DAYBREAK OIL & GAS, INC. - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is management's 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, 2015 and in
our Annual Report on Form 10-K for the year ended February 28, 2015. 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 Management's 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 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 oil and natural gas;
·
Our ability to find, acquire and develop oil and natural gas properties;
·
Fluctuations in the levels of our oil and natural gas exploration and development activities;
·
Risks associated with oil and natural gas exploration and development activities;
·
Competition for raw materials and customers in the oil and natural gas industry;
·
Technological changes and developments in the 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 our Form 10-K for the year ended February
28, 2015; 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, 2015 and in this Form 10-Q 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.
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Introduction and Overview
We are an independent oil and natural gas exploration, development and
production company. Our basic business model is to increase shareholder value
by finding and developing 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 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 oil and natural gas properties and on the
prevailing sales prices for oil and natural gas along with associated operating
expenses. The volatile nature of the energy markets makes it difficult to
estimate future prices of oil and natural gas; however, any prolonged period of
depressed prices, such as we are now experiencing, would have a material adverse
effect on our results of operations and financial condition.
Our operations are focused on identifying and evaluating prospective oil and
natural gas properties and funding projects that we believe have the potential
to produce 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 two multi-well oilfield projects; one in
Lawrence County, Kentucky
and the other in
Kern County, California
.
In the current fiscal year, we will continue to seek additional financing for
our planned exploration and development activities in both
Kentucky
and
California
. The Company has engaged an investment banking firm to assist in
securing refinancing of its debt under more favorable terms and implement its
development plans in
California
and
Kentucky
. We plan to obtain financing
through 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. Sales of
interests in our assets may be another source of cash flow.
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, 2015 and in Part III, Item 1A. Risk Factors of this 10-Q Report.
Throughout this Quarterly Report on Form 10-Q, 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 oil equivalent ("BOE").
Below is summary of our oil and natural gas projects in
Kentucky
and
California
.
Lawrence County, Kentucky
(Twin Bottoms Field)
The Twin Bottoms Field, comprising approximately 7,300 acres in two large contiguous blocks, is located in the Appalachian Basin of eastern
Kentucky
.
Log
data from existing vertical natural gas wells in the field indicate the
existence of proved oil reserves in the
Berea
sandstone, located at
approximately 2,000 feet. The lateral leg of each well is between 2,000 feet
and 4,500 feet in length. We have an approximate 25% working interest and an
approximate net revenue interest ("NRI") of 21.9% in all horizontal oil wells in
this project. The oil produced from our acreage in
Kentucky
is light crude oil
measuring between 42° and 44° API gravity. We are not the Operator of the Twin
Bottoms Field project; instead we rely on the experience of the current Operator
and its knowledge of this Field.
At November 30, 2015, we had 14 producing horizontal oil wells in the Twin
Bottoms Field. Our first well, the Grove H-1 was put on production in October
2013. During the year ended February 28, 2014, three additional oil wells, the
Grove #H-3, Grove #H-4 and Grove #H-5, were put on production. Nine additional
horizontal oil wells, the Dillon #H-6, Grove #H-7, Grove #H-8, Grove #H-9, Grove
#H-10, Jackson #H-20,
Lyons
#H-23,
Lyons
#H-24 and the Dillon #H-22, were put on
production during the year ended February 28, 2015. The App Energy #H-33 well
was drilled in October 2015 to a measured depth of 5,251 feet and encountered
3,913 feet of oil pay in the Berea Sandstone. Our average working interest and
NRI in these 14 producing horizontal oil wells is 22.6% and 19.7%, respectively.
In August 2015, we drilled the vertical leg portion of the Murray #H-34 well.
The well was logged and data was collected for use in the drilling of the App
Energy #H-33 well. The Company paid 12.5% of the drilling and completion cost
for a 25% working interest in the App Energy H-33 and Murray #H-34 wells as part
of the App Amendment. The horizontal portion of the Murray #H-34 well will be
drilled at a later date.
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Kentucky Drilling Plans
Selected wells may be drilled from time to time to maintain production and
leases, however; implementation of our full development plan will not begin
until there is a sustained improvement in crude oil prices and additional
financing is put in place. We do not plan to make any capital investments in
the Twin Bottoms Field project area during the remainder of the 2015-2016 fiscal
year.
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 which 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.
Our 20 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. Our
average working interest and NRI in these 20 producing oil wells is 36.6% and
28.5%, respectively. There are several other similar prospects on trend with
the Bear, Black and Dyer Creek reservoirs exhibiting the same seismic
characteristics. Some of these prospects, if successful, would utilize the
Company's 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.
Sunday Central Processing and Storage Facility
The oil produced from our acreage in
California
is considered heavy oil. The
oil ranges from 14° to 16° API (American Petroleum Institute) gravity. All of
the oil from our five producing properties is processed, stored and sold from
the Sunday central processing and storage facility. The oil must be heated to
separate and remove water to prepare it to be sold. We constructed these
facilities during the summer and fall of 2009 and at the same time established
electrical service for our field by constructing three miles of power lines. In
2013, we completed an upgrade to this facility including the addition of a
second oil storage tank to handle the additional oil production from the wells
drilled in 2013.
By utilizing the Sunday centralized production facility our average operating
costs have been reduced from over $40 per barrel in 2009 to a monthly average of
approximately $12 per barrel of oil for the nine months ended November 30, 2015.
With this centralized facility and having permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.
Exploration Properties
Bull Run Prospect
This prospect is located in the southern portion of our acreage position. The
drilling targets are the Etchegoin and
Santa Margarita
sands located between 800
and 1,200 feet deep. Utilizing the data received from a previously drilled well
that was not commercially successful, we expect to drill another exploratory
well on this prospect in the future. Future Bull Run wells will require a pilot
steam flood and production facilities. We estimate that the Bull Run prospect
is 70 acres in size. We have a 37.5% working interest in this prospect.
Sherman Prospect
This prospect is also located in the southern portion of our acreage position.
The drilling targets are the Olcese and Etchegoin sands between 1,000 and 2,000
feet deep. We estimate that the Sherman Prospect is 100 acres in size. The
Company is currently seeking an extension of the leases in this prospect which
expire in May 2016. We have a 37.5% working interest in this prospect.
Tobias Prospect
This prospect is also located in the central portion of our acreage position.
The drilling targets are the Vedder and Eocene sands between 2,000 and 4,500
feet deep. This prospect be drilled in the future. We estimate that the Tobias
prospect is 60 acres in size. We have a 37.5% working interest in this
prospect.
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California Drilling Plans
Future drilling plans include a combination of both exploratory drilling and
development well drilling. Planned drilling activity and implementation of our
full development plan will not begin until there is a sustained improvement in
crude oil prices and additional financing is put in place. We do not plan to
make any capital investments in the East Slopes Project during the rest of the
2015-2016 fiscal year.
