During the nine months ended November 30, 2010, a total of 60,000 warrants
were issued as part of the 12% Subordinated Note private placement, while prior
to the fiscal year end of February 28, 2010, 1,130,000 warrants were issued,
leading to a total issuance of 1,190,000 warrants as part of the 12%
Subordinated Notes private placement as discussed in Note 6 above.
Additionally during the nine months ended November 30, 2010, 150,000
warrants were issued to a consultant as payment for services rendered. These
warrants have an exercise price of $0.14 and expire on April 16, 2015. The fair
value of the warrants, as determined by the Black-Scholes option pricing model,
was $14,600 using the following assumptions: a risk free interest rate of
2.49%; volatility of 143.5%; and dividend yield of 0.0%.
No warrants were exercised or expired during the period. As of November
30, 2010 and February 28, 2010, there were 9,966,695 and 9,756,695 warrants
issued and outstanding, respectively.
The outstanding warrants as of November 30, 2010, have a weighted
average exercise price of $1.60; a weighted average remaining life of 1.39
years; and an intrinsic value of $-0-.
NOTE 11
RESTRICTED STOCK and RESTRICTED
STOCK UNIT PLAN
On April 6, 2009, the
Board of Directors (the Board)
of the Company approved the 2009 Restricted Stock and Restricted Stock Unit
Plan (the 2009 Plan) allowing the executive officers, directors, consultants
and employees of the Company and its affiliates to be eligible to receive
restricted stock and restricted stock unit awards. Subject to adjustment, the
total number of shares of the Companys 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.
On July 22, 2010, a total of 25,000 restricted shares were granted to
the five non-employee directors, as approved by the Compensation Committee of
the Board. These restricted shares were granted under the Companys director
compensation plan and pursuant to the 2009 Plan and fully vest equally over a
period of three years or upon the retirement of the director from the Board.
On July 22, 2010, a total of 425,000 restricted shares of the Companys
common stock were granted to five employees of the Company, as approved by the
Compensation Committee of the Board. These restricted shares were granted
pursuant to the 2009 Plan and fully vest equally over a period of four years.
At November 30, 2010, a total of 1,000,000 shares remained available
for issuance pursuant to the 2009 Plan. A summary of the 2009 Plan issuances is
shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant
Date
|
|
Shares
Awarded
|
|
Vesting
Period
|
|
Shares
Vested
|
|
Shares
Outstanding
(Unvested)
|
|
|
|
|
|
|
|
|
|
|
|
4/7/2009
|
|
|
1,900,000
|
|
|
3
Years
|
|
|
633,331
|
|
|
1,266,669
|
|
7/16/2009
|
|
|
25,000
|
|
|
3
Years
|
|
|
8,330
|
|
|
16,670
|
|
7/16/2009
|
|
|
625,000
|
|
|
4
Years
|
|
|
156,250
|
|
|
468,750
|
|
7/22/2010
|
|
|
25,000
|
|
|
3
Years
|
|
|
0
|
|
|
25,000
|
|
7/22/2010
|
|
|
425,000
|
|
|
4
Years
|
|
|
0
|
|
|
425,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,000,000
|
|
|
|
|
|
797,911
|
|
|
2,202,089
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the nine months ended November 30, 2010 and 2009, the Company
recognized compensation expense related to the above restricted stock grants of
$65,704, and $57,255, respectively. Unamortized compensation expense amounted
to $156,100 as of November 30, 2010.
12
NOTE 12
INCOME TAXES
Reconciliation between actual tax expense (benefit) and income taxes
computed by applying the U.S. federal income tax rate and state income tax
rates to income from continuing operations before income taxes is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
November 30, 2010
|
|
|
|
Nine Months Ended
November 30, 2009
|
|
|
|
|
|
|
|
|
|
|
Computed at U.S. and state
statutory rates (40%)
|
|
|
$
|
(482,725
|
)
|
|
|
$
|
(722,951
|
)
|
Permanent differences
|
|
|
|
37,979
|
|
|
|
|
10,417
|
|
Changes in valuation
allowance
|
|
|
|
444,746
|
|
|
|
|
712,534
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
$
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred liabilities are presented
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
November 30, 2010
|
|
|
|
February 28, 2010
|
|
|
|
|
|
|
|
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
|
$
|
5,812,210
|
|
|
|
$
|
5,114,269
|
|
Oil and gas properties
|
|
|
|
(130,133
|
)
|
|
|
|
123,062
|
|
Less valuation allowance
|
|
|
|
(5,682,077
|
)
|
|
|
|
(5,237,331
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
$
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At November 30, 2010, the Company had estimated net operating loss
carryforwards for federal and state income tax purposes of approximately
$14,530,525 which will begin to expire, if unused, beginning in 2024. The
valuation allowance increased approximately $444,746 for the nine months ended
November 30, 2010 and increased by $891,047 for the year ended February 28,
2010. Section 382 of the Internal Revenue Code places annual limitations on the
Companys net operating loss (NOL) carryforward.
The above estimates are based on managements decisions concerning
elections which could change the relationship between net income and taxable
income. Management decisions are made annually and could cause the estimates to
vary significantly.
