ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is managements assessment of the current and historical financial and operating results of the Company and of our financial condition. It is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our unaudited financial statements and notes thereto included elsewhere in this Quarterly Report on Form 10-Q for the nine months ended November 30, 2018 and in our Annual Report on Form 10-K for the year ended February 28, 2018. References to Daybreak, the Company, we, us or our mean Daybreak Oil and Gas, Inc.
Cautionary Statement Regarding Forward-Looking Statements
Certain statements contained in our Managements Discussion and Analysis
of Financial Condition and Results of Operations (MD&A) are intended to be covered by the safe harbor provided for under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act.
All statements other than statements of historical fact contained in this MD&A report are inherently uncertain and are forward-looking statements. Statements that relate to results or developments that we anticipate will or may occur in the future are not statements of historical fact. Words such as anticipate, believe, could, estimate, expect, intend, may, plan, predict, project, will and similar expressions identify forward-looking statements. Examples of forward-looking statements include, without limitation, statements about the following:
·
Our future operating results;
·
Our future capital expenditures;
·
Our future financing;
·
Our expansion and growth of operations; and
·
Our future investments in and acquisitions of crude oil and natural gas properties.
We have based these forward-looking statements on assumptions and analyses made in light of our experience and our perception of historical trends, current conditions, and expected future developments. However, you should be aware that these forward-looking statements are only our predictions and we cannot guarantee any such outcomes. Future events and actual results may differ materially from the results set forth in or implied in the forward-looking statements. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:
·
General economic and business conditions;
·
Exposure to market risks in our financial instruments;
·
Fluctuations in worldwide prices and demand for crude oil and natural gas;
·
Our ability to find, acquire and develop crude oil and natural gas properties;
·
Fluctuations in the levels of our crude oil and natural gas exploration and development activities;
·
Risks associated with crude oil and natural gas exploration and development activities;
·
Competition for raw materials and customers in the crude oil and natural gas industry;
·
Technological changes and developments in the crude oil and natural gas industry;
·
Legislative and regulatory uncertainties, including proposed changes to federal tax law and climate change legislation, regulation of hydraulic fracturing and potential environmental liabilities;
·
Our ability to continue as a going concern;
·
Our ability to secure financing under any commitments as well as additional capital to fund operations; and
·
Other factors discussed elsewhere in this Form 10-Q; in our other public filings and press releases; and discussions with Company management.
Our reserve estimates are determined through a subjective process and are subject to revision.
Should one or more of the risks or uncertainties described above or elsewhere in our Form 10-K for the year ended February 28, 2018 and in this Form 10-Q for the nine months ended November 30, 2018 occur, or should any underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically undertake no obligation to publicly update or revise any information contained in any forward-looking statement or any forward-looking statement in its entirety, whether as a result of new information, future events, or otherwise, except as required by law.
All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
16
Introduction and Overview
We are an independent crude oil and natural gas exploration, development and production company. Our basic business model is to increase shareholder value by finding and developing crude oil and natural gas reserves through exploration and development activities, and selling the production from those reserves at a profit. To be successful, we must, over time, be able to find crude oil and natural gas reserves and then sell the resulting production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment. A secondary means of generating returns can include the sale of either producing or non-producing lease properties.
Our longer-term success depends on, among many other factors, the acquisition and drilling of commercial grade crude oil and natural gas properties and on the prevailing sales prices for crude oil and natural gas along with associated operating expenses. The volatile nature of the energy markets makes it difficult to estimate future prices of crude oil and natural gas; however, any prolonged period of depressed prices or market volatility, would have a material adverse effect on our results of operations and financial condition.
Our operations are focused on identifying and evaluating prospective crude oil and natural gas properties and funding projects that we believe have the potential to produce crude oil or natural gas in commercial quantities. We conduct all of our drilling, exploration and production activities in the United States, and all of our revenues are derived from sales to customers within the United States. Currently, we are in the process of developing a multi-well oilfield project in Kern County, California and an
exploratory joint drilling project in Michigan.
On December 27, 2018, the Company paid Maximilian $700,000 to finalize a settlement of outstanding indebtedness through its credit facility and Michigan debt in the amount of approximately $12.6 million. The Company also acquired an additional 40% working interest in the Daybreaks Michigan Project along with a note receivable from its Michigan Project Partner. Daybreak now owns a 70% working interest in its Michigan Project. Furthermore, all liens and security interests granted to Maximilian with respect to the Companys leases in California and Michigan have been terminated and released. The effects of this transaction will be reflected on the Companys financial statements at February 28, 2019. The $700,000 paid to Maximilian was obtained from private investors (of which $300,000 was from a related party) by selling a Production Payment from future wells to be drilled in California and Michigan. The Company intends to raise an additional $600,000 to drill new wells in California and Michigan.
Our management cannot provide any assurances that Daybreak will ever operate profitably. We have not been able to generate sustained positive earnings on a Company-wide basis. As a small company, we are more susceptible to the numerous business, investment and industry risks that have been described in Item 1A. Risk Factors of our Annual Report on Form 10-K for the fiscal year ended February 28, 2018 and in Part III, Item 1A. Risk Factors of this 10-Q Report. Throughout this Quarterly Report on Form 10-Q, crude oil is shown in barrels (Bbls); natural gas is shown in thousands of cubic feet (Mcf) unless otherwise specified, and hydrocarbon totals are expressed in barrels of crude oil equivalent (BOE).
Below is brief summary of our crude oil projects in California and Michigan. Refer to our discussion in Item 2. Properties, in our Annual Report on Form 10-K for the year ended February 28, 2018 for more information on our California project and exploratory joint drilling project in Michigan.
Kern County, California (East Slopes Project)
The East Slopes Project is located in the southeastern part of the San Joaquin Basin near Bakersfield, California. Drilling targets are porous and permeable sandstone reservoirs that exist at depths of 1,200 feet to 4,500 feet. Since January 2009, we have participated in the drilling of 25 wells in this project. We have been the Operator at the East Slopes Project since March 2009.
The crude oil produced from our acreage in the Vedder Sand is considered heavy oil. The gravity of the crude oil ranges from 14
°
to 16
°
API (American Petroleum Institute) gravity and must be heated to separate and remove water prior to sale. Our crude oil wells in the East Slopes Project produce from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek locations. The Sunday property has six producing wells, while the Bear property has nine producing wells. The Black property is the smallest of all currently producing reservoirs, and currently has two producing wells at this property. The Ball property also has two producing wells while the Dyer Creek property has one producing well.
