MANAGEMENT’S DISCUSSION AND ANALYSIS
For the Three and Six Months Ended June 30, 2018
Date of Report: August 9, 2018
INTRODUCTION
The Company was incorporated under the laws of Ontario, Canada, on March 29, 1968 under the name "Dejour Mines Limited". By articles of amendment dated October 30, 2001, the issued common shares were consolidated on the basis of one (1) new share for every fifteen (15) old shares and the name of the company was changed to Dejour Enterprises Ltd. On June 6, 2003, the shareholders approved a resolution to complete a one new share for three old share consolidation, which became effective on October 1, 2003. In 2005, the Company was continued into the province of British Columbia under theBusiness Corporations Act(British Columbia). On March 9, 2011, the Company changed its name from Dejour Enterprises Ltd. to Dejour Energy Inc. On October 27, 2015, the Company changed its name from Dejour Energy Inc. to DXI Energy Inc. and effected a five-to-one share consolidation of its common shares.
The head office of DXI Energy is located at 520 – 999 Canada Place, Vancouver, British Columbia, V6C 3E1, and its registered and records office is located at 25th Floor, 700 West Georgia Street, Vancouver, British Columbia, V7Y 1B3. The common shares of DXI Energy are listed for trading on the Toronto Stock Exchange (“TSX”) under the symbol of “DXI” in Canada and the OTCQB (“OTCQB”) under the symbol of “DXIEF” in the United States.
The following management’s discussion and analysis (“MD&A”) is dated August 9, 2018 and should be read in conjunction with the Company’s unaudited interim condensed consolidated financial statements and notes thereto for the three and six months ended June 30, 2018 and its audited consolidated financial statements and MD&A for the year ended December 31, 2017. Additional information relating to DXI Energy can be found on SEDAR atwww.sedar.com.
FORWARD-LOOKING STATEMENTS
This document contains expectations, beliefs, plans, goals, objectives, assumptions, information, and statements about future events, conditions, results of operations or performance that constitute “forward-looking information” or “forward-looking statements” (collectively, “forward-looking statements”) under applicable securities laws. Undue reliance should not be placed on forward-looking statements. Forward-looking statements are based on current expectations, estimates and projections that involve a number of risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements. We caution that the foregoing list of risks and uncertainties is not exhaustive. Events or circumstances could cause actual dates to differ materially from those estimated or projected and expressed in, or implied by, these forward-looking statements. The forward-looking statements contained in this document are made as of the date hereof and the Company does not intend, and does not assume any obligation, to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise unless expressly required by applicable securities laws.
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The information set out herein with respect to forecasted 2018 results is “financial outlook” within the meaning of applicable securities laws. The purpose of this financial outlook is to provide readers with disclosure regarding DXI Energy’s reasonable expectations as to the anticipated results of its proposed business activities for 2018. Readers are cautioned that this financial outlook may not be appropriate for other purposes.
NON-IFRS MEASURES
This document contains certain financial measures, as described below, which do not have standardized meanings prescribed by International Financial Reporting Standards (“IFRS”). As these measures are commonly used in the oil and gas industry, the Company believes that their inclusion is useful to investors. The reader is cautioned that these amounts may not be directly comparable to measures for other companies where similar terminology is used. “Operating Netback” is calculated by deducting royalties and operating and transportation expenses from gross oil and gas revenues. “Cash Flows from Operations” is calculated by adding back settlement of decommissioning liabilities and change in operating working capital to cash flows from operating activities. Operating netback and cash flows from operations are used by DXI Energy as key measures of performance and are not intended to represent operating profits nor should they be viewed as an alternative to income or loss or other measures of financial performance, cash flows from operating activities calculated in accordance with IFRS.
The following table reconciles cash flows from (used in) operating activities to cash flows from (used in) operations, a non-IFRS measure:
| | | Three months ended June 30 | | | Six months ended June 30 | |
| (CA$ thousands) | | 2018 | | | 2017 | | | 2018 | | | 2017 | |
| | | $ | | | $ | | | $ | | | $ | |
| Cash flows used in operating activities | | (393 | ) | | (82 | ) | | (405 | ) | | (242 | ) |
| Change in operating working capital | | (98 | ) | | (196 | ) | | (624 | ) | | (382 | ) |
| Cash flows used in operations | | (491 | ) | | (278 | ) | | (1,029 | ) | | (624 | ) |
Further, the Company discloses “Adjusted Working Capital Deficit”, a non-IFRS measure on page 11, in determining the Company’s “Total Capital” under “Liquidity and Capital Resources” section. “Adjusted Working Capital Deficit” reflects management’s estimate of working capital cash flows on a going concern basis and not necessarily those prescribed by IFRS.
OTHER MEASUREMENTS
All dollar amounts are referenced in Canadian dollars, except when noted otherwise. Some numbers in this MD&A have been rounded to the nearest thousand for discussion purposes. A Barrel of Oil Equivalent (“BOE”) is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.
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CHANGES IN ACCOUNTING STANDARDS
The Company has adopted the following new and revised standards, along with all consequential amendments, effective January 1, 2018.
IFRS 9, “Financial Instruments”: In July 2014, the IASB completed the final phase of its project to replace IAS 39, the current standard on the recognition and measurement of financial instruments. IFRS 9 is now the new standard which sets out the recognition and measurement requirements for financial instruments and some contracts to buy or sell non-financial items. IFRS 9 provides a single model of classifying and measuring financial assets and liabilities and provides for only two classification categories: amortized cost and fair value. Hedge accounting requirements have also been updated in the new standard and are now more aligned with the risk management activities of an entity. The Company adopted IFRS 9 on January 1, 2018 and has determined that there was no material impact on its consolidated financial statements as a result of the adoption.
