations, social instability or other political, economic or diplomatic developments in the countries in which it operates and that global economic conditions will not deteriorate in a manner that has an adverse impact on the Company's business and its ability to advance its business strategy.
Forward looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to: any of the assumptions on which such forward looking information is based vary or prove to be invalid, including that the Company's geologic and reservoir models or analysis are not validated, anticipated results and estimated costs will not be consistent with managements' expectations, that the Company will not achieve a comparable level of hedging going forward in respect of its existing production, that the Company will not achieve the results anticipated by management from the Company's cost reduction measures, the risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production; delays or changes in plans with respect to exploration and development projects or capital expenditures; the uncertainty of reserve and resource estimates and projections relating to production, costs and expenses, and health, safety and environmental risks, including flooding and extended interruptions due to inclement or hazardous weather conditions), well shut-ins and the potential for damage to the affected wells, the risk of commodity price and foreign exchange rate fluctuations, risks and uncertainties associated with securing the necessary regulatory approvals and financing to proceed with continued development of the Tishomingo Field, the Company or its subsidiaries is not able for any reason to obtain and provide the information necessary to secure required approvals or that required regulatory approvals are otherwise not available when required, that unexpected geological results are encountered, that completion techniques require further optimization, that production rates do not match the Company's assumptions, that very low or no production rates are achieved, that the Company will cease to be in compliance with the covenants under its reserve-based loan facility and be required to repay outstanding amounts or that the borrowing base will be reduced pursuant to a borrowing base redetermination and the Company will be required to repay the resulting shortfall, that the Company is unable to access required capital, that occurrences such as those that are assumed will not occur, do in fact occur, and those conditions that are assumed will continue or improve, do not continue or improve and the other risks identified in the Company's most recent Annual Information Form under the "Risk Factors" section and the Company's other public disclosure, available under the Company's profile on SEDAR at www.sedar.com.
Although the Company has attempted to take into account important factors that could cause actual costs or results to differ materially, there may be other factors that cause actual results not to be as anticipated, estimated or intended. There can be no assurance that such statements will prove to be accurate as actual results and future events could differ materially from those anticipated in such statements. The forward-looking information included in this MD&A is expressly qualified in its entirety by this cautionary statement. Accordingly, readers should not place undue reliance on forward-looking information. The Company undertakes no obligation to update these forward-looking statements, other than as required by applicable law.
CORPORATE INFORMATION
DIRECTORS AND OFFICERS | AUDITORS |
KPMG LLP | |
David Neuhauser 1,2,3,5 | Calgary, AB |
Director, Chairman of the Board | |
BANKERS | |
Eric Brown 1,2,3,4,5 | Amegy Bank National Association |
Director | Denver, CO, USA |
Leslie O'Connor 1,2,3,4,5 | HSBC Bank Canada |
Director | Calgary, AB |
Wolf Regener 4 | BOK Financial |
Director, President and Chief Executive Officer | Tulsa, OK |
Gary Johnson | |
Chief Financial Officer and Vice President | CONSULTING ENGINEERS |
Netherland, Sewell & Associates, Inc. | |
1 Member of the Audit Committee | Houston, TX, USA |
2 Member of the Corporate Governance Committee | |
3 Member of the Compensation Committee | TRANSFER AGENT AND REGISTRAR |
4 Member of the HS&E Committee | Computershare Trust Company |
5 Member of the Reserves Committee | Calgary, AB |
STOCK EXCHANGE LISTING | HEAD OFFICE |
The Toronto Stock Exchange | Suite 207, 3623 Old Conejo Road |
Trading Symbol: KEI | Newbury Park, CA, USA 91320 |
(Over the Counter OTC) QB | Telephone: (805) 484-3613 |
Trading Symbol: KGEIF | Fax: (805) 484-9649 |
LEGAL COUNSEL | CANADIAN OFFICE |
DuMoulin Black LLP | 10th Floor, 595 Howe Street |
Vancouver, BC | Vancouver, BC, Canada V6C 2T5 |
Telephone (604) 687-1224 | |
Fax: (604) 687-3635 |