During the nine months ended November 30, 2018 we had production from 20 vertical crude oil wells. Our average working interest and net revenue interest (NRI) in these 20 wells is 36.6% and 28.4%, respectively.
17
We plan on acquiring additional acreage on trend with the Bear, Black and Dyer Creek reservoirs exhibiting the same seismic characteristics. Some of these prospects, if successful, would utilize the Companys existing production facilities. In addition to the current field development, there are several other exploratory prospects that have been identified from the seismic data, which we plan to drill in the future.
California Drilling Plans
Planned drilling activity and implementation of our oilfield development plan will not begin until there is a sustained improvement in crude oil prices and additional financing is put in place. We plan to spend approximately $300,000 in new capital investments within the East Slopes Project area in the 2019 calendar year if new financing is in place. Each new development well has a Daybreak net cost of $150,000.
Michigan Acreage Acquisition
In January 2017, Daybreak acquired a 30% working interest in 1,400 acres in the Michigan Basin where we have two shallow crude oil prospects. The leases have been secured and multiple targets have been identified through a 2-D seismic interpretation. A 3-D seismic survey was obtained in January and February of 2017. An analysis of the seismic survey confirmed the prospect identified on the 2-D seismic, as well as identified several additional drilling locations. We will obtain an additional 3-D survey to better delineate the other locations before a drilling program commences. The wells will be drilled vertically with conventional completions and no hydraulic fracturing will be required. The first well is expected to be drilled during the spring of 2019. In the meantime, we continue to maintain our lease position by paying lease rentals and renewing expiring leases.
Encumbrances
The Companys debt obligations, pursuant to a credit facility loan agreement and promissory notes entered into by and between Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC, a Delaware limited liability company, as lender, (
either party, as appropriate, is referred to in this Quarterly Report on Form 10-Q as Maximilian), and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and two mortgages; one covering our leases in California and the other covering our leases in Michigan. For further information on the credit facility loan agreements and promissory note with Maximilian refer to the discussion under the caption Current debt (Short-term borrowings) in the MD&A portion of this Quarterly report on Form 10-Q.
Results of Operations Nine months ended November 30, 2018 compared to the nine months ended November 30, 2017
California Crude Oil Prices
The price we receive for crude oil sales in California is based on prices posted for Midway-Sunset crude oil delivery contracts, less deductions that vary by grade of crude oil sold and transportation costs. The posted Midway-Sunset price generally moves in correlation to, and at a discount to, prices quoted on the New York Mercantile Exchange (NYMEX) for spot West Texas Intermediate (WTI) Cushing, Oklahoma delivery contracts.
Effective June 1, 2017, we were able to negotiate with our crude oil purchaser the use of a more favorable crude oil pricing schedule. We do not have any natural gas revenues in California.
There has been a significant amount of volatility in crude oil prices and a dramatic decline in our realized sale price of crude oil since June of 2014, when the monthly average price of WTI crude oil was $105.79 per barrel and our realized price per barrel of crude oil was $98.78. This decline in the price of crude oil has had a substantial negative impact on our cash flow from our producing California properties. While there has been an overall improvement in crude oil prices for the nine months ended November 30, 2018 in comparison to the nine months ended November 30, 2017, there is no guarantee that this trend will continue. Most recently the monthly average WTI price of oil has declined from $70.75 in October of 2018 to $56.96 in November 2018 representing the continued volatility in crude oil prices. It is beyond our ability to accurately predict how long crude oil prices will continue to remain at these lower price levels; when or at what level they may begin to stabilize; or when they may rebound to 2014 levels, as there are many factors beyond our control that dictate the price we receive on our crude oil sales.
A comparison of the average WTI price and average realized crude oil sales price at our East Slopes Project in California for the nine months ended November 30, 2018 and 2017 is shown in the table below:
|
|
|
|
|
|
|
| |
|
|
Nine Months Ended
|
|
|
|
|
November 30, 2018
|
|
November 30, 2017
|
|
Percentage Change
|
Average nine month WTI crude oil price (Bbl)
|
|
$
|
67.09
|
|
$
|
49.64
|
|
35.2%
|
Average nine month realized crude oil sales price (Bbl)
|
|
$
|
67.83
|
|
$
|
45.38
|
|
49.5%
|
18
For the nine months ended November 30, 2018, the average WTI price was $67.09 and our average realized crude oil sale price was $67.83, representing a premium of $0.74 per barrel or 1.1% higher than the average WTI price. In comparison, for the nine months ended November 30, 2017, the average WTI price was $49.64 and our average realized sale price was $45.38 representing a discount of $4.26 per barrel or 8.6% lower than the average WTI price.
Effective June 1, 2017, we were able to negotiate with our crude oil purchaser the use of a more favorable crude oil pricing schedule that has contributed to increasing the average realized price we receive on our crude oil sales. Historically, the sale price we receive for California heavy crude oil has been less than the quoted WTI price because of the lower API gravity of our California crude oil in comparison to the API gravity of quoted WTI crude oil.
California Crude Oil Revenue and Production
Crude oil revenue in California for the nine months ended November 30, 2018 increased $147,844 or 33.7% to $586,139 in comparison to revenue of $438,925 for the nine months ended November 30, 2017. The average sale price of a barrel of crude oil for the nine months ended November 30, 2018 was $67.83 in comparison to $45.38 for the nine months ended November 30, 2017.
The increase of $22.45 or 49.5% per barrel in the average realized price of a barrel of crude oil accounted for 100.0% of the increase in crude oil revenue for the nine months ended November 30, 2018. Effective June 1, 2017, we were able to negotiate with our crude oil purchaser the use of a more favorable crude oil pricing schedule that has contributed to increasing the average realized price we receive on our crude oil sales.
Our net sales volume for the nine months ended November 30, 2018 was 8,641 barrels of crude oil in comparison to 9,659 barrels sold for the nine months ended November 30, 2017. This decrease in crude oil sales volume of 1,018 barrels or 10.5% was due to 21 fewer days of production and the natural decline in reservoir pressure during the nine months ended November 30
, 2018.
The gravity of our produced crude oil in California ranges between 14° API and 16° API. Production for the nine months ended November 30, 2018 was from 20 wells resulting in 5,460 well days of production in comparison to 5,481 well days of production for the nine months ended November 30, 2017.