IFRS 15, “Revenue from Contracts with Customers”: the standard was issued in May 2014 and amended in April 2016. IFRS 15 applies to contracts with customers, excluding, most notably, insurance and leasing contracts. IFRS 15 prescribes a framework in accounting for revenues from contracts within its scope, including (a) identifying the contract, (b) identify separate performance obligations in the contract, (c) determine the transaction price of the contract, (d) allocate the transaction price to the performance obligations and (e) recognize revenues when each performance obligation is satisfied. IFRS 15 also prescribes additional financial statement presentations and disclosures. The Company adopted IFRS 15 on January 1, 2018, under the modified retrospective method where the cumulative effect is recognized at the date of initial application. It has been concluded that the adoption of IFRS 15 had no material effect on the Company’s consolidated financial statements.
CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS
Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates and judgments on a regular basis. The emergence of new information and changed circumstances may result in actual results or changes to estimates that differ materially from current estimates. Significant judgments, estimates and assumptions made by management in these financial statements are outlined in note 4 of the December 31, 2017 annual financial statements. There have been no significant changes in the Company’s critical accounting estimates and judgments applied during the interim period ended June 30, 2018 relative to the most recent annual financial statements as at and for the year ended December 31, 2017.
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DISCLOSURE CONTROLS AND INTERNAL CONTROLS OVER FINANCIAL REPORTING
The Company has designed disclosure controls and procedures (“DCP”) to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. During the financial year end of the Company, the appropriate officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s disclosure controls and procedures and have concluded that the Company’s disclosure controls and procedures are effective as of June 30, 2018.
The Company has designed internal controls over financial reporting ("ICFR") to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. During the financial year end of the Company, the appropriate officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s internal controls over financial reporting and concluded that the Company’s internal controls over financial reporting are effective as of December 31, 2017. The Company is required to disclose herein any change in the Company's ICFR that occurred during the recent fiscal period that has materially affected, or is reasonably likely to materially affect, the Company’s ICFR.
No material changes in the Company's DCP and its ICFR were identified during the three months ended June 30, 2018 that have materially affected, or are reasonably likely to materially affect, the Company's internal controls over financial reporting.
WHISTLEBLOWER POLICY
Effective December 28, 2007, the Company’s Audit Committee adopted resolutions that authorized the establishment of procedures for complaints received regarding accounting, internal controls or auditing matters, and for a confidential, anonymous submission procedure for employees and consultants who have concerns regarding questionable accounting or auditing matters. The implementation of the whistleblower policy is in accordance with the new requirements pursuant to Multilateral Instrument 52-110 Audit Committees, national Policy 58-201 Corporate Governance Guidelines and National Instrument 58-101 Disclosure of Corporate Governance Practices.
GROWTH STRATEGY
The Company implements a full cycle exploration and development program and, at the same time, opportunistically seeks to acquire assets with exploitation potential. To complement this strategy, the Company has retained a team of experienced and qualified personnel to act quickly on new opportunities.
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RESULTS OF OPERATIONS
FINANCIAL AND OPERATING HIGHLIGHTS
During the three months ended June 30, 2018, the Company:
| 1. | Reduced G&A expenses by 16% to $335,000 from $398,000 for the comparative period ended June 30, 2017; |
| | |
| 2. | Reduced financing expenses by 24% to $226,000 from $298,000 for the comparative period ended June 30, 2017; and |
| | |
| 3. | Completed the integration of the new technical data secured from the b-B100E discovery well with the updated proprietary 3D model of the Company’s acreage. This information will help identify and best define the optimal future oil and gas targets at Woodrush. |
REVENUE
| Second quarter 2018 vs. Second Quarter 2017 | | Three Months Ended June 30 | | | | |
| (CA$ thousands, except as otherwise noted) | | 2018 | | | 2017 | | | % change | |
| Production Volumes: | | | | | | | | | |
| Oil and natural gas liquids (bbls/d) | | 56 | | | 77 | | | -27% | |
| Natural gas (mcf/d) | | 876 | | | 1,237 | | | -29% | |
| Total (BOE/d) | | 203 | | | 283 | | | -28% | |
| Average realized prices: | | | | | | | | | |
| Oil and natural gas liquids ($/bbl) | | 64.65 | | | 62.10 | | | 4% | |
| Natural gas ($/mcf) | | 1.74 | | | 3.29 | | | -47% | |
| Total ($/BOE) | | 25.56 | | | 31.25 | | | -18% | |
| Revenue, before royalties: | | | | | | | | | |
| Oil and natural gas liquids | | 332 | | | 436 | | | -24% | |
| Natural gas | | 140 | | | 370 | | | -62% | |
| Total | | 472 | | | 806 | | | -41% | |
For the three months ended June 30, 2018 (“Q2 2018”), total revenue, before royalties, decreased by $334,000 or 41%, due to a 28% decline in oil and natural gas production on a “BOE” basis together with the reduction in the combined average realized prices for the quarter.
During Q2 2018, oil production decreased to an average of 56 BOPD from 77 BOPD for the three months ended June 30, 2017. This 27% decrease reflects the natural decline in oil production and increase in water cut associated with Halfway formation waterfloods of the Woodrush type in northeastern British Columbia. The reduction in natural gas production for Q2 2018 is due to the natural decline in natural gas production at Kokopelli in Colorado.