NOTE 13
COMMITMENTS AND CONTINGENCIES
Various lawsuits, claims and other contingencies arise in the ordinary
course of the Companys business activities. At the current time, the Company
is not involved in any lawsuits or claims. While the ultimate outcome of any
future contingency is not determinable at this time, management believes that
any liability or loss resulting therefrom will not materially affect the
financial position, results of operations or cash flows of the Company.
The Company, as an owner or lessee and operator of oil and gas
properties, is subject to various federal, state and local laws and regulations
relating to discharge of materials into, and protection of, the environment.
These laws and regulations may, among other things, impose liability on the
lessee under an oil and gas lease for the cost of pollution clean-up resulting
from operations and subject the lessee to liability for pollution damages. In
some instances, the Company may be directed to suspend or cease operations in
the affected area. The Company maintains insurance coverage that is customary
in the industry, although the Company is not fully insured against all
environmental risks.
The Company is not aware of any environmental claims existing as of
November 30, 2010. There can be no assurance, however, that current regulatory
requirements will not change, or past non-compliance with environmental issues
will not be discovered on the Companys oil and gas properties.
13
IT
EM 2.
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
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.
Some statements contained in this Form 10-Q report relate to results or
developments that we anticipate will or may occur in the future and are not
statements of historical fact. All statements other than statements of
historical facts contained in this MD&A report are inherently uncertain and
are forward-looking statements. 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 statements about the following:
|
|
|
|
|
Our future operating results,
|
|
|
|
|
|
Our future capital expenditures,
|
|
|
|
|
|
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 gas properties,
|
|
|
|
|
|
Fluctuations in the levels of our oil and natural gas exploration and
development activities in a concentrated area,
|
|
|
|
|
|
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 laws, drilling industry legal change, climate change
legislation, and potential environmental liabilities,
|
|
|
|
|
|
Our ability to continue as a going concern,
|
|
|
|
|
|
Our ability to secure additional capital to fund operations, and
|
|
|
|
|
|
Other factors discussed elsewhere in this Form 10-Q and in our public
filings, press releases and discussions with Company management.
|
Should one or more of the risks or uncertainties described above or
elsewhere in this Form 10-Q occur, or should 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 a
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.
14
Introduction and Overview
The following MD&A is managements assessment of the historical
financial and operating results of the Company for the three and nine month
periods ended November 30, 2010 and November 30, 2009 and of our financial
condition as of November 30, 2010 and is intended to provide information
relevant to an understanding of our financial condition, changes in our
financial condition and results of operations and cash flows; and, should be
read in conjunction with our unaudited financial statements and notes included
elsewhere in this Form 10-Q and in our Annual Report on Form 10-K for the
fiscal year ended February 28, 2010. Unless otherwise noted, all of this
discussion refers to continuing operations in Kern County, California.
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 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 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.
Plan of Operation
Our longer-term success depends on, among many other factors, the
acquisition and drilling of commercial grade oil and 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 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 gas properties and funding projects that we
believe have the potential to produce oil or gas in commercial quantities. We
are in the process of developing a multi-well oilfield project in Kern County,
California and have participated in the drilling of eleven oil wells that have
achieved commercial production. This project is comprised of three project
areas: East Slopes, East Slopes North and the Expanded AMI project.
Kern County, California (East Slopes Project
and East Slopes North Project)
On September 17, 2010, we finalized the acquisition of an additional
16.67% working interest from another working interest owner in the East Slopes
Project. This additional working interest is anticipated to increase our
monthly revenue from the five wells affected by this purchase by 75.76% or
between $15,000 and $20,000. With this purchase our average net revenue
interest in Kern County, California has increased from 21.83% to 28.77%.
East Slopes Project.
The installation of permanent production
facilities and electrical power to service the wells in the Sunday, Bear and
Black property locations has been completed. Work is continuing on the
completion of electrical service to our production facilities at the Dyer Creek
Field location. Our 3-D seismic data evaluation is continuing and the
reprocessing of the data to enhance the quality of prospects is expected to
yield more than the current 8 to 10 exploration prospects already identified on
this acreage. Refer to the discussion below for additional information on our
producing properties in the East Slopes Project area.
The Company is now well positioned to expand its operations in the East
Slopes Project having found five reservoirs at our Bear, Sunday, Black, Ball
and Dyer Creek locations. The Sunday location is now fully developed with three
vertical wells and one horizontal well. At least one more development well is
planned for our Bear location. The Bear reservoir is believed to be much larger
than the Sunday reservoir. The Black reservoir is the smallest of the three
reservoirs, and we will most likely drill only one developmental well. The Dyer
Creek and Ball reservoirs were put on production in late October 2010. 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 Companys existing production
15
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 Property
In November 2008, we made our initial oil discovery drilling the Sunday
#1 well. The well was put on production in January 2009. Production is from the
Vedder sand at approximately 2,000 feet. During 2009, we drilled three
development wells including one horizontal well. The Sunday reservoir is now
fully developed and we have no other plans to drill any more wells in this
reservoir. With the acquisition of the additional 16.67% working interest in
the East Slopes Project in September 2010, we have a 41.67% working interest
with a 29.0% net revenue interest in the Sunday #1 well. We continue to have a
37.5% working interest with a 27% net revenue interest in each of the Sunday #2
and #3 wells. In the Sunday #4 well, we own a 37.5% working interest with a 30.1%
net revenue interest.