Our crude oil sales revenue for the nine months ended November 30, 2018 and 2017 is set forth in the following table:
|
|
|
|
|
|
|
|
|
| |
|
|
Nine Months Ended
November 30, 2018
|
|
Nine Months Ended
November 30, 2017
|
Project
|
|
Revenue
|
|
Percentage
|
|
Revenue
|
|
Percentage
|
California East Slopes Project
|
|
$
|
586,139
|
|
100.0%
|
|
$
|
438,295
|
|
100.0%
|
*Our average realized sale price on a BOE basis for the nine months ended November 30, 2018 was $67.83 in comparison to $45.38 for the nine months ended November 30, 2017, representing an increase of $22.45 or 49.5% per barrel.
Operating Expenses
Total
operating expenses for the nine months ended November 30, 2018 were $834,228, a decrease of $209,548 or 20.1% compared to $1,043,776 for the nine months ended November 30, 2017. The decrease was due to less exploration work associated with our Michigan exploratory joint drilling project in the amount of $102,049 during the prior comparative period and a decrease of $71,081 in G&A expenses. Operating expenses for the nine months ended November 30, 2018 and 2017 are set forth in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
Nine Months Ended
November 30, 2018
|
|
Nine Months Ended
November 30, 2017
|
|
|
Expenses
|
|
Percentage
|
|
BOE
Basis
|
|
Expenses
|
|
Percentage
|
|
BOE
Basis
|
Production expenses
|
|
$
|
115,893
|
|
13.9%
|
|
|
|
|
$
|
130,454
|
|
12.5%
|
|
|
|
Exploration and drilling expenses
|
|
|
992
|
|
0.1%
|
|
|
|
|
|
103,041
|
|
9.9%
|
|
|
|
Depreciation, depletion, amortization (DD&A)
|
|
|
55,669
|
|
6.7%
|
|
|
|
|
|
77,526
|
|
7.4%
|
|
|
|
General and administrative (G&A) expenses
|
|
|
661,674
|
|
79.3%
|
|
|
|
|
|
732,755
|
|
70.2%
|
|
|
|
Total operating expenses
|
|
$
|
834,228
|
|
100.0%
|
|
$
|
96.54
|
|
$
|
1,043,776
|
|
100.0%
|
|
$
|
108.06
|
Production expenses include expenses associated with the production of crude oil and natural gas. These expenses include contract pumpers, electricity, road maintenance, control of well insurance, property taxes and well workover expenses; and, relate directly to the number of wells that are in production. For the nine months ended November 30, 2018, these expenses decreased by $14,561 or 11.2% to $115,893 in comparison to $130,454 for the nine months ended November 30, 2017. For the nine months ended November 30, 2018 and 2017, we had 20 wells on production in California.
Production expense on a barrel of oil equivalent (BOE) basis for the nine months ended November 30, 2018 and 2017 was $13.41 and $13.51, respectively. Production expenses represented 13.9% and 12.5% of total operating expenses for the nine months ended November 30, 2018 and 2017, respectively.
19
Exploration and drilling expenses include geological and geophysical (G&G) expenses as well as leasehold maintenance, plugging and abandonment (P&A) expenses and dry hole expenses. For the nine months ended November 30, 2018, these expenses decreased $102,049 to $992 in comparison to $103,041 the nine months ended November 30, 2017.
The two primary reasons for the year-to-year decrease was the G&G work on the new Michigan exploratory joint drilling project in the amount of $88,543 and the plug and abandonment (P&A) operations on two non-producing well bores in California for $14,492 representing $103,035 in aggregate that was done during the nine months ended November 30, 2017. Exploration and drilling expenses represented 0.1% and 9.9% of total operating expenses for the nine months ended November 30, 2018 and 2017, respectively.
Depreciation, depletion and amortization (DD&A) expenses relate to equipment, proven reserves and property costs, along with impairment, and is another component of operating expenses. For the nine months ended November 30, 2018, DD&A expenses decreased $21,857 or 28.2% to $55,669 in comparison to $77,526 for the nine months ended November 30, 2017. On a BOE basis, DD&A expense was $6.44 and $8.03 for the nine months ended November 30, 2018 and 2017, respectively.
The decrease in DD&A
is directly related to the increase in our reserve estimates in comparison to the prior year reserves. DD&A expenses represented 6.7% and 7.4% of total operating expenses for the nine months ended November 30, 2018 and 2017, respectively.
General and administrative (G&A) expenses include the salaries of our six full-time employees, including management.
Fifty percent (50%) of certain management salaries are currently being deferred until the Companys cash flow improves, however the entire salary expense is recognized under G&A on the statements of operations. Other items included in our G&A expenses are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance expenses and other administrative expenses necessary for an operator of crude oil and natural gas properties as well as for running a public company. For the nine months ended November 30, 2018, G&A expenses decreased $71,081 or 9.7% to $661,674 in comparison to $732,755 for the nine months ended November 30, 2017. We received, as Operator in California, administrative overhead reimbursement of $39,965 during the nine months ended November 30, 2018 for the East Slopes Project which was used to directly offset certain employee salaries. We are continuing a program of reducing all of our G&A costs wherever possible. G&A expenses represented 79.3% and 70.2% of total operating expenses for the nine months ended November 30, 2018 and 2017, respectively.
Interest expense, net for the nine months ended November 30, 2018 increased $373,329 or 27.3%
to $1,740,260 in comparison to $1,366,931 for the nine months ended November 30, 2017.
The increase in interest expense was due to the higher default rate of interest on our credit facility with Maximilian. Refer to the discussion below under the caption Current debt (Short-term borrowings) for more information on the Maximilian credit facility loan.