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| Year-to-date 2018 vs. Year-to-date 2017 | | Six Months Ended June 30 | | | | |
| (CA$ thousands, except as otherwise noted) | | 2018 | | | 2017 | | | % change | |
| Production Volumes: | | | | | | | | | |
| Oil and natural gas liquids (bbls/d) | | 62 | | | 84 | | | -26% | |
| Natural gas (mcf/d) | | 923 | | | 1,401 | | | -34% | |
| Total (BOE/d) | | 216 | | | 318 | | | -32% | |
| Average realized prices: | | | | | | | | | |
| Oil and natural gas liquids ($/bbl) | | 62.59 | | | 60.06 | | | 4% | |
| Natural gas ($/mcf) | | 2.23 | | | 3.23 | | | -31% | |
| Total ($/BOE) | | 27.50 | | | 30.17 | | | -9% | |
| Revenue, before royalties: | | | | | | | | | |
| Oil and natural gas liquids | | 701 | | | 915 | | | -23% | |
| Natural gas | | 373 | | | 820 | | | -55% | |
| Total | | 1,074 | | | 1,735 | | | -38% | |
For the six months ended June 30, 2018, total revenue, before royalties, decreased by $661,000 or 38%, due to a 32% decline in oil and natural gas production on a “BOE” basis together with the reduction in the combined average realized prices.
During the six months ended June 30, 2018, oil production decreased to an average of 62 BOPD from 84 BOPD for the six months ended June 30, 2017. This 26% decrease reflects the natural decline in oil production and increase in water cut associated with Halfway formation waterfloods of the Woodrush type in northeastern British Columbia. The reduction in natural gas production for the six months ended June 30, 2018 is due to the natural decline in natural gas production at Kokopelli in Colorado.
OIL OPERATIONS
| | | Three months ended June 30 | | | Six months ended June 30 | |
| ($/bbl) | | 2018 | | | 2017 | | | % change | | | 2018 | | | 2017 | | | % change | |
| | | $ | | | $ | | | | | | $ | | | $ | | | | |
| Oil and NGL's revenue, realized price | | 64.65 | | | 62.10 | | | 4% | | | 62.59 | | | 60.06 | | | 4% | |
| Royalties | | (7.33 | ) | | (7.44 | ) | | -2% | | | (7.71 | ) | | (8.33 | ) | | -7% | |
| Operating and transportation expenses | | (41.43 | ) | | (25.41 | ) | | 63% | | | (38.19 | ) | | (22.00 | ) | | 74% | |
| Operating netback | | 15.89 | | | 29.25 | | | -46% | | | 16.69 | | | 29.73 | | | -44% | |
The average price received for oil sales increased by 4% for the three and six months ended June 30, 2018, relative to the corresponding periods of 2017. The increase in DXI Energy’s average realized oil price reflected the benchmark price recovery in Canada and the rest of the world.
Average oil royalties for the three and six months ended June 30, 2018 were lower, relative to the corresponding periods of 2017, due to lower royalty rates for lower oil production in the 1st half of 2018. Operating and transportation expenses for the three and six months ended June 30, 2018 were higher, relative to the corresponding periods of 2017, mainly due to the repairs and maintenance work performed at its Woodrush properties. In addition, the increase resulted in higher per unit costs as fixed operating costs were allocated over a lower oil production volume.
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NATURAL GAS OPERATIONS
| | | Three months ended June 30 | | | Six months ended June 30 | |
| ($/mcf) | | 2018 | | | 2017 | | | % change | | | 2018 | | | 2017 | | | % change | |
| | | $ | | | $ | | | | | | $ | | | $ | | | | |
| Gas revenue, realized price | | 1.74 | | | 3.29 | | | -47% | | | 2.23 | | | 3.23 | | | -31% | |
| Royalties | | (0.12 | ) | | (0.30 | ) | | -59% | | | (0.16 | ) | | (0.24 | ) | | -33% | |
| Operating and transportation expenses | | (3.32 | ) | | (2.56 | ) | | 30% | | | (3.61 | ) | | (2.94 | ) | | 23% | |
| Operating netback | | (1.70 | ) | | 0.43 | | | -497% | | | (1.54 | ) | | 0.05 | | | -3142% | |
| Barrel of oil equivalent netback ($/BOE) | | (10.17 | ) | | 2.56 | | | -497% | | | (9.23 | ) | | 0.30 | | | -3142% | |
The average price received for gas sales decreased by 47% and 31% for the three and six months ended June 30, 2018, relative to the corresponding periods of 2017. The reduction was primarily because of a surplus of gas in the Woodrush region due to pipeline restrictions.
Average oil royalties for the three and six months ended June 30, 2018 were lower, relative to the corresponding periods of 2017, due to lower average gas prices received in both periods.
Operating and transportation expenses for the three and six months ended June 30, 2018 were higher, relative to the corresponding periods of 2017, mainly due to certain fixed operating costs being allocated to reduced natural gas production volumes.