Bear Property
In February 2009, we made our second oil discovery drilling the Bear #1
well which is approximately one mile northwest of our Sunday discovery. The
well was put on production in May 2009. Production is from the Vedder sand at
approximately 2,200 feet. In December 2009, we began a development program by
drilling and completing the Bear #2 well. In April 2010, we successfully
drilled and completed the Bear #3 and the Bear #4 wells. We plan to drill at
least one more development well before the Spring of 2011. With the acquisition
of the additional 16.67% working interest in the East Slopes Project in
September 2010, we have a 41.67% working interest with a 29.0% net revenue
interest in each of the Bear wells in this property.
Black Property
The Black property was acquired through a farm-in arrangement with a
local operator. The Black location is just south of the Bear location on the
same fault system. During January 2010, we drilled the Black #1 well. The well
was completed and put on production in January 2010. Production is from the
Vedder sand at 2,150 feet. We have a 37.5% working interest with a 29.8% net
revenue interest at this property.
Sunday Central Processing and Storage
Facility
The oil produced from our acreage is considered heavy oil. The oil
ranges from 13º to 15º API gravity. All of our oil from the Sunday, Bear and
Black locations is processed, stored and sold from this facility. The oil must
be heated to separate and remove the 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. As a result, our average operating costs have been reduced from
over $40 per barrel to below $17 per barrel of oil after accounting for the
loss of certain oil processing credits that ceased with our purchase of an
additional 16.67% working interest in September 2010. By having this central
facility and permanent electrical power, it ensures that our operating expenses
are kept to a minimum.
Ball Property
The Ball #1-11 well was put on production in late October 2010. Our 3-D
seismic indicates approximately 40 acres of closure, similar in size to the
Bear Property. We are currently planning a development program for this
property. Production from the Ball #1-11 well is being processed at the Dyer
Creek production facility. We have a 41.67% working interest with a 34.69% net
revenue interest at this property.
Dyer Creek Property
The Dyer Creek #67X-11 well was also put on production in late October
2010. This well is producing from the 1
st
Vedder sand and is located
to the north of the Bear reservoir on the same trapping fault. We are currently
planning a development program for this property. Production from the Dyer
Creek #67X-11 well
16
is also being processed at the Dyer Creek production facility. We have
a 41.67% working interest with a 34.69% net revenue interest at this property.
Dyer Creek Processing and Storage Facility
The Dyer Creek Processing and Storage Facility serves the Dyer Creek
and Ball properties and includes previously abandoned infrastructure that we
have refurbished. We are currently in the process of installing electrical
service to this location. Once this is completed, our oil processing costs
should be significantly reduced. The oil produced into this facility has
similar API gravity to the oil at the Sunday production facility in that the
oil must be heated to separate and remove the water to prepare it to be sold.
Bull Run Prospect
This is an Etchegoin and Santa Margarita sand prospect with drilling
targets located between 800 and 1,200 feet deep. We plan to drill an
exploratory well on this prospect during the early part of 2011. Based on wells
drilled by previous operators and our recently reprocessed 3-D seismic data, we
estimate that the Bull Run Prospect is approximately 280 acres in size and has
oil pay thickness that ranges from 35 feet to 70 feet. The Bull Run wells will
require a pilot steam flood and additional production facilities.
Production, Revenue and LOE
The table below shows our net production volume, net revenue and net
lease operating expenses (LOE) by property location for the three months and
nine months ended November 30, 2010 and November 30, 2009 in Kern County,
California. Due to certain oil processing credits that we received from
December 2009 through August 2010, our overall production costs for the Sunday
#1 well and all four Bear wells during that time period were significantly less
than the overall production costs for the other Sunday wells and the Black #1
well. These oil processing credits ended September 1, 2010 with our acquisition
of a portion of another working interest owners interest in this project.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
Property
|
|
November 30, 2010
|
|
November 30, 2009
|
|
November 30, 2010
|
|
November 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
Sunday
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (Bbls)
|
|
|
1,751
|
|
|
1,545
|
|
|
5,267
|
|
|
3,968
|
|
Revenue
|
|
$
|
128,794
|
|
$
|
99,745
|
|
$
|
372,498
|
|
$
|
233,991
|
|
LOE Costs
|
|
$
|
22,319
|
|
$
|
42,546
|
|
$
|
52,045
|
|
$
|
108,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bear
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (Bbls)
|
|
|
1,364
|
|
|
292
|
|
|
3,011
|
|
|
822
|
|
Revenue
|
|
$
|
101,063
|
|
$
|
19,070
|
|
$
|
216,087
|
|
$
|
51,142
|
|
LOE Costs
|
|
$
|
11,056
|
|
$
|
11,694
|
|
$
|
11,065
|
|
$
|
66,937
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Black
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (Bbls)
|
|
|
292
|
|
|
|
|
|
825
|
|
|
|
|
Revenue
|
|
$
|
21,414
|
|
$
|
|
|
$
|
58,723
|
|
$
|
|
|
LOE Costs
|
|
$
|
3,845
|
|
$
|
|
|
$
|
11,117
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dyer Creek/Ball
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (Bbls)
|
|
|
101
|
|
|
|
|
|
101
|
|
|
|
|
Revenue
|
|
$
|
7,796
|
|
$
|
|
|
$
|
7,796
|
|
$
|
|
|
LOE Costs
|
|
$
|
11,236
|
|
$
|
|
|
$
|
11,236
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Infrastructure Costs
|
|
$
|
8,322
|
|
$
|
(2,119
|
)
|
$
|
20,246
|
|
$
|
14,765
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (Bbls)
|
|
|
3,508
|
|
|
1,836
|
|
|
9,204
|
|
|
4,791
|
|
Revenue
|
|
$
|
259,064
|
|
$
|
118,815
|
|
$
|
655,104
|
|
$
|
285,134
|
|
LOE Costs
|
|
$
|
56,778
|
|
$
|
52,121
|
|
$
|
105,709
|
|
$
|
190,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price
|
|
$
|
73.85
|
|
$
|
64.70
|
|
$
|
71.18
|
|
$
|
59.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average LOE Cost
|
|
$
|
16.19
|
|
$
|
28.39
|
|
$
|
11.49
|
|
$
|
39.75
|
|
17
For the nine months ended November 30, 2010, production on the Sunday
property was from four wells in comparison to three wells for the comparative
nine months ended November 30, 2009. The Bear property had production from two
wells for nine months and an additional two wells for seven months during the
nine months ended November 30, 2010 in comparison to one well for the nine
months ended November 30, 2009.