Encumbrances
The Company's debt obligations, pursuant to a loan agreement entered into by and
between Maximilian Resources LLC, a
Delaware
limited liability company and
successor by assignment to Maximilian Investors LLC (either party, as
appropriate, is referred to "Maximilian"), as lender, and the Company are
secured by a perfected first priority security interest in substantially all of
the personal property of the Company, and a mortgage on our leases in
Kern County, California
encompassing the Sunday, Bear, Black, Ball and Dyer Creek
properties. For further information on the loan agreement refer to the
discussion under the caption "Non-current Borrowings" in this MD&A.
Results of Operations - Nine Months Ended November 30, 2015 compared to the Nine Months Ended November 30, 2014
Hydrocarbon Prices
The price we receive for oil sales in both
Kentucky
and
California
is based on
prices quoted on the New York Mercantile Exchange ("NYMEX") for spot West Texas
Intermediate ("WTI")
Cushing, Oklahoma
delivery contracts, less deductions that
vary by grade of crude oil sold and transportation costs. The price we receive
for natural gas sales in
Kentucky
per Mcf is based on the Columbia Gas
Transmission Corp. Appalachia Index ("TCO Appalachia") whereby we will receive
76% of the TCO Appalachia price per dekatherm (DTH) less $0.25 compression cost
for each Mcf of natural gas delivered. We do not have any natural gas revenues
in
California
.
Since June 2014, there has been a significant decline in the WTI price of crude
oil and subsequently in the realized price we receive from oil sales. This
decline in the price of crude oil has had a substantial negative impact on our
cash flow from both our
Kentucky
and
California
properties as shown in the table
below.
Percentage
June 2014 November 2015 Decline
Monthly average WTI crude oil price $ 105.79 $ 42.39
59.9%
Monthly average realized crude oil
sales price (Bbl) $ 101.32 $ 36.66 63.8%
Kentucky Oil Prices
For the nine months ended November 30, 2015, our average realized oil sale price
was $49.38 in comparison to the average WTI price of $49.94 representing a
discount of $0.56 per barrel or 1.1% lower than the average WTI price. In
comparison, for the nine months ended November 30, 2014, the average WTI price
was $96.04 and our average realized sale price was $95.48 representing a
discount of $0.56 per barrel or 0.6% lower than the average WTI price.
Kentucky Natural Gas Prices
For the nine months ended November 30, 2015, our average realized natural gas
sale price was $1.62 per Mcf (thousand cubic feet) in comparison to the average
Henry Hub price of $2.64 per million BTU representing a discount of $1.02 per
Mcf or 38.6% lower than the average Henry Hub price. In comparison, for the
nine months ended November 30, 2014, the average realized sale price was $3.01
per Mcf in comparison to the average Henry Hub price of $4.28 per million BTU
representing a discount of $1.27 or 29.7% lower than the average Henry Hub
price.
California Oil Prices
For the nine months ended November 30, 2015, the average WTI price was $49.94
and our average realized oil sale price was $41.89, representing a discount of
$8.05 per barrel or 16.1% lower than the average WTI price. In comparison, for
the nine months ended November 30, 2014, the average WTI price was $96.04 and
our average realized sale price was $89.10 representing a discount of $6.94 per
barrel or 7.2% lower than the average WTI price. Historically, the sale price
we receive for
California
heavy oil has been less than the quoted WTI price
because of the lower API gravity of our
California
oil in comparison to WTI oil
API gravity.
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Total Oil and Natural Gas Revenue and Production
Our revenues are derived entirely from the sale of our share of oil production
in
Kentucky
and
California
and natural gas sales in
Kentucky
. Oil and natural
gas revenues for the nine months ended November 30, 2015 in aggregate decreased
$1,430,925 or 56.8%, to $1,087,450 in comparison to revenues of $2,518,375 for
the nine months ended November 30, 2014. Oil and natural gas sales volume
decreased 2,520 BOE (barrels of oil equivalent) or 8.6% to 26,528 (BOE) in
comparison to 29,048 (BOE) for the nine months ended November 30, 2014. The
decrease in volume was due to the natural decline in oil producing reservoir
pressure. Our average realized sale price on a BOE basis for the nine months
ended November 30, 2015 was $40.99 in comparison to $86.75 for the nine months
ended November 30, 2014, representing a decline of $45.76 or 52.8% per barrel.
Kentucky Oil Revenue and Production
Production in
Kentucky
is from horizontal oil wells in consolidated shale sands
that are characterized by large initial production volumes that decline quite
rapidly to a much lower and more stable long-term production volume.
Fluctuations in revenue are closely linked to both production volumes and crude
oil prices. Our first oil sales in
Kentucky
occurred in October 2013. Oil
revenue in
Kentucky
for the nine months ended November 30, 2015 decreased
$754,841 or 55.7% to $601,339 in comparison to revenue of $1,356,180 for the
nine months ended November 30, 2014. The average realized sale price of a
barrel of oil for the nine months ended November 30, 2015 was $49.38 in
comparison to $95.48 for the nine months ended November 30, 2014. The decrease
of $46.11 or 48.3% in the average sale price of a barrel of oil was responsible
for 86.8% of the decline in
Kentucky
oil revenue for the nine months ended
November 30, 2015.
Our net sales volume in the nine months ended November 30, 2015 was 12,179
barrels of oil in comparison to 14,221 barrels sold during the nine months ended
November 30, 2014. This decrease in oil sales volume of 2,042 barrels or 14.4%
was responsible for 13.2% of the decline in
Kentucky
oil revenue for the nine
months ended November 30, 2015.
The API gravity of our produced oil in
Kentucky
ranges between 42° API and 44°
API. Production for the nine months ended November 30, 2015 was from 14 wells
resulting in 3,274 well days of production in comparison to 1,709 well days from
10 horizontal oil wells during the nine months ended November 30, 2014.
Kentucky Natural Gas Revenue and Production
Natural gas production is a by-product from our horizontal oil wells and the
volume varies on a well-to-well basis. Our first natural gas sales in
Kentucky
also occurred in October 2013. Natural gas revenue for the nine months ended
November 30, 2015 decreased $4,583 to $34,752 in comparison to revenue of
$39,335 for the nine months ended November 30, 2014. The average realized sale
price per Mcf for the nine months ended November 30, 2015 was $1.62 in
comparison to $3.01 for the nine months ended November 30, 2014.
Our net sales volume in the nine months ended November 30, 2015 was 21,443 Mcf
or 3,574 BOE in comparison to 13,350 Mcf or 2,225 BOE during the nine months
ended November 30, 2014. The increase of 8,093 MCF or 1,349 BOE representing a
60.6% increase was due to infrastructure improvements that had previously
inhibited natural gas production from existing wells.