FINANCING EXPENSES
| | | Three months ended June 30 | | | Six months ended June 30 | |
| (CA$ thousands, except per BOE) | | 2018 | | | 2017 | | | % change | | | 2018 | | | 2017 | | | % change | |
| | | $ | | | $ | | | | | | $ | | | $ | | | | |
| Interest on short-term loan from related parties | | 25 | | | 33 | | | -24% | | | 50 | | | 60 | | | -17% | |
| Accretion of long-term loans from related parties | | 183 | | | 251 | | | -27% | | | 370 | | | 494 | | | -25% | |
| Other financing expenses | | 18 | | | 14 | | | 29% | | | 80 | | | 28 | | | 186% | |
| | | 226 | | | 298 | | | -24% | | | 500 | | | 582 | | | -14% | |
| Average debt outstanding | | 7,500 | | | 7,807 | | | -4% | | | 7,500 | | | 7,710 | | | -3% | |
| Average interest rate on debt | | 5.2% | | | 7.7% | | | -33% | | | 5.2% | | | 7.8% | | | -34% | |
| | | | | | | | | | | | | | | | | | | |
| Interest expense per BOE(1) | | 5.26 | | | 5.82 | | | -10% | | | 4.97 | | | 5.22 | | | -5% | |
(1) Interest expense used in the calculation of ``Interest expense per BOE`` includes interest on loans from related parties.
Accretion expense is the Financing Expense realized in the current period on the related party loan, which was issued with embedded financial instruments. In accordance with IFRS, the related party debt is measured using an estimated fair value of a similar loan with no financial instruments attached. The loan is accreted using the “implicit” interest rate (as distinct from the related debt instrument’s coupon rate) on the related party loan.
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Accretion expense for the three and six months ended June 30, 2018 was lower than the corresponding periods of 2017. The decrease was due to lower “implicit” interest rate on the related party loan for the periods.
GENERAL AND ADMINISTRATIVE (“G&A”) EXPENSES
| | | Three months ended June 30 | | | Six months ended June 30 | |
| (CA$ thousands, except per BOE) | | 2018 | | | 2017 | | | % change | | | 2018 | | | 2017 | | | % change | |
| | | $ | | | $ | | | | | | $ | | | $ | | | | |
| Salary and benefits | | 93 | | | 80 | | | 16% | | | 186 | | | 186 | | | 0% | |
| Other G&A expenses | | 248 | | | 325 | | | -24% | | | 544 | | | 634 | | | -14% | |
| Gross G&A expenses | | 341 | | | 405 | | | -16% | | | 730 | | | 820 | | | -11% | |
| Overhead recoveries | | (6 | ) | | (7 | ) | | -14% | | | (13 | ) | | (14 | ) | | -7% | |
| Total net G&A expenses | | 335 | | | 398 | | | -16% | | | 717 | | | 806 | | | -11% | |
| $ per BOE | | 18.17 | | | 15.45 | | | 18% | | | 18.37 | | | 14.02 | | | 31% | |
Lower G&A expenses for the three and six months ended June 30, 2018 was the result of the implementation of the Company’s overall cost savings plan. G&A expenses increased on a “per BOE” basis by 18% and 31% for the three and six months ended June 30, 2018 due to a decline in oil and natural gas production.
AMORTIZATION, DEPLETION AND IMPAIRMENT LOSSES
| | | Three months ended June 30 | | | Six months ended June 30 | |
| (CA$ thousands, except per BOE) | | 2018 | | | 2017 | | | % change | | | 2018 | | | 2017 | | | % change | |
| | | $ | | | $ | | | | | | $ | | | $ | | | | |
| Amortization and depletion | | 315 | | | 195 | | | 62% | | | 652 | | | 441 | | | 48% | |
| Impairment losses | | 2 | | | 350 | | | -99% | | | 2 | | | 1,282 | | | -100% | |
| Total amortization, depletion and impairment losses | | 317 | | | 545 | | | -42% | | | 654 | | | 1,723 | | | -62% | |
| $ per BOE | | 17.20 | | | 21.15 | | | -19% | | | 16.75 | | | 29.97 | | | -44% | |
The increase in amortization and depletion for the three and six months ended June 30, 2018 was primarily due to the capital expenditures incurred for the newly drilled natural gas well at Woodrush. This was offset by lower oil and gas production for both periods.
During the six months ended June 30, 2017, the Company recorded an impairment of $370,000 on its oil and gas properties in British Columbia, Canada and $350,000 on one of its exploration and evaluation assets in Alberta, Canada. The impairment was recognized based on the difference between the carrying value of the assets and their recoverable amount. Additionally, the Company recorded an impairment of $562,000 on its exploration and evaluation assets in the U.S. because the carrying value of some assets exceeded their recoverable amount.
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LOSS FOR THE PERIOD
| | | Three months ended June 30 | | | Six months ended June 30 | |
| (CA$ thousands, except per share amounts and BOE) | | 2018 | | | 2017 | | | % change | | | 2018 | | | 2017 | | | % change | |
| | | $ | | | $ | | | | | | $ | | | $ | | | | |
| Income (loss) | | (1,086 | ) | | (1,621 | ) | | -33% | | | (2,268 | ) | | (3,171 | ) | | -28% | |
| $ per common share, basic | | (0.01 | ) | | (0.04 | ) | | -71% | | | (0.02 | ) | | (0.07 | ) | | -69% | |
| $ per common share, fully diluted | | (0.01 | ) | | (0.04 | ) | | -71% | | | (0.02 | ) | | (0.07 | ) | | -69% | |
| $ per BOE | | (58.91 | ) | | (62.91 | ) | | -6% | | | (58.10 | ) | | (55.16 | ) | | 5% | |
The 33% and 28% decrease in the loss for the three and six months ended June 30, 2018 was primarily due to lower amortization, depletion and impairment loss and the recognition of loss on debt extinguishment of $918,000 in June 2017. This was partially offset by lower net revenues.