Results of Operations Three months ended November 30, 2018 compared to the three months ended November 30, 2017
A comparison of the average WTI price and average realized crude oil sales price at our East Slopes Project in California for the three months ended November 30, 2018 and 2017 is shown in the table below:
|
|
|
|
|
|
| |
|
Three Months Ended
|
|
|
|
November 30, 2018
|
|
November 30, 2017
|
|
Percentage Change
|
Average three month WTI crude oil price (Bbl)
|
$
|
65.98
|
|
$
|
52.68
|
|
25.3%
|
Average three month realized crude oil sales price (Bbl)
|
$
|
68.76
|
|
$
|
52.02
|
|
32.2%
|
For the three months ended November 30, 2018, the average WTI price was $65.98 and our average realized crude oil sale price was $68.76, representing a premium of $2.78 per barrel or 4.2% higher than the average WTI price. In comparison, for the three months ended November 30, 2017, the average WTI price was $52.68 and our average realized sale price was $52.02 representing a discount of $0.66 per barrel or 1.3% lower than the average WTI price. Effective June 1, 2017, we were able to negotiate with our crude oil purchaser the use of a more favorable crude oil pricing schedule that has contributed to increasing the average realized price we receive on our crude oil sales. Historically, the sale price we receive for California heavy crude oil has been less than the quoted WTI price because of the lower API gravity of our California crude oil in comparison to the API gravity of quoted WTI crude oil.
California Crude Oil Revenue and Production
Crude oil revenue in California for the three months ended November 30, 2018, increased $22,904 or 13.5% to $192,436 in comparison to revenue of $169,532 for the three months ended November 30, 2017. The average sale price of a barrel of crude oil for the three months ended November 30, 2018 was $68.76 in comparison to $52.02 for the three months ended November 30, 2017. The increase of $16.74 or 32.2% per barrel in the average realized price of a barrel of crude oil accounted for 100.0% of the increase in crude oil revenue for the three months ended November 30, 2018.
20
Our net sales volume for the three months ended November 30, 2018 was 2,799 barrels of crude oil in comparison to 3,259 barrels sold for the three months ended November 30, 2017. This decrease in crude oil sales volume of 460 barrels or 14.1% was due to 37 fewer days of production and the natural decline in reservoir pressure during the three months ended November 30, 2018.
The gravity of our produced crude oil in California ranges between 14° API and 16° API. Production for the three months ended November 30, 2018 was from 20 wells resulting in 1,783 well days of production in comparison to 1,820 well days of production for the three months ended November 30, 2017.
Our crude oil sales revenue for the three months ended November 30, 2018 and 2017 are set forth in the following table:
|
|
|
|
|
|
|
|
|
| |
|
|
Three Months Ended
November 30, 2018
|
|
Three Months Ended
November 30, 2017
|
Project
|
|
Revenue
|
|
Percentage
|
|
Revenue
|
|
Percentage
|
California East Slopes Project
|
|
$
|
192,436
|
|
100.0%
|
|
$
|
169,532
|
|
100.0%
|
*Our average realized sale price on a BOE basis for the three months ended November 30, 2018 was $68.76 in comparison to $52.02 for the three months ended November 30, 2017, representing an increase of $16.74 or 32.2% per barrel.
Operating Expenses
Total
operating expenses for the three months ended November 30, 2018 were $273,785, a decrease of $20,388 or 6.9% compared to $294,173 for the three months ended November 30, 2017. Operating expenses for the three months ended November 30, 2018 and 2017 are set forth in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
Three Months Ended
November 30, 2018
|
|
Three Months Ended
November 30, 2017
|
|
|
Expenses
|
|
Percentage
|
|
BOE
Basis
|
|
Expenses
|
|
Percentage
|
|
BOE
Basis
|
Production expenses
|
|
$
|
41,337
|
|
15.1%
|
|
|
|
|
$
|
38,229
|
|
13.0%
|
|
|
|
Exploration and drilling expenses
|
|
|
-
|
|
0.0%
|
|
|
|
|
|
8,048
|
|
2.7%
|
|
|
|
Depreciation, depletion, amortization (DD&A)
|
|
|
18,144
|
|
6.6%
|
|
|
|
|
|
26,190
|
|
8.9%
|
|
|
|
General and administrative (G&A) expenses
|
|
|
214,304
|
|
78.3%
|
|
|
|
|
|
221,706
|
|
75.4%
|
|
|
|
Total operating expenses
|
|
$
|
273,785
|
|
100.0%
|
|
$
|
97.82
|
|
$
|
294,173
|
|
100.0%
|
|
$
|
90.27
|
For the three months ended November 30, 2018, production expenses increased by $3,108 or 8.1% to $41,337 in comparison to $38,229 for the three months ended November 30, 2017. For the three months ended November 30, 2018 and 2017 we had 20 wells on production in California. Production expense on a barrel of oil equivalent (BOE) basis for the three months ended November 30, 2018 and 2017 were $14.77 and $11.73, respectively. Production expenses represented 15.1% and 13.0% of total operating expenses for the three months ended November 30, 2018 and 2017, respectively.
For the three months ended November 30, 2018, we did not incur any exploration and drilling expenses in comparison to $8,048 for the three months ended November 30, 2017. Exploration and drilling expenses represented 0.0% and 2.7% of total operating expenses for the three months ended November 30, 2018 and 2017, respectively.
For the three months ended November 30, 2018, DD&A expenses decreased $8,046 or 30.7% to $18,144 in comparison to $26,190 for the three months ended November 30, 2017.
DD&A on a BOE basis was $6.48 and $8.04 for the three months ended November 30, 2018 and 2017, respectively. The decrease in DD&A is directly related to the increase in our reserve estimates in comparison to the prior year reserves. DD&A expenses represented 6.6% and 8.9% of total operating expenses for the three months ended November 30, 2018 and 2017, respectively.
For the three months ended November 30, 2018, G&A expenses decreased $7,402 or 3.3% to $214,304 in comparison to $221,706 for the three months ended November 30, 2017. Fifty percent (50%) of certain employees salaries are currently being deferred until the Companys cash flow improves, however the entire salary expense is recognized under G&A on the statements of operations. We received, as Operator in California, administrative overhead reimbursement of $13,322 during the three months ended November 30, 2018 for the East Slopes Project which was used to directly offset certain employee salaries. We are continuing a program of reducing all of our G&A costs wherever possible. G&A expenses represented 78.3% and 75.4% of total operating expenses
for the three months ended November 30, 2018 and 2017, respectively.
21
Interest expense, net for the three months ended November 30, 2018 increased $165,381 or 40.2% to $576,795 in comparison to $411,414 for the three months ended November 30, 2017. The increase in interest expense was due to the higher default rate of interest on our credit facility with Maximilian. Refer to the discussion below under the caption Current debt (Short-term borrowings) for more information on the Maximilian credit facility loan.