California Revenue and Production
Production in
California
is from vertical oil wells that historically produce at
relatively stable levels over time. Fluctuations in revenue are generally more
dependent on the price of crude oil and the timing of oil sales rather than oil
production volumes. Oil revenue in
California
for the nine months ended
November 30, 2015 decreased $671,501 or 59.8% to $451,359 in comparison to
revenue of $1,122,860 for the nine months ended November 30, 2014. The average
realized sale price of a barrel of oil for the nine months ended November 30,
2015 was $41.89 in comparison to $89.10 for the nine months ended November 30,
2014. The decrease of $47.22 or 53.0% in the average realized sale price of a
barrel of oil accounted for 88.6% of the decrease in
California
oil revenue for
the nine months ended November 30, 2015.
Our net sales volume in the nine months ended November 30, 2015 was 10,775
barrels of oil in comparison to 12,602 barrels sold during the nine months ended
August 31, 2014. This decrease in oil sales volume of 1,827 barrels or 14.5%
accounted for 11.4% of the decrease in
California
oil revenue for the nine
months ended November 30, 2015. The decrease in volume was due to natural
decline in the oil producing reservoirs.
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The gravity of our produced oil in
California
ranges between 14° API and 16°
API. Production for the nine months ended November 30, 2015 was from 20 wells
resulting in 5,410 well days of production in comparison to 5,482 of production
from 20 wells for the nine months ended November 30, 2014.
Oil and natural gas revenues for the nine months ended November 30, 2015 and 2014 are set forth in the table below:
Nine Months Ended Nine Months Ended
November 30, 2015 November 30, 2014
Revenue Percentage Revenue Percentage
Kentucky - Twin Bottoms Field (oil) $ 601,339 55.3% $ 1,356,180 53.8%
Kentucky - Twin Bottoms Field (natural gas) 34,752 3.2% 39,335 1.6%
California - East Slopes Project (oil) 451,359 41.5% 1,122,860 44.6%
Total oil and natural gas revenues* $ 1,087,450 100.0%
$ 2,518,375 100.0%
*Our average realized sale price on a BOE basis for the nine months ended November 30, 2015 was $40.99 in comparison to $86.75 for the nine months ended November 30, 2014, representing a decline of $45.76 or 52.8% per barrel.
Operating Expenses. Total operating expenses for the nine months ended November
30, 2015 decreased by $127,503 or 8.2% to $1,420,624 in comparison to $1,548,127
for the nine months ended November 30, 2014.
Operating expenses for the nine months ended November 30, 2015 and November 30, 2014 are set forth in the table below:
Nine Months Ended Nine Months Ended
November 30, 2015 November 30, 2014
BOE BOE
Expenses Percentage Basis Expenses Percentage Basis
Production expenses $ 208,243 14.7% $ 251,625 16.3%
Exploration and
drilling expenses 29,823 2.1% 20,172 1.3%
Depreciation,
Depletion,
Amortization, and
Impairment ("DD&A") 399,698 28.1% 426,366 27.5%
General and
Administrative ("G&A")
expenses 782,860 55.1% 849,964 54.9%
Total operating
expenses $ 1,420,624 100.0% $ 53.55 $ 1,548,127 100.0% $ 53.33
Production expenses include expenses associated with the production of oil and natural gas. These expenses include pumper salaries, 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, 2015, these expenses decreased by
$43,382 or 17.2% to $208,243 in comparison to $251,625 for the nine months ended
November 30, 2014. For the nine months ended November 30, 2015 we had 20 wells
on production in
California
and 14 wells on production in
Kentucky
in comparison
to 20 wells in
California
and 10 wells in
Kentucky
for the nine months ended
November 30, 2014. Production expenses represented 14.7% of total operating
expenses.
Production expenses in
Kentucky
and
California
for the nine months ended November 30, 2015 and November 30, 2014 are set forth in the table below:
Nine Months Ended Nine Months Ended
November 30, 2015 November 30, 2014
Expenses Percentage Expenses Percentage
Kentucky - Twin Bottoms Field $ 86,928 41.7% $ 106,633 42.4%
California - East Slopes Project 121,315 58.3% 144,992 57.6%
Total production expenses $ 208,243 100.0% $ 251,625 100.0%
Production expenses on a BOE basis in
Kentucky
and
California
for the nine
months ended November 30, 2015 and November 30, 2014 are set forth in the table
below:
Nine Months Ended
November 30, 2015 November 30, 2014
Kentucky - Twin Bottoms Field (BOE) $ 5.52 $
6.39
California - East Slopes Project (BOE) $ 11.26 $
11.63
Aggregate production expenses (BOE) $ 7.85 $ 8.66
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Exploration and drilling expenses include geological and geophysical ("G&G")
expenses as well as leasehold maintenance and dry hole expenses. These expenses
increased $9,651 or 47.8% to $29,823 for the nine months ended November 30, 2015
in comparison to $20,172 the nine months ended November 30, 2014 primarily due
to additional G&G work in
Kentucky
. Exploration and drilling expenses
represented 2.1% of total operating expenses.
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, 2015, DD&A expenses decreased $26,668 or 6.3% to
$399,698 in comparison to $426,366 for the nine months ended November 30, 2014.
The decrease in DD&A is directly related to the level of our hydrocarbon
production in both
Kentucky
and
California
offset by additional impairment in
California
of $34,744. On a BOE basis, DD&A and impairment represented $15.07
and $14.68 per barrel for the nine months ended November 30, 2015 and 2014,
respectively. DD&A expenses represented 28.1% of total operating expenses.
G&A expenses include the salaries of six full-time employees, including
management. Other items included in our G&A expenses are legal and accounting
expenses, director fees, stock compensation, investor relations fees, travel
expenses, insurance, Sarbanes-Oxley ("SOX") compliance expenses and other
administrative expenses necessary for an operator of oil and natural gas
properties as well as for running a public company. For the nine months ended
November 30, 2015, G&A expenses decreased $67,104 or 7.9% to $782,860 in
comparison to $849,964 for the nine months ended November 30, 2014. We
received, as Operator in
California
, administrative overhead reimbursement of
$39,965 during the nine months ended November 30, 2015 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 55.1% of total operating expenses.
Interest income for the nine months ended November 30, 2015 decreased $70,078 or
8.4% to $763,700 in comparison to $833,778 for the nine months ended November
30, 2014 due to reduced interest rates and modification of the Note receivable
from App Energy. For further discussion on the App Energy Note refer to the
discussion of the App Loan Agreement under Capital Resources and Liquidity -
Cash Flow Provided by (Used in) Financing Activities, Non-current Debt
(Long-term Borrowings) in this MD&A.