Initial production costs for the Dyer Creek and Ball properties were
higher than normal because of the generator rental and fuel costs in the place
of electricity. Once the installation of electrical service is completed to the
Dyer Creek Processing and Storage Facility, the production costs will be
significantly reduced and are anticipated to be similar to the wells on the
Sunday, Bear and Black properties on an average per well basis.
The table below shows our net sales volume, net revenue and net LOE for
all California properties for the last five quarterly periods ended November
30, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
November 30, 2010
|
|
Three Months
Ended
August 31, 2010
|
|
Three Months
Ended
May 31, 2010
|
|
Three Months
Ended
February 28, 2010
|
|
Three Months
Ended
November 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (Bbls)
|
|
|
3,508
|
|
|
2,976
|
|
|
2,720
|
|
|
2,690
|
|
|
1,836
|
|
Revenue
|
|
$
|
259,064
|
|
$
|
202,987
|
|
$
|
193,051
|
|
$
|
184,224
|
|
$
|
118,815
|
|
LOE Costs
|
|
$
|
56,778
|
|
$
|
19,514
|
|
$
|
30,393
|
|
$
|
23,815
|
|
$
|
52,121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price
|
|
$
|
73.85
|
|
$
|
68.21
|
|
$
|
70.97
|
|
$
|
68.48
|
|
$
|
64.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average LOE Cost
|
|
$
|
16.18
|
|
$
|
6.56
|
|
$
|
11.17
|
|
$
|
8.85
|
|
$
|
28.39
|
|
As evidenced in the table above, quarterly LOE costs have generally
declined since the start-up of our production facilities during the quarter
ended November 30, 2009, even with the increased production resulting from the
additional wells that have been drilled since November 2009. Certain oil
processing credits that we were receiving on the Sunday #1 well and the four
Bear wells had been recorded as a reduction of production costs for those five
wells. These oil processing credits began in December 2009 and ended on
September 1, 2010.
East Slopes North Project.
As part of the sale
of a 25% working interest by us in May 2009 to a group of Texas companies, we
acquired a 25% working interest in a 14,100 acre Seismic Option Area
immediately to the north of our East Slopes Project area. We are considering
plans to acquire a seismic survey over that area in 2011.
Tulare County, California (Expanded AMI
Project)
Expanded AMI Project.
This project in Tulare
County, California is also located in the San Joaquin Basin. Since 2006,
Daybreak and its partners have leased approximately 9,000 acres. Three prospect
areas have been identified to the north of the East Slopes Project and East
Slopes North Project areas in Kern County. A 3-D seismic survey over the
prospect area is required before any exploration drilling can be done. We
currently have a 50% working interest in this project area.
Three Months Ended November 30, 2010 compared
to the Three Months Ended November 30, 2009 - Continuing Operations
The following discussion compares our results for the three month
periods ended November 30, 2010 and November 30, 2009. In December 2009, we
ended our involvement in the Krotz Springs Project in Louisiana. Unless otherwise
referenced, these operating results only cover our continuing operations at the
East Slopes Project in Kern County, California.
Revenues.
Revenues
are derived entirely from the sale of our share of oil production. We realized
the first revenues from producing wells in California during February 2009. For
the three months ended November
18
30, 2010, oil revenues from continuing operations were $259,064 in
comparison to $118,815 for the three months ended November 30, 2009. This
represents an increase of $140,249 or 118.0%.
The revenues for the three months ended November 30, 2010 were from
eleven producing wells in California. The Ball #1-11 and Dyer Creek #67X-11
wells, located on the Ball and Dyer Creek properties, were put into production in late
October 2010. Our net share of production was 3,508 and 1,836 barrels with an
average price of $73.85 and $64.70 per barrel for the three months ended
November 30, 2010 and November 30, 2009, respectively. A table of our revenues
follows:
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
November 30, 2010
|
|
Three Months
Ended
November 30, 2009
|
|
|
|
|
|
|
|
California - East Slopes Project
|
|
$
|
259,064
|
|
$
|
118,815
|
|
Louisiana - Krotz Springs
|
|
|
-0-
|
|
|
666
|
|
|
|
|
|
|
|
Total Revenues
|
|
$
|
259,064
|
|
$
|
119,481
|
|
Costs and Expenses.