The credit facility activity is discussed further in the discussion of the Maximilian Loan Agreement (Credit Facility) under the Current Debt (Short-Term Borrowings) section of this MD&A.
Due to the nature of our business, we expect that revenues, as well as all categories of expenses, will continue to fluctuate substantially on a quarter-to-quarter and year-to-year basis. Revenues are highly dependent on the volatility of hydrocarbon prices and production volumes. Production expenses will fluctuate according to the number and percentage ownership of producing wells as well as the amount of revenues we receive based on the price of crude oil. Exploration and drilling expenses will be dependent upon the amount of capital that we have to invest in future development projects, as well as the success or failure of such projects. Likewise, the amount of DD&A expense will depend upon the factors cited above including the size of our proven reserves base and the market price of energy products. G&A expenses will also fluctuate based on our current requirements, but will generally tend to increase as we expand the business operations of the Company. An on-going goal of the Company is to improve cash flow to cover the current level of G&A expenses and to fund our drilling programs in California and Michigan.
Capital Resources and Liquidity
Our primary financial resource is our proven crude oil reserve base. Our ability to fund any future capital expenditure programs is dependent upon the prices we receive from crude oil sales, the success of our drilling programs in California and Michigan and the availability of capital resource financing. There has been a significant amount of volatility in crude oil prices and a dramatic decline in our realized sale price of crude oil since June of 2014, when the monthly average price of WTI crude oil was $105.79 per barrel. This decline in the price of crude oil has had a substantial negative impact on our cash flow from our producing California properties. While there has been an overall improvement in crude oil prices for the nine months ended November 30, 2018 in comparison to the nine months ended November 30, 2017, there is no guarantee that this trend will continue. Most recently, the monthly average WTI price of oil has declined from $70.75 in October of 2018 to $56.96 in November 2018 representing the continued volatility in crude oil prices. It is beyond our ability to accurately predict how long crude oil prices will continue to remain at these lower price levels; when or at what level they may begin to stabilize; or when they may continue to rebound as there are many factors beyond our control that dictate the price we receive for our crude oil sales.
We plan to spend approximately $300,000 in new capital investments within the East Slopes Project area in the 2019 calendar year if new financing is in place. Each new development well has a Daybreak net cost of $150,000. However, our actual expenditures may vary significantly from this estimate if our plans for exploration and development activities change during the year or if we are unable to obtain financing to fund these capital investments. Factors such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during the current fiscal year.
Changes in our capital resources at November 30, 2018 in comparison to February 28, 2018 are set forth in the table below:
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
Increase
|
|
Percentage
|
|
November 30, 2018
|
|
February 28, 2018
|
|
(Decrease)
|
|
Change
|
Cash
|
$
|
41,651
|
|
$
|
48,535
|
|
$
|
(6,884)
|
|
(14.2%)
|
Restricted cash
|
$
|
-
|
|
$
|
100,029
|
|
$
|
(100,029)
|
|
(100.0%)
|
Current Assets
|
$
|
211,399
|
|
$
|
333,652
|
|
$
|
(122,253)
|
|
(36.6%)
|
Total Assets
|
$
|
934,296
|
|
$
|
1,095,900
|
|
$
|
(161,604)
|
|
(14.7%)
|
Current Liabilities
|
$
|
(18,165,762)
|
|
$
|
(16,343,108)
|
|
$
|
1,822,654
|
|
11.2%
|
Total Liabilities
|
$
|
(18,207,027)
|
|
$
|
(16,380,282)
|
|
$
|
1,826,745
|
|
11.2%
|
Working Capital Deficit
|
$
|
(17,954,363)
|
|
$
|
(16,009,456)
|
|
$
|
1,944,907
|
|
12.1%
|
Our working capital deficit increased approximately $1.9 million or 12.1% to $17,954,363 at November 30, 2018 in comparison to $16,009,456 at February 28, 2018. The increase in our working capital deficit was due to an increase in our accounts payable balances and accrued interest relating to the Maximilian credit facility loan as well as a decrease in both our cash balance and our restricted cash balances.
While we have ongoing positive cash flow from our crude oil operations in California, we have not yet been able to generate sufficient cash flow to cover all of our G&A and interest expense requirements. We anticipate an increase in our cash flow will occur when we are able to return to our planned drilling program that will result in an increase in the number of wells on production.
22
Our business is capital intensive. Our ability to grow is dependent upon favorably obtaining outside capital and generating cash flows from operating activities necessary to fund our investment activities. There is no assurance that we will be able to achieve profitability. Since our future operations will continue to be dependent on successful exploration and development activities and our ability to seek and secure capital from external sources, should we be unable to achieve sustainable profitability this could cause any equity investment in the Company to become worthless.
Major sources of funds in the past for us have included the debt or equity markets and the sale of assets. While we have positive cash flow from our operations in California, we will have to rely on the capital markets to fund future operations and growth. Our business model is focused on acquiring exploration or development properties as well as existing production. Our ability to generate future revenues and operating cash flow will depend on successful exploration, and/or acquisition of crude oil and natural gas producing properties, which may very likely require us to continue to raise equity or debt capital from outside sources.
Daybreak has ongoing capital commitments to develop certain leases pursuant to their underlying terms. Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself. These ongoing capital commitments will cause us to seek additional forms of financing through various methods, including issuing debt securities, equity securities, bank debt, or combinations of these instruments which could result in dilution to existing security holders and increased debt and leverage. The current volatility in the credit and capital markets as well as the decline in crude oil prices from June of 2014 price levels has restricted our ability to obtain needed capital. No assurance can be given that we will be able to obtain funding under any loan commitments or any additional financing on favorable terms, if at all. The sale of all or part of interests in our assets may be another source of cash flow available to us.
The Companys financial statements for the nine months ended November 30, 2018 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business. We have incurred net losses since entering the crude oil and natural gas exploration industry in 2005, and as of the nine months ended November 30, 2018, we have an accumulated deficit of $40,322,732 and a working capital deficit of $17,954,363 which raises substantial doubt about our ability to continue as a going concern.
In the current fiscal year, we will continue to seek additional financing for our planned exploration and development activities in California and Michigan. We could obtain financing through one or more various methods, including issuing debt securities, equity securities, or bank debt, or combinations of these instruments, which could result in dilution to existing security holders and increased debt and leverage. No assurance can be given that we will be able to obtain funding under any loan commitments or any additional financing on favorable terms, if at all.