Interest expense for the nine months ended November 30, 2015 increased $231,151
or 11.1% to $2,312,741 in comparison to $2,081,590 for the nine months ended
November 30, 2014. The increase in interest expense is directly related to the
modified loan payment terms on our credit facility with Maximilian. The credit
facility activity is discussed further in the discussion of the Maximilian
Credit Facility - Amended and Restated Loan Agreement in the MD&A section of
this 10-Q report under Capital Resources and Liquidity - Cash Flow Provided by
(Used in) Financing Activities, Non-current Debt (Long-term Borrowings) in this
MD&A.
Results of Operations - Three Months Ended November 30, 2015 compared to the Three Months Ended November 30, 2014
Kentucky Oil Prices
For the three months ended November 30, 2015, our average realized oil sale
price was $43.66 in comparison to the average WTI price of $44.70 representing a
discount of $1.04 per barrel or 2.3% from the average WTI price. In comparison,
for the three months ended November 30, 2014 the average WTI price was $84.47
and our average realized sale price was $84.11, representing a discount of $0.36
per barrel or 0.4% lower than the average WTI prices.
Kentucky Natural Gas Prices
For the three months ended November 30, 2015, our average realized natural gas
sale price was $1.33 per Mcf in comparison to the average Henry Hub price of
$2.36 per million BTU representing a discount of $1.03 per Mcf or 43.5% lower
than the average Henry Hub price. In comparison, for the three months ended
November 30, 2014, the average realized sale price was $3.15 per Mcf while the
average Henry Hub price was $3.94 per million BTU representing a discount of
$0.79 or 20.0% lower than the average Henry Hub price.
California Oil Prices
For the three months ended November 30, 2015, the average WTI price was $44.70
and our average realized oil sale price was $35.88 representing a discount of
$8.82 per barrel or 19.7% lower than the average WTI price. In comparison, for
the three months ended November 30, 2014, the average WTI price was $84.47 and
our average realized sale price was $75.80, representing a discount of $8.67 per
barrel or 10.3% lower than the average WTI price.
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Total Oil and Natural Gas Revenue and Production
Oil and natural gas revenues for the three months ended November 30, 2015 in
aggregate decreased $387,318 or 58.4%, to $276,332 in comparison to revenues of
$663,650 for the three months ended November 30, 2014. Oil and natural gas
sales volume decreased 1,272 BOE (barrels of oil equivalent) or 13.9% to 7,891
(BOE) in comparison to 9,163 (BOE) for the three months ended November 30, 2014.
Our average realized sale price on a BOE basis for the three months ended November 30, 2015 was $35.02 in comparison to $72.43 for the three months ended November 30, 2014, representing a decline of $37.41 or 51.6% per barrel.
Kentucky Oil Revenue and Production
Oil revenue in
Kentucky
for the three months ended November 30, 2015 decreased
$197,255 or 59.0% to $136,901 in comparison to revenue of $334,156 for the three
months ended November 30, 2014. The average realized sale price of a barrel of
oil for the three months ended November 30, 2015 was $43.66 in comparison to
$84.11 for the three months ended November 30, 2014. The decrease of $40.46 or
48.1% in the average sale price of a barrel of oil accounted for 81.5% of the
decline in
Kentucky
oil revenue for the three months ended November 30, 2015.
Our net sales volume for the three months ended November 30, 2015 was 3,136
barrels of oil in comparison to 3,991 barrels sold for the three months ended
August 31, 2014. This decrease in oil sales volume of 855 barrels or 21.4%
accounted for 18.5% of the decline in
Kentucky
oil revenue for the three months
ended November 30, 2015.
Production for the three months ended November 30, 2015 was from 14 wells resulting in 1,102 well days of production in comparison to 776 well days from 10 horizontal oil wells during for the three months ended November 30, 2014.
Kentucky Natural Gas Revenue and Production
Natural gas revenue for the three months ended November 30, 2015 decreased
$11,858 to $8,948 in comparison to revenue of $20,806 for the three months ended
November 30, 2014. The average realized sale price per Mcf for the three months
ended November 30, 2015 was $1.33 in comparison to $3.15 for the three months
ended November 30, 2014. Our net sales volume for the three months ended
November 30, 2015 was 6,710 Mcf or 1,118 BOE in comparison to 6,599 Mcf or 1,100
BOE for the three months ended November 30, 2014. The increase in natural gas
volume of 112 or 19 BOE representing a 1.7% increase was due to infrastructure
improvements that had previously inhibited natural gas production from existing
wells.
California Revenue and Production
Oil revenue in
California
for the three months ended November 30, 2015 decreased
$178,205 or 57.7% to $130,483 in comparison to revenue of $308,688 for the three
months ended November 30, 2014. The average realized sale price of a barrel of
oil for the three months ended November 30, 2015 was $35.88 in comparison to
$75.80 for the three months ended November 30, 2014. The decrease of $39.92 or
52.7% in the average realized sale price of a barrel of oil accounted for 91.2%
of the decrease in
California
oil revenue for the three months ended November
30, 2015.
Our net sales volume for the three months ended November 30, 2015 was 3,637
barrels of oil in comparison to 4,072 barrels sold for the three months ended
November 30, 2014. This decrease in oil sales volume of 435 barrels or 10.7%
accounted for 8.8% of the decrease in revenue for the three months ended
November 30, 2015. Production for the three months ended November 30, 2015 was
from 20 wells resulting in 1,748 well days of production in comparison to 1,816
of production from 20 wells for the three months ended November 30, 2014.
Oil and natural gas revenues for the three months ended November 30, 2015 and November 30, 2014 are set forth in the table below:
Three Months Ended Three Months Ended
November 30, 2015 November 30, 2014
Revenue Percentage Revenue Percentage
Kentucky - Twin Bottoms Field (oil) $ 136,901 49.6% $ 334,156 50.4%
Kentucky - Twin Bottoms Field (natural gas) 8,948 3.2% 20,806 3.1%
California - East Slopes Project (oil) 130,483 47.2% 308,688 46.5%
Total oil and natural gas revenues* $ 276,332 100.0% $
663,650 100.0%
*Our average realized sale price on a BOE basis for the three months ended November 30, 2015 was $35.02 in comparison to $72.43 for the three months ended November 30, 2014, representing a decline of $37.41 or 51.6% per barrel.
22
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Operating Expenses. Total operating expenses for the three months ended November 30, 2015 increased by $4,304 or 0.9% to $462,719 in comparison to $458,415 for the three months ended November 30, 2014.