CASH FLOWS FROM OPERATIONS
| | | Three months ended June 30 | | | Six months ended June 30 | |
| (CA$ thousands, except per share amounts and BOE) | | 2018 | | | 2017 | | | % change | | | 2018 | | | 2017 | | | % change | |
| | | $ | | | $ | | | | | | $ | | | $ | | | | |
| Cash flows used in operations | | (491 | ) | | (278 | ) | | 77% | | | (1,029 | ) | | (624 | ) | | 65% | |
| $ per common share, basic | | (0.00 | ) | | (0.01 | ) | | -100% | | | (0.01 | ) | | (0.01 | ) | | 0% | |
| $ per common share, fully diluted | | (0.00 | ) | | (0.01 | ) | | -100% | | | (0.01 | ) | | (0.01 | ) | | 0% | |
| $ per BOE | | (26.64 | ) | | (10.79 | ) | | 147% | | | (26.36 | ) | | (10.85 | ) | | 143% | |
During the three and six months ended June 30, 2018, the increase in excess funds used in operations is primarily related to the reduction in oil and natural gas revenues in 2018 caused by the decline in oil and gas production.
Cash flows from operations is impacted by production, prices received, royalties paid, operating and transportation expenses and general and administrative expenses.
CAPITAL EXPENDITURES
DXI Energy is committed to future growth through its strategy to implement a full-cycle exploration and development program, augmented by strategic acquisitions with exploitation upside.
Additions to property and equipment and exploration and evaluation assets:
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| | | Six months ended June 30, 2018 | | | Six months ended June 30, 2017 | | | | |
| (CA$ thousands) | | $ | | | % of total | | | $ | | | % of total | | | % change | |
| | | | | | | | | | | | | | | | |
| Land acquisition and retention | | 21 | | | 3.0% | | | 26 | | | 16.0% | | | -19% | |
| Drilling and completion | | 621 | | | 89.5% | | | 39 | | | 23.9% | | | 100% | |
| Geological and geophysical | | 44 | | | 6.3% | | | 88 | | | 54.0% | | | 100% | |
| Capitalized general and administrative | | 8 | | | 1.2% | | | 10 | | | 6.1% | | | -20% | |
| Total | | 694 | | | 100.0% | | | 163 | | | 100.0% | | | 326% | |
LIQUIDITY AND CAPITAL RESOURCES
DXI Energy manages its capital structure to support current and future business plans and periodically adjusts the structure in response to changes in economic conditions and the risk characteristics of its underlying assets and operations. DXI Energy may adjust its capital structure by issuing shares, altering debt levels, modifying capital programs, acquiring or disposing of assets or participating in joint ventures.
| | | June 30, 2018 | | | December 31, 2017 | | | | |
| (CA$ thousands) | | $ | | | $ | | | % change | |
| Adjusted working capital deficit(1) | | 5,538 | | | 3,628 | | | 53% | |
| Loans from related parties (face value) | | 7,500 | | | 7,500 | | | 0% | |
| Non-cash portion of financial contract liability | | 3,137 | | | 2,988 | | | 5% | |
| Net debt(2) | | 16,175 | | | 14,116 | | | | |
| Share capital | | 101,715 | | | 101,715 | | | 0% | |
| Contributed surplus and accumulated other comprehensive income | | 16,971 | | | 16,224 | | | 5% | |
| Deficit | | (118,113 | ) | | (115,845 | ) | | 2% | |
| Total Capital | | 16,748 | | | 16,210 | | | | |
| (1) | Accounts payable and accrued liabilities and cash portion of financial contract liability less cash and cash equivalents, accounts receivable, and prepaids and deposits |
| | |
| (2) | Excludes decommissioning liability |
Adjusted Working Capital
| | | June 30, 2018 | | | December 31, 2017 | |
| (CA$ thousands) | | $ | | | $ | |
| Working capital deficit | | (10,174 | ) | | (8,167 | ) |
| Non-cash flow through share liability | | - | | | 93 | |
| Adjusted working capital deficit | | (10,174 | ) | | (8,074 | ) |
| Add: current portion of loans from related parties | | 1,499 | | | 1,458 | |
| Add: non-cash portion of financial contract liability | | 3,137 | | | 2,988 | |
| Adjusted working capital deficit (excluding loans from related parties and financial contract liability) | | (5,538 | ) | | (3,628 | ) |
The adjusted working capital deficit at June 30, 2018 includes $158,000 of cash and cash equivalents, $242,000 of accounts receivable, $8,000 of prepaids and deposits, $2.0 million of accounts payable and accrued liabilities, and $3.9 million of financial contract liability.
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DXI Energy expects to fund operations and capital expenditures with cash flows from operations, existing cash and cash equivalents and by accessing the capital markets, as required.
Going Concern, Financial Contract Liability and Loans from Related Parties
The financial statements were prepared on a going concern basis. The going concern basis 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.
The Company has a working capital deficiency of $10.2 million. The Company also has an accumulated deficit of $118.1 million. Of this amount, $7.1 million is represented by a financial contract liability of Dejour USA, which was due on September 30, 2016. The current status of this instrument is described in the section entitled “Financial Contract Liability”, below.