As a subsequent event to the end of our fiscal third quarter, on December 27, 2018, we paid Maximilian $700,000 to finalize a settlement of outstanding indebtedness on our credit facility and Michigan debt in the amount of approximately $12.6 million. The Company also acquired an additional 40% working interest in the Daybreaks Michigan Project along with a note receivable from its Michigan Project Partner. Daybreak now owns a 70% working interest in its Michigan Project. Furthermore, all liens and security interests granted to Maximilian with respect to the Companys leases in California and Michigan have been terminated and released. The effects of this transaction will be reflected on the Companys financial statements at February 28, 2019. The $700,000 paid to Maximilian was obtained from private investors (of which $300,000 was from a related party) by selling a Production Payment from future wells to be drilled in California and Michigan. The Company intends to raise an additional $600,000 to drill new wells in California and Michigan.
Changes in Financial Condition
During the nine months ended November 30, 2018, we received crude oil sales revenue from 20 wells in California. Our commitment to improving corporate profitability remains unchanged. We experienced an increase in revenues of $147,844 or 33.7% to $586,139 for the nine months ended November 30, 2018 in comparison to revenues of $438,295 for the nine months ended November 30, 2017. The increase of $22.45 or 49.5% per barrel in the average realized price of a barrel of crude oil accounted for 100.0% of the increase in crude oil revenue for the nine months ended November 30, 2018. For the nine months ended November 30, 2018, we had an operating loss of $248,089 in comparison to an operating loss of $605,481 for the nine months ended November 30, 2017. This improvement in reducing our operating loss was due to both an increase in revenue and a reduction in expenses.
Our balance sheet at November 30, 2018 reflects total assets of approximately $0.9 million in comparison to approximately $1.1 million at February 28, 2018. This decrease of approximately $0.2 million is primarily due to cash outflow from operations and depletion expense.
23
At November 30, 2018, total liabilities were approximately $18.2 million in comparison to approximately $16.4 million at February 28, 2018. The increase in liabilities of approximately $1.8 million was due to increases in payables and accrued interest on our credit facility balance with Maximilian. On December 27, 2018, we paid Maximilian $700,000 to finalize a settlement of outstanding indebtedness through its credit facility and Michigan debt in the amount of approximately $12.6 million. Refer to the discussion in Capital Resources and Liquidity section of this MD&A for further information on this subsequent event.
The balance of our common stock issued and outstanding of 51,532,364 shares remained unchanged from February 28, 2018.
Cash Flows
Changes in the net funds provided by and (used in) our operating, investing and financing activities are set forth in the table below:
|
|
|
|
|
|
|
|
|
| |
|
Nine Months
Ended
November 30, 2018
|
|
Nine Months
Ended
November 30, 2017
|
|
Increase
(Decrease)
|
|
Percentage
Change
|
Net cash (used in) operating activities
|
$
|
(32,986)
|
|
$
|
(152,257)
|
|
|
(119,271)
|
|
(78.3%)
|
Net cash (used in ) investing activities
|
$
|
(12,227)
|
|
$
|
-
|
|
|
(12,227)
|
|
(100.0%)
|
Net cash provided by (used in) financing activities
|
$
|
(61,700)
|
|
$
|
122,700
|
|
|
(184,400)
|
|
(150.3%)
|
Cash Flow (Used In) Operating Activities
Cash flow from operating activities is derived from the production of our crude oil and natural gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances. For the nine months ended November 30, 2018, cash flow used in operating activities was $32,986 in comparison to cash flow used in operating activities of $152,217 for the nine months ended November 30, 2017. This decrease of $119,271 in our cash flow used in operating activities for the nine months ended November 30, 2018 was due to a reduction in our changes of non-cash operating expenses and accounts payable balances offset by changes in our asset and accrued interest balances. Changes in non-cash account balances relate primarily to DD&A and amortization of debt discount. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.
Cash Flow (Used In) Investing Activities
Cash flow from investing activities is derived from changes in crude oil and natural gas property balances and any lending activities. Cash flow used in our investing activities for the nine months ended November 30, 2018 was $12,227 in comparison to cash flow used in our investing activities of -$0- for the nine months ended November 30, 2017
.
Cash Flow Provided By (Used In) Financing Activities
Cash flow from financing activities is derived from changes in long-term liability account balances or in equity account balances, excluding retained earnings. Cash flow used in our financing activities was $61,700 for the nine months ended November 30, 2018 in comparison to cash flow provided by our financing activities of $122,700 for the nine months ended November 30, 2017. This increase of $184,400 used in our cash flow activities was primarily due to an additional principal payment of $50,000 made to reduce the outstanding balance on the UBS line of credit. For the nine months ended November 30, 2018, we made total payments of $95,000 to our line of credit with UBS Bank.
The following discussion is a summary of cash flows provided by, and used in, the Companys financing activities at November 30, 2018.
Current debt (Short-term borrowings)
Related Party
The Company has a note payable-related party loan balance of $250,100 as of November 30, 2018 and February 28, 2018. The Companys Chairman, President and Chief Executive Officer has loaned the Company an aggregate $250,100 that was used for a variety of corporate purposes including an escrow requirement on a loan commitment; maturity extension fees on third party loans; and a reduction of principal on the Companys credit line with UBS Bank. These loans are non-interest bearing loans and repayment will be made upon a mutually agreeable date in the future.
24
12% Subordinated Notes
The Companys 12% Subordinated Notes (the Notes) issued pursuant to a January 2010 private placement offering to accredited investors, resulted in $595,000 in gross proceeds (of which $250,000 was from a related party) to the Company and accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th. On January 29, 2015, the Company and 12 of the 13 holders of the Notes agreed to extend the maturity date of the Notes for an additional two years to January 29, 2017. Effective January 29, 2017, the maturity date of the Notes and the expiration date of the warrants that were issued in conjunction with the Notes were extended for an additional two years to January 29, 2019. There are ten noteholders, holding 980,000 warrants, who have not yet exercised their warrants. The exercise price of the associated warrants was lowered from $0.14 to $0.07 as a part of the Note maturity extension. The Notes principal of $565,000 is payable in full at the amended maturity date of the Notes. The fair value of the warrant modification, as determined by the Black-Scholes option pricing model, was $29,075 and was recognized as a discount to debt and is being amortized over the extended maturity date of the Notes. The Black-Scholes valuation encompassed the following weighted average assumptions: a risk free interest rate of 1.22%; volatility of 378.73%; and dividend yield of 0.0%.