Operating expenses for the three months ended November 30, 2015 and November 30, 2014 are set forth in the table below:
Three Months Ended Three Months Ended
November 30, 2015 November 30, 2014
BOE BOE
Expenses Percentage Basis Expenses Percentage Basis
Production expenses $ 62,637 13.5% $ 86,140 18.8%
Exploration and drilling
expenses 9,756 2.1% 7,362 1.6%
Depreciation, Depletion,
Amortization, and
Impairment ("DD&A") 141,969 30.7% 134,873 29.4%
General and Administrative
("G&A") expenses 248,357 53.7% 230,040 50.2%
Total operating expenses $ 462,719 100.0% $ 58.64 $ 458,415 100.0% $ 50.03
For the three months ended November 30, 2015, production expenses decreased by
$23,503 or 27.3% to $62,637 in comparison to $86,140 for the three months ended
November 30, 2014. For the three months ended November 30, 2014 we had 20 wells
on production in
California
and 14 wells on production in
Kentucky
in comparison
to 20 wells in
California
and 10 wells in
Kentucky
for the three months ended
November 30, 2014. Production expenses represented 13.5% of total operating
expenses for the three months ended November 30, 2015.
Production expenses in
Kentucky
and
California
for the three months ended November 30, 2015 and November 30, 2014 are set forth in the table below:
Three Months Ended Three Months Ended
November 30, 2015 November 30, 2014
Expenses Percentage Expenses Percentage
Kentucky - Twin Bottoms Field $ 28,374 45.3% $ 31,482 36.5%
California - East Slopes Project 34,263 54.7% 54,658 63.5%
Total production expenses $ 62,637 100.0% $ 86,140 100.0%
Production expenses on a BOE basis in
Kentucky
and
California
for the three
months ended November 30, 2015 and November 30, 2014 are set forth in the table
below:
Three Months Ended
November 30, 2015 November 30, 2014
Kentucky - Twin Bottoms Field (BOE) $ 6.67 $
6.12
California - East Slopes Project (BOE) $ 9.42 $
13.42
Aggregate production expenses (BOE) $ 7.94 $
9.40
For the three months ended November 30, 2015, exploration and drilling expenses
increased $2,394 or 32.5% to $9,756 in comparison to $7,362 for the three months
ended November 30, 2014. Exploration and drilling expenses represented 2.1% of
total operating expenses for the three months ended November 30, 2015.
For the three months ended November 30, 2015, DD&A expenses increased $7,096 or
5.3% to $141,969 in comparison to $134,873 for the three months ended November
30, 2014. The increase in DD&A is directly related to the recognition of
$34,744 in property impairment in
California
offset by lower hydrocarbon
production volumes in both
Kentucky
and
California
. On a BOE basis, DD&A and
impairment represented $17.99 and $14.75 per barrel for the three months ended
November 30, 2015 and 2014, respectively. DD&A expenses represented 30.7% of
total operating expenses for the three months ended November 30, 2015.
For the three months ended November 30, 2015, G&A expenses increased $18,317 or
8.0% to $248,357 in comparison to $230,040 for the three months ended November
30, 2014. We received, as Operator in
California
, administrative overhead
reimbursement of $13,322 during the three months ended November 30, 2015 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 53.7% of total operating expenses for the three months ended November 30, 2015.
Interest income for the three months ended November 30, 2015 decreased $39,836
or 10.5% to $339,096 in comparison to $378,932 for the three months ended
November 30, 2014 due to reduced loan balances on the Note receivable from App
Energy.
23
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Interest expense for the three months ended November 30, 2015 increased $263,684
or 36.7% to $982,270 in comparison to $718,586 for the three months ended
November 30, 2014. The increase in interest expense is directly related to the
modified loan payment terms on our credit facility with Maximilian. The credit
facility activity is discussed further in the discussion of the Maximilian
Credit Facility - Amended and Restated Loan Agreement in the MD&A section of
this 10-Q report under Capital Resources and Liquidity - Cash Flow Provided by
(Used in) Financing Activities, Non-current Debt (Long-term Borrowings).
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 dependent upon both hydrocarbon production levels and the price we receive for hydrocarbon sales.
Since June of 2014, there has been a significant decline in the WTI price of crude oil and subsequently in the realized price we receive from oil sales.
This decline in the price of crude oil has had a substantial negative impact on our cash flow from both our
Kentucky
and
California
properties. Production expenses will fluctuate according to the number and percentage ownership of producing wells that we own. 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 ongoing goal of the Company is to improve cash flow to cover the
current level of G&A expenses and to fund our development drilling programs in
California
and
Kentucky
.
Capital Resources and Liquidity
Our primary financial resource is our proven oil reserves base. Our ability to
fund any future capital expenditure programs is dependent upon the prices we
receive from oil sales, the success of our exploration and development program
in
Lawrence County, Kentucky
and
Kern County, California
and the availability of
capital resource financing.
The Company has engaged an investment banking firm to assist in securing refinancing of its debt at more favorable terms and implement our development plans in
California
and
Kentucky
.
Changes in our capital resources at November 30, 2015 in comparison to February 28, 2015 are set forth in the table below:
Increase Percentage
November 30, 2015 February 28, 2015 (Decrease) Change
Cash $ 108,646 $ 496,772 $ (388,126) (78.1%)
Current Assets $ 1,354,327 $ 2,554,519 $ (1,200,192) (47.0%)
Total Assets $ 10,874,253 $ 12,313,061 $ (1,438,808) (11.7%)
Current Liabilities $ 7,205,479 $ 8,311,541 $ (1,106,062) (13.3%)
Total Liabilities $ 17,941,058 $ 17,497,651 $ 443,407 2.5%
Working Capital Deficit $ (5,851,152) $ (5,757,022) $ (94,130) (1.6%)
Our working capital deficit decreased $94,130 or 1.6% to $5,851,152 at November
30, 2015 in comparison to $5,757,022 at February 28, 2015. This decrease in the
working capital deficit was due to reclassification of part of the current
portion of the Maximilian credit facility debt to non-current debt due to a loan
modification with Maximilian during the nine months ended November 30, 2015.
While we have ongoing positive cash flow from our operations in
California
and
Kentucky
we have not yet been able to generate sufficient cash flow to cover all
of our G&A and interest expense requirements on a consistent basis.
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 and equity
markets, as well as select asset sales. While we have achieved positive cash
flow from operations in
Kentucky
and
California
, we will have to rely on these
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 oil and natural gas
producing properties, and stabilized hydrocarbon prices, which may very likely
require us to continue to raise equity or debt capital from outside sources.
24
--------------------------------------------------------------------------------
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 decline of hydrocarbon
prices, may restrict our ability to obtain needed capital.
The Company's financial statements for the nine months ended November 30, 2015
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.