On March 12, 2015, as amended on May 6, 2015, June 22, 2015, September 28, 2015, November 18, 2015 and June 5, 2017, the Company issued a promissory note for $4.5 million to Hodgkinson Equities Corp. (“HEC”), a private company controlled by the CEO of the Company. The promissory note is secured by all assets of Dejour USA and a negative pledge by the Company not to further encumber its Canadian oil and gas properties without HEC’s prior approval. The principal and interest at Canadian prime rate plus 5% per annum was repayable by the earlier of (i) within 10 business days of receipt of written demand from HEC for the repayment and (ii) June 10, 2015 or such later date to which the term of the promissory note may be extended. On May 6, 2015, the due date of the loan was extended to September 30, 2015. On September 28, 2015, the due date of the loan was further extended to December 31, 2015. On November 18, 2015, the Company extended the due date of the loan from December 31, 2015 to November 30, 2018. Additionally, a monthly principal repayment of $114,230.77 is due on the 1st day of each month commencing June 1, 2016. HEC agreed to waive the requirement of the Company to repay the total monthly principal repayments of $1,371,000 until the loan was restructured on June 5, 2017. In consideration for the extension, the Company issued HEC 9,000,000 Warrants. Each Warrant entitles the holder to acquire one common share at a price of C$0.45/US$ 0.35 per share any time prior to December 4, 2020. Shares acquired through the exercise of Warrants prior to April 5, 2016 were restricted from sale through the facilities of the stock exchanges. On February 19, 2016, the Company rescinded the negative pledge security agreement and issued a first mortgage in favour of HEC on its Canadian oil and gas properties. The first mortgage security so issued ranked “pari passu” with HVI’s first mortgage security interest. On June 5, 2017, the Company restructured the term of the loan with extension of the due date from November 30, 2018 to June 5, 2022; reduction of the interest rate to Canadian prime rate plus 1% per annum; and the right to convert the entire outstanding amount into 58,441,558 common shares of the Company at a price of $0.077 per share. In exchange for the modification, HEC agreed to cancel the 9,000,000 warrants described above. Upon an event of default, all the indebtedness under the promissory note become due and payable and the interest rate is immediately increased to the Canadian prime rate plus 4.5% per annum.
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On April 2, 2018, HEC has agreed to assume the loan of $1,000,000 from a director and officer of the Company and his spouse. The loan bears interest at 10% per annum and is secured with a 2nd mortgage on DEAL’s oil and gas properties of $1,000,000. The principal and interest accrued on the loan were repayable on or before June 30, 2019.
On June 22, 2015, as amended on September 28, 2015, November 18, 2015 and June 5, 2017, the Company issued a promissory note for $2.0 million to Hodgkinson Ventures Inc. (“HVI”), a private company associated with the CEO of the Company, on a “pari passu” basis with the loan from HEC. The promissory note is secured by all assets of Dejour USA and a negative pledge by the Company not to further encumber its Canadian oil and gas properties without HVI’s prior approval. The principal and interest at Canadian prime rate plus 5% per annum was repayable on or before September 30, 2015. On September 28, 2015, the due date of the loan was extended to December 31, 2015. On November 18, 2015, the Company extended the due date of the loan from December 31, 2015 to November 30, 2018. Additionally, a monthly principal repayment of $50,769.23 is due on the 1st day of each month commencing June 1, 2016. HVI agreed to waive the requirement of the Company to repay the total monthly principal repayments of $660,000 until the loan was restructured on June 5, 2017. In consideration for the extension, the Company issued HVI 4,000,000 Warrants. Each Warrant entitles the holder to acquire one common share at a price of C$0.45/US$ 0.35 per share any time prior to December 4, 2020. Shares acquired through the exercise of Warrants prior to April 5, 2016 were restricted from sale through the facilities of the stock exchanges. On February 19, 2016, the Company rescinded the negative pledge security agreement and issued a first mortgage in favour of HVI on its Canadian oil and gas properties. The first mortgage security so issued ranked “pari passu” with HEC’s first mortgage security interest. On June 5, 2017, the Company restructured the term of the loan with extension of the due date from November 30, 2018 to June 5, 2022; reduction of the interest rate to Canadian prime rate plus 1% per annum; and the right to convert the entire outstanding amount into 25,974,025 common shares of the Company at a price of $0.077 per share. In exchange for the modification, HVI agreed to cancel the 4,000,000 warrants described above. Upon an event of default, all the indebtedness under the promissory note become due and payable and the interest rate is immediately increased to the Canadian prime rate plus 4.5% per annum.
On July 10, 2018, Hodgkinson Equities Corporation (“HEC”) and Hodgkinson Ventures Inc. (“HVI”) each signed a Waiver of Deferred Payment of Borrowings (“Waiver”) to the Company to defer and extend payment of all interest amounts owing in respect of the secured promissory notes through to and inclusive of September 30, 2018. The amounts owing at September 30, 2018 will be approximately $118,000. The Waiver does not amend the due date of the HEC and HVI loans. Accordingly, no loan principal payments are in default.
On July 10, 2018, HEC and HVI also advised the Company they would no longer provide any significant additional capital to enable the Company to meet ongoing operating and general and administrative expenses.
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The Company’s ability to continue as a going concern is dependent upon attaining profitable operations and sourcing additional equity and debt capital from financiers, other than the present non-arm’s length lenders to the Company, to provide the Company with sufficient capital to meet capital expenditure commitments and continue exploration and development activities. The present non-arm’s length lenders to the Company have informed the Company they will not provide any significant additional capital to the Company. There is no assurance that future financing and exploration and development activities will be successful. These material uncertainties cast substantial doubt upon the Company’s ability to continue as a going concern. These consolidated financial statements do not reflect the adjustments to the carrying values of assets and liabilities, the reported revenues and expenses, and the balance sheet classifications used that would be necessary if the going concern assumptions were not appropriate.