The Notes principal of $565,000 is payable in full at the amended maturity date of the Notes. Should the Board of Directors, on the maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Companys common stock at a conversion rate equal to 75% of the average closing price of the Companys common stock over the 20 consecutive trading days preceding December 31, 2018. Amortization expense was $10,903 at November 30, 2018 and 2017. The unamortized debt discount at November 30, 2018 and February 28, 2018 was $2,423 and $13,326, respectively.
12% Note balances at November 30, 2018 and February 28, 2018 are set forth in the table below:
|
|
|
|
| |
|
November 30, 2018
|
|
February 28, 2018
|
12% Subordinated notes
|
$
|
315,000
|
|
$
|
315,000
|
Debt discount
|
|
(1,351)
|
|
|
(7,429)
|
12% Subordinated notes balance, net
|
$
|
313,649
|
|
$
|
307,571
|
12% Note balances related parties at November 30, 2018 and February 28, 2018 are set forth in the table below:
|
|
|
|
| |
|
November 30, 2018
|
|
February 28, 2018
|
12% Subordinated notes related party
|
$
|
250,000
|
|
$
|
250,000
|
Debt discount
|
|
(1,072)
|
|
|
(5,897)
|
12% Subordinated notes related party balance, net
|
$
|
248,928
|
|
$
|
244,103
|
In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at a rate of two warrants for every dollar raised through the private placement. The warrants have an amended exercise price of $0.07 and an amended expiration date of January 29, 2019. The 12% Note warrants that have been exercised are set forth in the table below. At November 30, 2018, there were 980,000 warrants that were not exercised and had not expired.
|
|
|
|
|
| |
Fiscal Period
|
|
Warrants
Exercised
|
|
Shares of
Common Stock
Issued
|
|
Number of
Accredited
Investors
|
Year Ended February 28, 2014
|
|
100,000
|
|
100,000
|
|
1
|
Year Ended February 28, 2015
|
|
50,000
|
|
50,000
|
|
1
|
Year Ended February 29, 2016
|
|
-
|
|
-
|
|
-
|
Year Ended February 28, 2017
|
|
-
|
|
-
|
|
-
|
Year Ended February 28, 2018
|
|
-
|
|
-
|
|
-
|
Nine Months Ended November 30, 2018
|
|
-
|
|
-
|
|
-
|
Totals
|
|
150,000
|
|
150,000
|
|
2
|
25
Maximilian Loan Agreement (Credit Facility)
On October 31, 2012, the Company entered into a loan agreement with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to in these notes to the financial statements as Maximilian), which provided for a revolving credit facility of up to $20 million, that matured on October 31, 2016, with a minimum commitment of $2.5 million. In August 2013, the Company amended its loan agreement with Maximilian thereby increasing the amount of the credit facility to $90 million and reduced the annual interest rate to 12%. The Company evaluated the amendment of the revolving credit facility under ASC 470-50-40 and determined that the Companys borrowing capacity under the amended loan agreement exceeded its borrowing capacity under the old loan agreement. Consequently, the unamortized discount and deferred financing costs as of the date of amendment were amortized over the term of the loan agreement.
On October 31, 2016 through the Fourth Amendment to the Amended and Restated Loan and Security Agreement (the Restructuring Agreement), the maturity date of the loan was changed to February 28, 2020.
As a result of the decline in hydrocarbon prices that started in June of 2014, the Company has been unable to make any type of interest or principal payments required under the amended terms of its credit facility with Maximilian since December of 2015. Due to the Companys default on the Maximilian loan, all unamortized discount and deferred financing costs were fully amortized during the twelve months ended February 28, 2018. Under the terms of the Restructuring Amendment all unpaid interest is currently being accrued. Accrued interest on the credit facility loan at November 30, 2018 and February 28, 2018 was $3,459,858 and $1,812,128, respectively. During the nine months ended November 30, 2018 and 2017, the Company received advances of $-0- and $102,700, respectively, under the terms of the credit facility.
On December 27, 2018, we paid Maximilian $700,000 to finalize a settlement of outstanding indebtedness on the credit facility and Michigan debt in the amount of approximately $12.6 million. The settlement included a release and termination of all liens and security interests granted to Maximilian with respect to the Companys California and Michigan projects. Refer to the discussion in Capital Resources and Liquidity section of this MD&A for further information on this subsequent event.
Maximilian Promissory Note Michigan Exploratory Joint Drilling Project
The Company has a note payable loan balance to Maximilian of $94,650 as of November 30, 2018 and February 28, 2018. The Company has received $94,650 in aggregate from multiple advances since January 2017 from Maximilian under a separate promissory note agreement dated January 17, 2017 and amended on February 10, 2017 regarding the development of an exploratory joint drilling project in Michigan. Advances under this agreement are subject to a 5% (five percent) per annum interest rate. In the event of a default of any of the Companys obligations under the promissory note, the amounts due may be called immediately due and payable at Maximilians option.
Due to a lack of available funding from Maximilian, we have been unable to spud a well on the Michigan project. The Company is currently considered to be in default under the terms of its loan agreement. Maximilian is currently in receivership. The United States District Court for the Eastern District of New York, Southern Division has hired consultants to assist in finding a new lender. No assurances can be made as to who the new lender will be or how the structure of the loan will affect the Company. Accrued interest on the Michigan promissory note at November 30, 2018 and February 28, 2018 was $8,774 and $5,158, respectively. During the nine months ended November 30, 2018 and 2017, the Company received advances of $-0- and $10,650. The $10,650 was paid directly to the Operator of the Michigan project by Maximilian on the Companys behalf.