Since entering the oil and gas exploration industry, we have mostly incurred
quarterly net losses. As of November 30, 2015, we have an accumulated deficit
of $30,087,731 and a working capital deficit of $5,851,152 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 both
Kentucky
and
California
. The Company has engaged an investment banking firm to assist in
securing refinancing of its debt under more favorable terms and implement its
development plans in
California
and
Kentucky
. We plan to obtain financing
through 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. Sales of
interests in our assets may be another source of cash flow.
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 Nine Months Increase Percentage
November 30, 2015 November 30, 2014 (Decrease) Change
Net cash provided by (used in)
operating activities $ (438,547) $ 254,645 $ (693,192) (272.2%)
Net cash provided by (used in)
investing activities $ 670,237 $ (3,387,719) $ 4,057,956 119.8%
Net cash provided by (used in)
financing activities $ (619,816) $ 3,153,669 $ (3,773,485) (119.7%)
Cash Flow Provided by (Used In) Operating Activities
Cash flow from operating activities is derived from the production of our 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, 2015, we had a cash flow deficit in operating
activities of $438,547 in comparison to cash flow provided by operating
activities of $254,645 for the nine months ended November 30, 2014. This
decline in operating cash flow of 693,192 or 272.2% is directly related to lower
realized hydrocarbon revenues from the sharp decline of approximately 64% in
crude oil prices since June of 2014. Non-cash account balances relating to
DD&A; amortization of debt discount and deferred financing costs accounted for a
represented $820,338 in aggregate for the nine months ended November 30, 2015.
Changes in our receivables, prepaids and payables balances accounted for a net
increase of approximately $623,330 in our cash flow, but were offset by the
increase in the net loss of approximately $1.9 million for the nine months ended
November 30, 2015. Variations in cash flow from operating activities may impact
our level of exploration and development expenditures.
Cash Flow Provided by (Used in) Investing Activities
Cash flow from investing activities is derived from changes in oil and gas
property balances and our lending activities associated with the App Energy
loan. Cash flow provided by investing activities for the nine months ended
November 30, 2015 was $670,237, a change of $4,057,956 from the $3,387,719 used
in investing activities for the nine months ended November 30, 2014. This
change of $4,057,956 was due to less drilling activity because of lower
hydrocarbon prices and reduced lending to App Energy for the nine months ended
November 30, 2015. The credit facility and our lending activity to App Energy
is discussed further in the MD&A section of this 10-Q report under the caption
"Long-Term Borrowings - Maximilian Credit Facility."
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 used in our financing activities was $619,816 for the nine
months ended November 30, 2015 in comparison to cash flow provided by our
financing activities of approximately $3.2 million for the nine months ended
November 30, 2014. This change of $3,773,485 was due to less drilling activity
because of lower hydrocarbon prices for the nine months ended November 30, 2015
resulting in less borrowing through our credit facility with Maximilian. The
credit facility and our lending activity to App Energy is discussed further in
the MD&A section of this 10-Q report discussed further in the discussion of the
25
--------------------------------------------------------------------------------
Maximilian Credit Facility - Amended and Restated Loan Agreement in the MD&A
section of this 10-Q report under Capital Resources and Liquidity - Cash Flow
Provided by (Used in) Financing Activities, Non-current Debt (Long-term
Borrowings) in this MD&A.
The following discussion is a summary of cash flows provided by, and used in, the Company's financing activities at November 30, 2015.
Current Debt (Short-Term Borrowings)
Related Party
During the years ended February 29, 2012 and February 28, 2013, the Company's
President and Chief Executive Officer loaned the Company $250,100 in aggregate
that was used for a variety of corporate purposes including an escrow
requirement on a loan commitment; extension fees on third party loans; and, a
reduction of principal on the Company's 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.
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 our President and
Chief Executive Officer. At November 30, 2015, the Line of Credit had an
outstanding balance of $853,136. Interest is payable monthly at a stated
reference rate of 0.249% + 337.5 basis points and totaled $28,770 for the nine
months ended November 30, 2015. The reference rate is based on the 30 day LIBOR
("London Interbank Offered Rate") and is subject to change from UBS.
Non-current Debt (Long-Term Borrowings)
12% Subordinated Notes
The Company's 12% Subordinated Notes ("the Notes") were issued pursuant to a
March 2010 private placement (of which $250,000 was issued to a related party)
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. The note principal of $565,000 is payable in full at
the amended maturity 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 Company's common stock at a conversion rate equal to 75% of the average
closing price of the Company's common stock over the 20 consecutive trading days
preceding December 31, 2016.
12% Notes balances at November 30, 2015 and February 28, 2015 are set forth in
the table below:
November 30, 2015 February 28, 2015
12% Subordinated Notes $ 315,000 $ 315,000
12% Subordinated Notes, related party 250,000 250,000
$ 565,000 $ 565,000
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 exercise price of
$0.14 and an amended expiration date of January 29, 2017. The 12% Note warrants
that have been exercised are set forth in the table below.
Shares of Number of
Warrants Common Stock Accredited
Fiscal Period Exercised Issued Investors
Year Ended February 28, 2014 100,000 100,000 1
Year Ended February 28, 2015 50,000 50,000 1
Nine Months Ended November 30, 2015 - - -
Totals 150,000 150,000 2
26
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Maximilian Credit Facility
On October 31, 2012, the Company entered into a loan agreement with Maximilian,
which provided for a revolving credit facility of up to $20 million, maturing on
October 31, 2016, with a minimum commitment of $2.5 million. The loan had
annual interest of 18% and a monthly commitment fee of 0.5%. The Company also
granted Maximilian a 10% working interest in its share of the oil and natural
gas leases in
Kern County, California
. The relative fair value of this 10%
working interest amounting to $515,638 was recognized as a debt discount and is
being amortized over the term of the loan. Amortization expense was $100,896
for the nine months ended November 30, 2015. Unamortized debt discount amounted
to $103,168 at November 30, 2015.
In 2012, the Company also issued 2,435,517 warrants to third parties who
assisted in the closing of the loan. The warrants have an exercise price of
$0.044; contain a cashless exercise provision; have piggyback registration
rights; and are exercisable for a period of five years expiring on October 31,
2017. The fair value of the warrants, as determined by the Black-Scholes option
pricing model, was $98,084 and included the following assumptions: a risk free
interest rate of 0.72%; stock price of $0.04, volatility of 153.44%; and a
dividend yield of 0.0%. The fair value of the warrants was recognized as a
financing cost and is being amortized as a part of deferred financing cost over
the term of the loan. As of November 30, 2015, 316,617 of these warrants remain
unexercised.