Operating
expenses for the three months ended November 30, 2010 increased by $73,211 or
12.6% compared to the three months ended November 30, 2009. A significant
decrease of $60,048 or 26.6% occurred in exploration & drilling and
depreciation, depletion and amortization (DD&A) costs, but this was
offset by an increase of $132,233 or 44.5% in general and administrative
(G&A) costs. Production costs and bad debt expense for the three months
ended November 30, 2010 remained relatively unchanged in comparison to the
three months ended November 30, 2009.
A table of our costs and expenses for the three months ended November
30, 2010 and November 30, 2009 follows:
|
|
|
|
|
|
|
|
|
|
November 30, 2010
|
|
November 30, 2009
|
|
|
|
|
|
|
|
Production Costs
|
|
$
|
56,778
|
|
$
|
52,121
|
|
Exploration and Drilling
|
|
|
18,938
|
|
|
52,542
|
|
DD&A
|
|
|
146,651
|
|
|
173,095
|
|
Bad debt expense
|
|
|
1,119
|
|
|
4,750
|
|
G&A
|
|
|
429,483
|
|
|
297,250
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses
|
|
$
|
652,969
|
|
$
|
579,758
|
|
Production costs include costs directly associated with the generation
of oil and gas revenues, road maintenance and well workover costs. For the
three months ended November 30, 2010, these costs increased by $4,657 or 8.9%
compared to the three months ended November 30, 2009. The increase in
production costs is directly related to the number of producing wells in the
two comparative periods. For the three months ended November 30, 2010 we had
eleven producing wells, nine of which produced for the entire three month
period. The other two wells were put on production in late October 2010. In the
three months ended November 30, 2009 we had four producing wells in California.
Production costs for the two wells that were put on production in October 2010
are currently higher than they will be once electrical service installation is
completed to the wells and associated production facilities. The oil processing
credits that we were receiving for five wells using the Sunday Central
Processing and Storage Facility ended September 1, 2010 and this also
contributed to higher production costs at this facility. Production costs
represented 8.7% of total operating expenses.
Exploration and drilling costs include geological and geophysical
(G&G) costs as well as leasehold maintenance costs and dry hole expenses.
For the three months ended November 30, 2010 these costs decreased $33,604 or
64.0%, in comparison to the three months ended November 30, 2009. Exploration
costs decreased primarily because of fewer leases and the timing of when
certain leases became due to renewal dates on the leases. Exploration and
drilling costs represented 2.9% of total operating expenses.
DD&A of equipment costs, proven reserves and property costs along
with impairment are another component of operating expenses. DD&A expenses
decreased $26,444 or 15.3% for the three months ended
19
November 30, 2010 compared to the three months ended November 30, 2009.
DD&A represented 22.4% of total operating expenses.
Bad debt expense decreased $3,631 or 76.4% for the three months ended
November 30, 2010 in comparison to the three months ended November 30, 2009.
Bad debt expense represented 0.2% of total operating expenses.
G&A expenses, including management and employee salaries, legal and
accounting expenses, director fees, stock compensation, investor relations
fees, travel expenses, insurance, Sarbanes-Oxley (SOX) compliance expenses
and other administrative costs for the three months ended November 30, 2010
increased $132,233 or 44.5%, compared to the three months ended November 30,
2009. G&A expenses were higher in legal, accounting, advertising &
marketing and fundraising costs for the three months ended November 30, 2010.
Management and employee salaries, director fees and stock compensation
decreased by $6,270 or 2.9%. Travel and associated costs decreased by $10,010
or 61.9% for the three months ended November 30, 2010. For the three months
ended November 30, 2009, we received, as Operator, administrative overhead
reimbursement of approximately $26,318 for the East Gilbertown Field in Alabama
which was used to directly offset certain employee salaries. Since we are no
longer involved in this project there was no corresponding offset to employee
salaries for the three months ended November 30, 2010. We are continuing a
program of reducing all of our G&A costs wherever possible. G&A costs
represented 65.8% of total operating expenses from continuing operations.
Interest income for the three months ended November 30, 2010 decreased
$1,776 or 86.9% compared to the three months ended November 30, 2009, due to
lower average cash balances.
Interest expense for the three months ended November 30, 2010 increased
$57,328 compared to the three months ended November 30, 2009, due to
amortization of the debt discount and interest on the 12% Subordinated Notes
that were sold from January 2010 through March 2010 and amortization of loan
origination fees and the fair value of the net profits interest associated with
the $750,000 note payable from the acquisition of the additional working
interest in Kern County, California.
Due to the nature of our business, as well as the relative immaturity
of the Company, 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. Production costs will fluctuate according to the number and
percentage ownership of producing wells, as well as the amount of revenues
being contributed by such wells. 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 and impairment costs will depend upon
the factors cited above. G&A costs will also fluctuate based on our current
requirements, but will generally tend to increase as we expand the business
operations of the Company.