Financial Contract Liability
On December 31, 2012, Dejour USA entered into a financial contract with a U.S. oil and gas drilling fund (“Drilling Fund”) to fund the drilling of up to three wells and the completion of up to four wells in the State of Colorado. The total amount contributed by the Drilling Fund was US$7,000,000.
The financial contract contains a provision whereby Dejour USA must purchase the Drilling Funds’ working interest in the four wells funded by the US$7,000,000 if the Drilling Fund fails to obtain a certain minimum return on investment by September 30, 2016. A subsequent amendment limited Dejour USA’s cash exposure to a potential “put” by the Drilling Fund to US$3,000,000, with the difference to be settled by an assignment of working interests in certain P&NG properties owned by Dejour USA. The Company is not a party to the financial contract.
On September 30, 2016, the Drilling Fund served notice to Dejour USA requiring Dejour USA to purchase the Drilling Funds’ working interest in the 4 wellbores in accordance with the contract. However, prior to serving such notice, the Drilling Fund executed certain assignments transferring ownership of its working interests in the 4 wellbores to another entity and the assignee mortgaged its interest therein. Dejour USA and its attorneys are reviewing the impact of the Drilling Fund’s actions on the validity of the financial contract between the parties.
As at June 30, 2018, Dejour USA has recorded a liability owing to the Drilling Fund of $7,087,000, as follows:
| (CA$ thousands) | | $ | |
| Balance at January 1, 2017 (US$5,382) | | 7,226 | |
| Foreign exchange gain | | (474 | ) |
| Balance at December 31, 2017 (US$5,382) | | 6,752 | |
| Foreign exchange loss | | 335 | |
| Balance at June 30, 2018 (US$5,382) | | 7,087 | |
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This amount, if any, is subject to a resolution of the financial contract between the parties. Dejour USA has received no formal communication from the Drilling Fund since the “put” notice date of September 30, 2016.
Capital Resources
In December 2017, the Company signed a “Funding and Participation Agreement” (“the Agreement”) with a private U.S. based investment firm to underwrite 50% of the capital costs of at least one exploration well at its Woodrush properties in Canada. Under the terms of the Agreement, the investment firm will pay approximately two-thirds of the total costs of the 1st well of the 2018 program, through tie in, to earn a 15% Gross Overriding Royalty (“GORR”). In March 2018, the Company successfully drilled the 1st discovery natural gas well at Woodrush jointly with the investment firm.
The investment firm has the right to elect to participate in the drilling and completion of a 2nd and subsequent wells, if any, by paying 50% of the capital costs to earn a 15% GORR in the well spacing unit on a well-by-well basis.
In United States, the Company and its partners intend to continue to develop the Kokopelli project when natural gas and natural gas liquids prices paid to producers return to acceptable levels.
CONTRACTUAL OBLIGATIONS
As of June 30, 2018, the Company has obligations to make future payments, representing contracts and other commitments that are known and committed.
| (CA$ thousands) | | 2018 | | | 2019 | | | 2020 | | | 2021 | | | 2022 | | | Thereafter | | | Total | |
| | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | | | $ | |
| Trade and other payables | | 1,996 | | | - | | | - | | | - | | | - | | | Nil | | | 1,996 | |
| Debt repayments(1) | | - | | | 1,000 | | | - | | | - | | | 6,500 | | | Nil | | | 7,500 | |
| Interest payments(2) | | 50 | | | 50 | | | - | | | - | | | - | | | Nil | | | 100 | |
| Operating lease obligations | | 44 | | | 75 | | | 17 | | | - | | | - | | | Nil | | | 136 | |
| Financial contract liability(3) | | 7,087 | | | - | | | - | | | - | | | - | | | Nil | | | 7,087 | |
| Total | | 9,177 | | | 1,125 | | | 17 | | | - | | | 6,500 | | | Nil | | | 16,819 | |
| (1) | Short-term and long-term loans from related parties |
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| (2) | Fixed interest payments on loan from related parties of $1,000,000. Interest payments tied to prime bank rate on the loan of $6,500,000 are excluded from this analysis. |
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| (3) | This represents the Company’s obligations over the 36-month put option period until it expires. See Note 9 to the consolidated financial statements for details. |
RELATED PARTY TRANSACTIONS
During the six months ended June 30, 2018 and 2017, the Company entered into the following transactions with related parties:
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| (a) | Compensation awarded to key management included a total of salaries and consulting fees of $235,000 (2017 - $232,000) and non-cash stock-based compensation of $77,000 (2017 - $Nil). Key management includes the Company’s officers and directors. The salaries and consulting fees are included in general and administrative expenses. Included in accounts payable and accrued liabilities at June 30, 2018 is $306,000 (December 31, 2017 - $131,000) owing to the two officers of the Company. |
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| (b) | Interest expenses of $192,000 (2017 - $180,000) related to the loans from related parties were paid in cash to the CEO of the Company and his spouse or the companies controlled by or associated with the CEO of the Company. And, interest expenses of $Nil (2017 - $139,000) related to the loans from related parties were paid via issuance of the Company’s shares to the companies controlled by or associated with the CEO of the Company. |
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| (c) | In 2015, the Company entered into loan agreements with a director and officer of the Company and his spouse and the private companies associated with the director and officer of the Company. The terms and conditions of these agreements are described in the section “Going Concern, Financial Contract Liability and Loans from Related Parties” above. |
OFF-BALANCE SHEET ARRANGEMENTS
The Company has no material undisclosed off-balance sheet arrangements that have or are reasonably likely to have, a current or future effect on our results of operations or financial condition at June 30, 2018.