In accordance with the guidance found in ASC-470-10-45, the entire balance of both the Maximilian credit facility loan and the Michigan loan is presented under the current liabilities section of the balance sheets. Current debt balances at November 30, 2018 and February 28, 2018 are set forth in the table below:
|
|
|
|
| |
|
November 30, 2018
|
|
February 28, 2018
|
Credit facility balance
|
$
|
9,063,144
|
|
$
|
9,063,144
|
Michigan exploratory joint drilling debt
|
|
94,650
|
|
|
94,650
|
Subtotal debt
|
|
9,157,794
|
|
|
9,157,794
|
Accrued interest on credit facility and Michigan exploratory joint drilling debt
|
|
3,468,632
|
|
|
1,817,287
|
Total Maximilian debt
|
$
|
12,626,426
|
|
$
|
10,975,081
|
26
On December 27, 2018, we paid Maximilian $700,000 to finalize a settlement of outstanding indebtedness on the credit facility and Michigan debt in the amount of approximately $12.6 million. The settlement included a release and termination of all liens and security interests granted to Maximilian with respect to the Companys California and Michigan projects. Refer to the discussion in Capital Resources and Liquidity section of this MD&A for further information on this subsequent event.
Line of Credit
The Company has an existing $890,000 line of credit for working capital purposes with UBS Bank USA (UBS), established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of its Chairman, President and Chief Executive Officer. On July 10, 2017 a $700,000 portion of the outstanding line of credit balance was converted to a 24 month fixed term annual interest rate of 3.244% with interest payable monthly. The remaining principal balance of the line of credit has a stated reference rate of 0.249% + 337.5 basis points with interest payable monthly. The reference rate is based on the 30 day LIBOR (London Interbank Offered Rate) and is subject to change from UBS.
At November 30, 2018 and February 28, 2018, the line of credit had an outstanding balance of $834,329 and $873,350, respectively. During the nine months ended November 30, 2018 and 2017, the Company made payments to the line of credit of $95,000 and $45,000, respectively. Interest incurred for the nine months ended November 30, 2018 and 2017 was $22,680 and $24,903, respectively.
Capital Commitments
Daybreak has ongoing capital commitments to develop certain leases pursuant to their underlying terms. Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself. These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company. The current uncertainty in the credit and capital markets, and the current economic downturn in the energy sector, may restrict our ability to obtain needed capital.
Restricted Stock and Restricted Stock Unit Plan
On April
6, 2009, the Board approved the Restricted Stock and Restricted Stock Unit Plan (the 2009 Plan) allowing the executive officers, directors, consultants and employees of Daybreak and its affiliates to be eligible to receive restricted common stock and restricted common stock unit awards. Subject to adjustment, the total number of shares of Daybreak common stock that will be available for the grant of awards under the 2009 Plan may not exceed 4,000,000 shares; provided, that, for purposes of this limitation, any stock subject to an award that is forfeited in accordance with the provisions of the 2009 Plan will again become available for issuance under the 2009 Plan. We believe that awards of this type further align the interests of our employees and our shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance. Restricted stock and restricted stock units also enhance our ability to attract and retain the services of qualified individuals.
At November 30, 2018, a total of 3,000,000 shares of restricted stock had been awarded under the 2009 Plan, with 2,986,220 shares outstanding and fully vested. A total of 1,013,780 common stock shares remained available at November 30, 2018 for issuance pursuant to the 2009 Plan. A summary of the 2009 Plan issuances is set forth in the table below:
|
|
|
|
|
|
|
|
|
| |
Grant
Date
|
|
Shares
Awarded
|
|
Vesting
Period
|
|
Shares
Vested
(1)
|
|
Shares
Returned
(2)
|
|
Shares
Outstanding
(Unvested)
|
4/7/2009
|
|
1,900,000
|
|
3 Years
|
|
1,900,000
|
|
-
|
|
-
|
7/16/2009
|
|
25,000
|
|
3 Years
|
|
25,000
|
|
-
|
|
-
|
7/16/2009
|
|
625,000
|
|
4 Years
|
|
619,130
|
|
5,870
|
|
-
|
7/22/2010
|
|
25,000
|
|
3 Years
|
|
25,000
|
|
-
|
|
-
|
7/22/2010
|
|
425,000
|
|
4 Years
|
|
417,090
|
|
7,910
|
|
-
|
|
|
3,000,000
|
|
|
|
2,986,220
(1)
|
|
13,780
(2)
|
|
-
|
(1)
Does not include shares that were withheld to satisfy such tax liability upon vesting of a restricted award by a Plan Participant, and subsequently returned to the 2009 Plan.
(2)
Reflects the number of common shares that were withheld pursuant to the settlement of the number of shares with a fair market value equal to such tax withholding liability, to satisfy such tax liability upon vesting of a restricted award by a Plan Participant.
For the nine months ended November 30, 2018 and 2017, the Company did not recognize any stock compensation expense related to the above restricted stock grants since all issuances have been fully amortized.
27
Management Plans to Continue as a Going Concern
We continue to implement plans to enhance Daybreaks ability to continue as a going concern. The Company currently has a net revenue interest in 20 producing crude oil wells in our East Slopes Project located in Kern County, California. The revenue from these wells has created a steady and reliable source of revenue for the Company. Our average working interest in these wells is 36.6% and the average net revenue interest is 28.4%.
We anticipate revenues will continue to increase as the Company participates in the drilling of more wells in the East Slopes Project in California and as our drilling operations begin in Michigan. However given the current volatility and instability in hydrocarbon prices, the timing of any drilling activity in California and Michigan will be dependent on a sustained improvement in hydrocarbon prices and a successful refinancing or restructuring of our credit facility.
We believe that our liquidity will improve when there is a sustained improvement in hydrocarbon prices. Our sources of funds in the past have included the debt or equity markets and the sale of assets. While the Company does have positive cash flow from its crude oil properties, it has not yet established a positive cash flow on a company-wide basis. It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future. However, we cannot offer any assurance that we will be successful in executing the aforementioned plans to continue as a going concern.
Our financial statements as of November 30, 2018 do not include any adjustments that might result from the inability to implement or execute Daybreaks plans to improve our ability to continue as a going concern.
On December 27, 2018, we paid Maximilian $700,000 to finalize a settlement of outstanding indebtedness on the credit facility and Michigan debt in the amount of approximately $12.6 million. The settlement included a release and termination of all liens and security interests granted to Maximilian with respect to on the Companys California and Michigan projects. Refer to the discussion in Capital Resources and Liquidity section of this MD&A for further information on this subsequent event.
Critical Accounting Policies
Refer to Daybreaks Annual Report on Form 10-K for the fiscal year ended February 28, 2018.
Off-Balance Sheet Arrangements
As of November 30, 2018, we did not have any off-balance sheet arrangements or relationships with unconsolidated entities or financial partners that have been, or are reasonably likely to have, a material effect on our financial position or results of operations.
28