Three Months Ended November 30, 2010 compared
to the Three Months Ended November 30, 2009 - Discontinued Operations
Alabama (East Gilbertown Field)
On March 19, 2010, we closed the sale of our interest in the East
Gilbertown Field to a third party with an effective date of March 1, 2010. The
cost and expense information for the three months ended November 30, 2010
reflect certain credits that result in this information being additions to
revenue rather than deductions from revenue. Prior period income statement
amounts applicable to the East Gilbertown Field have been reclassified and
included under Income (loss) from discontinued operations. Because of the low
prices for oil in prior periods, we had previously fully impaired our
capitalized cost in this property.
20
The following table presents the revenues and expenses related to the
East Gilbertown Field for the three month periods ended November 30, 2010 and
November 30, 2009.
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
November 30, 2010
|
|
Three Months
Ended
November 30, 2009
|
|
|
|
|
|
|
|
Oil sales revenue
|
|
$
|
|
|
$
|
19,213
|
|
Cost and expenses
|
|
|
60
|
|
|
29,083
|
|
|
|
|
|
|
|
|
|
Income (loss) from
discontinued operations
|
|
$
|
60
|
|
$
|
(9,870
|
)
|
Nine Months Ended November 30, 2010 compared
to the Nine Months Ended November 30, 2009 - Continuing Operations
The following discussion compares our results for the nine month
periods ended November 30, 2010 and November 30, 2009. Unless otherwise
referenced, these results only cover our continuing operations at the East
Slopes Project in Kern County, California.
Revenues.
Revenues
are derived entirely from the sale of our share of oil production. For the nine
months ended November 30, 2010, oil and gas revenues from continuing operations
were $759,121 in comparison to $286,900 for the nine months ended November 30,
2009. This represents an increase of $472,221 or 164.6%.
The revenues for the nine months ended November 30, 2010 include a
special one-time revenue adjustment in regards to the Krotz Springs well in
Louisiana. The revenue adjustment of $104,017 represented additional gas
revenue from May 2007 through December 2009. In Kern County, California, our
net share of production was 9,204 and 4,791 barrels of oil with an average price
per barrel of $71.18 and $59.52 for the nine months ended November 30, 2010 and
November 30, 2009, respectively. A table of our revenues follows:
|
|
|
|
|
|
|
|
|
|
Nine Months
Ended
November 30, 2010
|
|
Nine Months
Ended
November 30, 2009
|
|
|
|
|
|
|
|
California - East Slopes
Project
|
|
$
|
655,104
|
|
$
|
285,133
|
|
Louisiana - Krotz Springs
|
|
|
104,017
|
|
|
1,767
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
$
|
759,121
|
|
$
|
286,900
|
|
Costs and Expenses.
Total
operating expenses for the nine months ended November 30, 2010 decreased by
$225,382 or 10.7% compared to the nine months ended November 30, 2009.
Significant decreases occurred in production costs, DD&A and bad debt
expense in comparison to the nine months ended November 30, 2009. These
decreases were offset by an increase in G&A costs for the nine months ended
November 30, 2010. Exploration and drilling showed a slight increase for the
nine months ended November 30, 2010 in comparison to the nine months ended
November 30, 2009.
A table of our costs and expenses for the nine months ended November
30, 2010 and November 30, 2009 follows:
|
|
|
|
|
|
|
|
|
|
Nine Months
Ended
November 30, 2010
|
|
Nine Months
Ended
November 30, 2009
|
|
|
|
|
|
|
|
Production Costs
|
|
$
|
105,709
|
|
$
|
244,394
|
|
Exploration and Drilling
|
|
|
163,221
|
|
|
156,468
|
|
DD&A
|
|
|
383,708
|
|
|
525,680
|
|
Gain on Write-Off of Asset Retirement Obligation
|
|
|
(8,324
|
)
|
|
|
|
Bad debt expense (recovery)
|
|
|
(3,928
|
)
|
|
81,439
|
|
G&A
|
|
|
1,234,423
|
|
|
1,092,210
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses
|
|
$
|
1,874,809
|
|
$
|
2,100,191
|
|
21
Production costs for the nine months ended November 30, 2010 decreased
by $138,685 or 56.7% compared to the nine months ended November 30, 2009
primarily because of the completion of our production facilities. Production
costs represented 5.6% of total operating expenses.
Exploration and drilling costs increased by $6,753 or 4.3% for the nine
months ended November 30, 2010 compared to the nine months ended November 30,
2009 primarily because of higher leasing costs on lease renewals. Exploration
and drilling costs represented 8.7% of total operating expenses.
DD&A and impairment expenses for the nine months ended November 30,
2010 decreased $141,972 or 27.0% compared to the nine months ended November 30,
2009. This decrease was due to extra impairment charges being recognized in
California for the nine months ended November 30, 2009. DD&A costs
represented 20.5% of total operating expenses.
Bad debt expense decreased $85,367 for the three months ended November
30, 2010 in comparison to the three months ended November 30, 2009. This
decrease was primarily from the recognition of a third party bad debt related
to the Krotz Springs project in Louisiana during the nine months ended November
30, 2009.
G&A expense increased $142,213, or 13.0%, for the nine months ended
November 30, 2010 compared to the nine months ended November 30, 2009.
Reductions were realized in the areas of travel and associated costs as well as
shareholder services. Legal expenses increased $39,922 primarily due to costs
associated with the 12% Subordinated notes and our acquisition of additional
working interest in California during the nine months ended November 30, 2010.