Maximilian Credit Facility - Amended and Restated Loan Agreement
In connection with the Company's acquisition of a working interest from App in
the Twin Bottoms Field in
Lawrence County, Kentucky
, the Company amended its
loan agreement with Maximilian on August 28, 2013. The amended loan agreement
provided for an increase in the revolving credit facility from $20 million to
$90 million and a reduction in the annual interest rate from 18% to 12%. The
monthly commitment fee of 0.5% per month on the outstanding principal balance
remained unchanged. Advances under the amended loan agreement will mature on
August 28, 2017. The obligations under the amended loan agreement continue to
be secured by a perfected first priority security interest in substantially all
of the personal property of the Company, and a mortgage on the Company's leases
in
Kern County, California
. The amended loan agreement also provided for the
revolving credit facility to be divided into two borrowing sublimits. The first
borrowing sublimit is $50 million and is for borrowing by the Company, primarily
for its ongoing oil and natural gas exploration and development activities.
The
second borrowing sublimit, of $40 million, is for loans to be extended by the
Company, as lender, to App, as borrower pursuant to a Loan and Security
Agreement entered into between the Company and App on August 28, 2013 (See Note
8 - Note Receivable).
The amended loan agreement contains customary covenants for loan of such type,
including among other things, covenants that restrict the Company's ability to
make capital expenditures, incur indebtedness, incur liens and dispose of
property. The amended loan agreement also contains various events of default,
including failure to pay principal and interest when due, breach of covenants,
materially incorrect representations and bankruptcy or insolvency. If an event
of default occurs, all of the Company's obligations under the amended loan
agreement could be accelerated by Maximilian, causing all loans outstanding
(including accrued interest and fees payable thereunder) to be declared
immediately due and payable.
As consideration for Maximilian facilitating the Company's transactions with App
and entering into the amended loan agreement, the Company (a) issued to
Maximilian approximately 6.1 million common shares, representing 9.99% of the
Company's outstanding common stock on a fully-diluted basis at the time of
grant, and (b) issued approximately 6.1 million warrants to purchase shares of
the Company's common stock representing the right to purchase up to an
additional 9.99% of the Company's outstanding common stock on a fully-diluted
basis, calculated as of the date of grant. The warrants have an exercise price
of $0.10; contain a cash exercise provision and are exercisable for a period of
three years expiring on August 28, 2016; and contain an exercise blocker
provision that prevents any exercise of the warrants if such exercise and
related issuance of common stock would increase the Maximilian holdings of the
Company's common stock to more than 9.99% of the Company's currently issued and
outstanding shares at the time of the exercise. The Company also granted to
Maximilian a 50% net profits interest in the Company's 25% working interest,
after the Company recovers its investment, in the Company's working interest in
its
Kentucky
acreage, pursuant to an Assignment of Net Profits Interest entered
into as of August 28, 2013 by and between the Company and Maximilian.
On May 28, 2014 at Maximilian's request, the Company finalized a
share-for-warrant exchange agreement in which Maximilian returned to the Company
427,729 common shares and was in turn issued the same number of warrants
containing the same provisions as the originally issued warrants. This
share-for-warrant exchange occurred so that Maximilian would hold no more than
9.99% of the Company's common shares issued and outstanding. The Company
determined that the share-for-warrant exchange did not result in any incremental
fair value.
27
--------------------------------------------------------------------------------
On August 21, 2014, the Company entered into a First Amendment to Amended and
Restated Loan and Security Agreement and Share Repurchase Agreement (the "First
Amendment") with Maximilian. The First Amendment secured for the Company an
additional advance of $2,200,000 under its credit facility with Maximilian since
the advances made by Maximilian had already exceeded its minimum funding
commitment. Additionally, Maximilian agreed to temporarily decrease the required
monthly payment made by the Company until it has paid $1,000,000 less than the
principal payments required by the previous agreement. Furthermore, Maximilian
agreed to reduce the regular interest rate applicable to the loan from 12% per
annum to 9% per annum and the default interest rate by 3%.
The additional advance, the reduction in the required monthly payment and the
reduction in the interest rate were facilitated through the company's
acquisition of 5,694,823 shares of our common stock held by Maximilian. The
repurchased shares were cancelled and restored to the status of authorized, but
unissued stock. The Company paid for the share repurchase transaction through
an advance of $1,708,447 under the existing loan agreement with Maximilian.
On May 20, 2015, the Company entered into a Second Amendment to Amended and Restated Loan and Security Agreement (the "Second Amendment") with Maximilian.
The Second Amendment modified the calculation of the required monthly payment
for a three-month period ending June 30, 2015. As consideration for entering
into the loan modification, the Company agreed to lower the exercise price of
the warrants Maximilian currently holds from $0.10 to $0.04. No other terms of
the warrant agreement were changed.
On October 14, 2015, the Company entered into a Third Amendment to the Amended
and Restated Loan and Security Agreement and Second Warrant Amendment with
Maximilian, (the "Third Amendment"). Pursuant to the Third Amendment,
Maximilian agreed to a reduction in the Company's monthly payments under the
loan agreement to $50,000 per month for a period of six months ending on
February 29, 2016. The reduction in monthly payments allows for additional
funds to be used by the Company in drilling and completing additional wells in
Kentucky
. As consideration for the reduction in the monthly payment amount, the
Company agreed that twenty percent of the amount by which the monthly payment
was reduced would be added to the loan balance, and the portion of the monthly
payment savings that constitutes savings in interest or commitment fees would be
treated as an additional advance of principal under the loan agreement (the
"Deemed Advances"). The Company also agreed to grant to Maximilian an
overriding royalty interest of 1.5% of its working interest in four wells in
Kentucky
. As part of the Third Amendment, the Company also agreed to extend the
expiration date of the warrants held by Maximilian to purchase up to 6,550,281
shares of common stock of the Company to August 28, 2018. The Company
determined that the modification of the warrant expiration date did not result
in any incremental fair value.
With the assistance of Maximilian, the Company is currently working with an
investment banking firm to assist in securing refinancing of its debt with
Maximilian, since the long-term commitment needed to develop the
Kentucky
and
California
projects no longer fits the Maximilian business model. Maximilian is
continuing to work with the Company in modifying the credit facility terms
during this period of lower hydrocarbon prices.
Current debt balances at November 30, 2015 and February 28, 2015 are set forth
in the table below:
November 30, 2015 February 28, 2015
Maximilian note $ 3,419,074 $ 4,823,325
Maximilian note discount (103,168) (132,114)
$ 3,315,906 $ 4,691,211
Non-current debt balances at November 30, 2015 and February 28, 2015 are set
forth in the table below:
November 30, 2015 February 28, 2015
Maximilian note $ 10,138,706 $ 8,663,458
Maximilian note discount - (71,951)
$ 10,138,706 $ 8,591,507
App Loan Agreement
In connection with amending and restating its loan agreement with Maximilian, on
August 28, 2013 the Company extended to App Energy, LLC, a
Kentucky
limited
liability company ("App Energy") a credit facility for the development of a
shallow oil project in an existing natural gas field in
Lawrence County, Kentucky
pursuant to a Loan and Security Agreement between the Company as lender
and App Energy as borrower (the "App Loan Agreement").