SUMMARY OF QUARTERLY RESULTS
The following table summarizes key financial and operating information by quarter for the past eight quarters ending June 30, 2018:
| (CA$ thousands, except per unit amounts) | | 2018 Q2 | | | 2018 Q1 | | | 2017 Q4 | | | 2017 Q3 | | | 2017 Q2 | | | 2017 Q1 | | | 2016 Q4 | | | 2016 Q3 | |
| Gross oil and gas revenues | | 472 | | | 602 | | | 589 | | | 492 | | | 806 | | | 929 | | | 954 | | | 1,009 | |
| Net income (loss) | | (1,086 | ) | | (1,182 | ) | | (1,286 | ) | | (753 | ) | | (1,621 | ) | | (1,550 | ) | | (2,366 | ) | | (957 | ) |
| Per share - basic ($/common share) | | (0.01 | ) | | (0.01 | ) | | (0.01 | ) | | (0.01 | ) | | (0.04 | ) | | (0.03 | ) | | (0.05 | ) | | (0.02 | ) |
| Per share - fully diluted ($/common share) | | (0.01 | ) | | (0.01 | ) | | (0.01 | ) | | (0.01 | ) | | (0.04 | ) | | (0.03 | ) | | (0.05 | ) | | (0.02 | ) |
| Total assets | | 18,457 | | | 19,024 | | | 18,809 | | | 18,323 | | | 19,060 | | | 20,018 | | | 21,260 | | | 22,770 | |
| Average production (BOE/d) | | 203 | | | 229 | | | 228 | | | 230 | | | 283 | | | 352 | | | 327 | | | 385 | |
| Average realized price ($/BOE) | | 25.56 | | | 29.24 | | | 28.04 | | | 23.33 | | | 31.25 | | | 29.30 | | | 31.90 | | | 28.38 | |
| Operating netback ($/BOE) | | (2.99 | ) | | (0.74 | ) | | (4.40 | ) | | 1.12 | | | 9.80 | | | 6.71 | | | 7.60 | | | 7.86 | |
| Netback as a percentage of sales | | -12% | | | -3% | | | -16% | | | 5% | | | 31% | | | 23% | | | 24% | | | 28% | |
The fluctuations in DXI Energy’s revenue and income (loss) from quarter to quarter are primarily caused by variations in production volumes, realized oil and natural gas prices and the related impact on royalties and operating and transportation expenses. Please refer to the Results of Operations section of this MD&A for detailed discussion of changes from the 2nd quarter of 2018 to the 2nd quarter of 2017, and to the Company’s previously issued interim and annual MD&A for changes in prior quarters.
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BUSINESS RISKS
DXI Energy’s exploration and production activities are concentrated in the Northeastern B.C. portion of the competitive Western Canadian Sedimentary Basin and the Piceance Basin of Central United States, where activity is highly competitive and includes a variety of different sized companies ranging from smaller junior producers and intermediate and senior producers to the much larger integrated petroleum companies. DXI Energy is subject to a number of risks which are also common to other organizations involved in the oil and gas industry. Such risks include finding and developing oil and gas reserves at economic costs, estimating amounts of recoverable reserves, production of oil and gas in commercial quantities, marketability of oil and gas produced, fluctuations in commodity prices, financial and liquidity risks and environmental and safety risks.
In order to reduce exploration risk, DXI Energy employs highly qualified and motivated professional employees who have demonstrated the ability to generate quality proprietary geological and geophysical prospects. To maximize drilling success, DXI Energy explores in areas that afford multi-zone prospect potential, targeting a range of shallower low to moderate risk prospects with some exposure to select deeper high-risk prospects with high-reward opportunities.
DXI Energy has retained an independent engineering consulting firm that assists the Company in evaluating recoverable amounts of oil and gas reserves. Values of recoverable reserves are based on a number of variable factors and assumptions such as commodity prices, projected production, future production costs and government regulation. Such estimates may vary from actual results.
The Company mitigates its risk related to producing hydrocarbons through the utilization of the most advanced technology and information systems. In addition, DXI Energy strives to operate the majority of its prospects, thereby maintaining operational control. The Company does rely on its partners in jointly owned properties that DXI Energy does not operate.
DXI Energy is exposed to market risk to the extent that the demand for oil and gas produced by the Company exists within Canada and the United States. External factors beyond the Company’s control may affect the marketability of oil and gas produced. These factors include commodity prices and variations in the Canada-United States currency exchange rate, which in turn respond to economic and political circumstances throughout the world. Oil prices are affected by worldwide supply and demand fundamentals while natural gas prices are affected by North American supply and demand fundamentals. DXI Energy may periodically use futures and options contracts to hedge its exposure against the potential adverse impact of commodity price volatility.
Exploration and production for oil and gas is very capital intensive. As a result, the Company relies on equity markets as a source of new capital. In addition, DXI Energy utilizes bank financing to support ongoing capital investment. Funds from operations also provide DXI Energy with capital required to grow its business. Equity and debt capital is subject to market conditions and availability may increase or decrease from time to time. Funds from operations also fluctuate with changing commodity prices.
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SAFETY AND ENVIRONMENT
Oil and gas exploration and production can involve environmental risks such as pollution of the environment and destruction of natural habitat, as well as safety risks such as personal injury. The Company conducts its operations with high standards in order to protect the environment and the general public. DXI Energy maintains current insurance coverage for comprehensive and general liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect current corporate requirements, as well as industry standards and government regulations.
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