Management and employee salaries, director fees and stock compensation also
decreased by $19,557 or 2.9% for the three months ended November 30, 2010. For
the nine months ended November 30, 2009, we received, as Operator,
administrative overhead reimbursement of approximately $76,279 for the East
Gilbertown Field in Alabama which was used to directly offset certain employee
salaries. Since we are no longer involved in this project there was no
corresponding offset to employee salaries for the nine months ended November
30, 2010. We are continuing to reduce our G&A expenses wherever possible.
G&A costs represented 65.8% of total operating expenses.
Interest income for the nine months ended November 30, 2010 decreased
$9,965 or 83.7% compared to the nine months ended November 30, 2009 due to
lower average cash balances.
Interest expense increased $103,226 for the nine months ended November
30, 2010 compared to the nine months ended November 30, 2009 due to
amortization of debt discount and interest on the 12% Subordinated Notes that
were sold from January 2010 through March 2010 and amortization of loan
origination fees and the fair value of the net profit interest associated with
the $750,000 note payable from the acquisition of the additional working
interest in Kern County, California.
Nine Months Ended November 30, 2010 compared
to the Nine Months Ended November 30, 2009 - Discontinued Operations
Alabama (East Gilbertown Field)
Prior period income statement amounts applicable to the East Gilbertown
Field have been reclassified and included under Income (loss) from discontinued
operations. The cost and expense information for the nine months ended November
30, 2010 reflect certain credits that result in this information being
additions to revenue rather than deductions from revenue. Because of the low
prices for oil in prior periods, we had previously fully impaired our
capitalized cost in this property.
22
The following table presents the revenues and expenses related to the
East Gilbertown Field for the nine month periods ended November 30, 2010 and
November 30, 2009.
|
|
|
|
|
|
|
|
|
|
Nine Months
Ended
November 30, 2010
|
|
Nine Months
Ended
November 30, 2009
|
|
|
|
|
|
|
|
Oil sales revenue
|
|
$
|
|
|
$
|
62,418
|
|
Cost and expenses
|
|
|
731
|
|
|
67,557
|
|
|
|
|
|
|
|
|
|
Income (loss) from
discontinued operations
|
|
$
|
731
|
|
$
|
(5,139
|
)
|
Liquidity and Capital Resources
Our primary financial resource is our oil reserves base. Our ability to
fund a future capital expenditure program is dependent upon the level of prices
we receive from oil sales; the success of our exploration and development
program in Kern County, California; and the availability of capital resource
financing. Factors such as changes in operating margins and the availability of
capital resources could increase or decrease our ultimate level of expenditures
during the next fiscal year.
The Companys financial statements for the nine months ended November
30, 2010 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 inception and as of November 30,
2010 have an accumulated deficit of $22,397,971, which raises substantial doubt
about our ability to continue as a going concern.
For the last two years, we have been working to reposition Daybreak to
better meet our corporate goals and objectives by selling our interest in
projects that were not contributing to the strategic growth of the Company.
These projects included the Saxet Deep Field in Texas and the East Gilbertown
Field in Alabama. Additionally, we have discontinued participation in the KSU
#59 well in the Krotz Springs Field in St. Landry Parish, Louisiana. These
actions have allowed us to improve cash flow and move forward with the current
exploration and development program in Kern County, California.
We are continuing to pursue funding alternatives, including, but not
limited to, debt or equity securities, to fund the development of the East
Slopes Project. However no assurance can be given that we will be able to
obtain any additional financing on favorable terms, if at all.
The changes in our capital resources at November 30, 2010 compared with
February 28, 2010 are:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
November 30, 2010
|
|
February 28, 2010
|
|
Increase
(Decrease)
|
|
Percentage
Change
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
123,425
|
|
$
|
247,951
|
|
$
|
(124,526
|
)
|
|
(50.2
|
%)
|
Current Assets
|
|
$
|
806,427
|
|
$
|
1,070,541
|
|
$
|
(264,114
|
)
|
|
(24.7
|
%)
|
Total Assets
|
|
$
|
3,404,537
|
|
$
|
3,010,036
|
|
$
|
394,501
|
|
|
13.1
|
%
|
Current Liabilities
|
|
$
|
2,762,871
|
|
$
|
1,388,339
|
|
$
|
1,374,532
|
|
|
99.0
|
%
|
Total Liabilities
|
|
$
|
3,328,364
|
|
$
|
1,896,601
|
|
$
|
1,431,763
|
|
|
75.5
|
%
|
Working Capital
|
|
$
|
(1,956,444
|
)
|
$
|
(317,798
|
)
|
$
|
(1,638,646
|
)
|
|
(515.6
|
%)
|
Our working capital decreased $1,638,646 from ($317,798) as of February
28, 2010 to ($1,956,444) as of November 30, 2010. This decrease in working
capital was principally due to the drilling activity that has occurred during
the nine months ended November 30, 2010; the continuing reduction in the $1.5
million debt we assumed when we acquired the additional 25% working interest in
California in March 2009; and meeting ongoing financial commitments reflected
in our G&A costs. As of November 30, 2010, approximately $334,213 was
remaining to be paid from the default of our previous partners in California
and is included in the accounts payable balance.