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The App Loan Agreement provides for a revolving credit facility of up to $40
million, maturing on August 28, 2017, with a minimum commitment of $2.65 million
(the "Initial Advance"). All funds advanced to App Energy, as borrower, by
Daybreak, as lender, are to be borrowed by Daybreak under its Amended Loan
Agreement with Maximilian. The Initial Advance bears interest at a rate per
annum equal to 16.8%, and subsequent loans under the Loan Agreement bear
interest at a rate per annum equal to 12%. The App Loan Agreement also provides
for a monthly commitment fee of 0.6% per month of the outstanding principal
balance of the loans. The obligations under the App Loan Agreement are secured
by a perfected first priority security interest in substantially all of the
assets of App Energy, including the App Energy leases in
Lawrence County, Kentucky
.
The proceeds of the initial borrowing by App Energy of $2.65 million under the
App Energy facility were primarily used to (a) pay loan fees and closing costs,
(b) repay indebtedness and (c) finance the drilling of three wells by App Energy
in the Twin Bottoms Field in
Lawrence County, Kentucky
in which the Company has
a 25% working interest. Future advances under the facility will primarily be
used for oil and natural gas exploration and development activities.
The App Loan Agreement contains customary covenants for loan of such type,
including, among other things, covenants that restrict App Energy's ability to
make capital expenditures, incur indebtedness, incur liens and dispose of
property. The App Loan Agreement also contains various events of default,
including failure to pay principal and interest when due, breach of covenants,
materially incorrect representations and bankruptcy or insolvency. If an event
of default occurs, all of App Energy's obligations under the App Loan Agreement
could be accelerated by the Company, causing all loans outstanding (including
accrued interest and fees payable thereunder) to be declared immediately due and
payable.
In connection with the App Loan Agreement, App Energy also granted to the
Company a 25% working interest in approximately 6,400 acres (currently 7,300
acres) in two large contiguous blocks in the Twin Bottoms Field in
Lawrence County, Kentucky
and entered into a corresponding promissory note and a
Mortgage, Leasehold Mortgage, Assignment of Production, Security Agreement and
Financing Statement, both dated as of August 28, 2013. App Energy's manager,
John A. Piedmonte, Jr., also entered into a limited Indemnity Agreement in
connection with the loan. The loans under the App Loan Agreement are also
guaranteed by certain of App Energy's affiliates.
In connection with entering into the Third Amendment with Maximilian, the
Company concurrently entered into a Third Amendment to Loan and Security
Agreement with App Energy (the "App Amendment"), which amended the Company's
loan agreement with App Energy in which the Company, as lender, lends to App
Energy, as borrower, a portion of the advances it receives pursuant to its loan
agreement with Maximilian. The App Amendment provides for a reduction in
interest rate and a reduction in monthly payments to be made by App Energy to
the Company for the same payment cycles as the reduced payment to be made by the
Company under the Maximilian Amendment. The reduction in monthly payments by
App Energy will allow App Energy to fund its share of drilling and completing
additional wells in
Kentucky
with the Company. As consideration for the
reduction in the monthly payment amount, App Energy agreed that certain amounts
will be treated as additional advances under the App Energy loan agreement, and
that it would fund a portion of the Company's drilling and development expenses
with respect to two wells. App Energy also agreed to grant to Maximilian an
overriding royalty interest on the same terms as the overriding royalty interest
agreed to by the Company.
Note receivable balances at November 30, 2015 and February 28, 2015 are set
forth in the table below:
November 30, 2015 February 28, 2015
Note receivable - current $ 642,540 $
1,320,944
Note receivable - non-current 3,738,296 3,429,056
$ 4,380,836 $ 4,750,000
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 economic downturn, may
restrict our ability to obtain needed capital.
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Encumbrances
The Company's debt obligations, pursuant to the loan agreement with Maximilian,
are secured by a perfected first priority security interest in substantially all
of the personal property of the Company, and a mortgage on our leases in
Kern County, California
encompassing the Sunday, Bear, Black, Ball and Dyer Creek
properties. For further information on the loan agreement refer to the
discussion of the Maximilian Credit Facility - Amended and Restated Loan
Agreement in the MD&A section of this 10-Q report under Capital Resources and
Liquidity - Cash Flow Provided by (Used in) Financing Activities, Non-current
Debt (Long-term Borrowings) in this MD&A.
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, 2015, a total of 3,000,000 shares of restricted stock had been
awarded and remained outstanding under the 2009 Plan, with 2,986,220 shares
having fully vested. A total of 1,013,780 common stock shares remained
available at August 31, 2015 for issuance pursuant to the 2009 Plan. A summary
of the 2009 Plan issuances is set forth in the table below:
Shares
Grant Shares Vesting Shares Shares Outstanding
Date Awarded Period Vested(1) Returned(2) (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, 2015, the Company did not recognize any
stock compensation expense related to the above restricted stock grants since
all issuances have been fully amortized.
Management Plans to Continue as a Going Concern
We continue to implement plans to enhance Daybreak's ability to continue as a
going concern. The Company currently has a net revenue interest in 20 producing
wells in its East Slopes Project located in
Kern County, California
(the "East
Slopes Project"). The revenue from these wells has created a steady and
reliable source of revenue. The Company's average working interest in these
wells is 36.6% with an average net revenue interest of 28.5% for these same
wells. Additionally, Daybreak currently has a net revenue interest in 14
producing horizontal oil wells in the Twin Bottoms Field in
Lawrence County, Kentucky
. Our average working interest in these 14 wells is 22.6% with an
average net revenue interest of 19.7%.
We anticipate revenues will continue to increase as the Company participates in
the drilling of more wells in
Kentucky
and
California
. Daybreak plans to
continue its development drilling program at a rate that is compatible with its
cash flow, funding opportunities and hydrocarbon prices.
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The Company's sources of funds in the past have included the debt and equity
markets and select asset sales. The Company has experienced revenue growth from
its oil properties, however, it has not yet established a consistent 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 the Company cannot offer any assurance that the Company
will be successful in executing the aforementioned plans to continue as a going
concern.
Critical Accounting Policies
Refer to Daybreak's Annual Report on Form 10-K for the fiscal year ended February 28, 2015.
Off-Balance Sheet Arrangements
As of November 30, 2015, 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.
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