23
During the nine months ended November 30, 2010, we reported an
operating loss of approximately $1,115,688 as compared with an operating loss
of approximately $1,813,291 from the comparative nine month period ended
November 30, 2009. This decrease in the operating loss of approximately
$697,603 or 38.5% from the comparative nine months ended November 30, 2009 was
achieved by increasing revenue and lowering operating costs. Revenue increased
due to both an increase in production and an improvement in the sales price of
oil. We increased production by 4,413 barrels of oil or 92.1% through sales
from eleven producing wells in comparison to sales from four producing wells in
the nine months ended November 30, 2009. The average price of oil increased by
$11.66 to $71.18 per barrel or 19.6% for the nine months ended November 30,
2010 in comparison to the nine months ended November 30, 2009.
Operating expenses decreased by 10.7% or $225,382 to $1,874,809 from
$2,100,191 for the nine months ended November 30, 2010 and 2009, respectively.
Production costs and DD&A expenses experienced the greatest reductions with
a combined reduction of 36.4% or $280,657. This reduction was offset by an
increase in G&A expenses for the nine months ended November 30, 2010.
Cash Flows
Our sources of funds in the past have included the debt or equity
markets and, while we have positive cash flow from our oil and gas properties,
we have not yet established positive cash flow on a company-wide basis. We will
need to rely on the debt or equity private or public markets, if available, to
fund future operations. Our business model is focused on acquiring exploration
and development properties and also acquiring existing producing properties.
Our ability to generate future revenues and operating cash flow will depend on
successful exploration and/or acquisition of oil and gas producing properties,
which may very likely require us to continue to raise equity or debt capital
from outside sources, if available.
Our expenditures consist primarily of exploration and drilling costs;
production costs; geological and engineering services and acquiring mineral
leases. Additionally, our expenses also consist of consulting and professional
services, employee compensation, legal, accounting, travel and other G&A
expenses which we have incurred in order to address necessary organizational activities.
The net funds provided by and (used in) each of our operating,
investing and financing activities are summarized in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
November 30, 2010
|
|
Nine Months Ended
November 30, 2009
|
|
Increase
(Decrease)
|
|
Percentage
Change
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used
in) operating activities
|
|
$
|
109,069
|
|
$
|
(2,315,663
|
)
|
$
|
2,424,732
|
|
|
104.7
|
%
|
Net cash provided by (used
in) investing activities
|
|
$
|
(1,013,595
|
)
|
$
|
348,410
|
|
$
|
(1,362,005
|
)
|
|
(390.9
|
%)
|
Net cash provided by
financing activities
|
|
$
|
780,000
|
|
|
|
|
$
|
780,000
|
|
|
100.0
|
%
|
Cash Flow Provided by (Used in) Operating
Activities
Cash flow from operating activities is derived from the production of
our oil and gas reserves and changes in the balances of receivables, payables
or other non-oil property asset account balances. For the nine months ended
November 30, 2010, we had a positive cash flow from operating activities of
$109,069, in comparison to a negative cash flow of ($2,315,663) for the nine
months ended November 30, 2009. This change of $2,424,732 was the result of an
increase in oil revenues; a reduction in operating expenses; increased
collections of outstanding receivable amounts; and refund of Operator bonds
from states we are no longer operating in. 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 and other assets account balances. Cash used in investing
activities for the nine months ended November 30, 2010 was ($1,013,595), an
increase of $1,362,005 from the $348,410 provided by investing activities for
the nine months ended
24
November 30, 2009. This change was primarily from the increase in our
oil and gas property balances resulting from the successful drilling of four
wells and the increase in our working interest in five currently producing
wells all in Kern County, California offset by our receipt of proceeds on the
sale of the additional 25% working interest in California (acquired from
certain defaulting working interest partners) during the nine months ended
November 30, 2009.
Cash Flow Provided by Financing Activities
Cash flow from financing activities is derived from changes in equity
account balances excluding retained earnings or changes in long-term liability
account balances. Cash flow provided by financing activities increased by
$780,000 for the nine months ended November 30, 2010, whereas no financing
activity occurred in comparative nine months ended November 30, 2009. This
change for the nine months ended November 30, 2010 is from funds received
through the sale of the $30,000 portion of the 12% Subordinated Notes in a
private placement during the nine months ended November 30, 2010 and the
financing we received for the purchase of the additional working interest in
Kern County, California.
Daybreak has ongoing capital commitments to develop all of its oil and
gas 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. A major source of capital for Daybreak in the past has
been through the sale of debt or equity securities in the private or public
markets. The debt or equity markets, if available to us, will continue to be
capital sources for Daybreak until sustained positive cash flow has been
achieved. The current uncertainty in the credit and capital markets, may
restrict our ability to obtain needed capital.
12% Subordinated Notes
On March 16, 2010 we closed a private placement of 12% Subordinated
Notes (the Notes) resulting in total gross proceeds of $595,000. A total of
$250,000 Notes were sold to a related party, the Companys President and Chief
Executive Officer. The terms and conditions of the related party Note were
identical to the terms and conditions of the other participants Notes. The
Notes are subject to an annual interest rate of 12%, payable semi-annually, and
mature on January 29, 2015. On the maturity date, the Company may 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 prior to December 31, 2014.
Proceeds from the sale of the notes were used to meet operating expenses and
fund a portion of our development drilling program in Kern County, California.
This offering of securities was made pursuant to a private placement held under
Regulation D promulgated under the Securities Act of 1933, as amended.
One-Year Note Payable
On September 17, 2010, we exercised a preferential right to acquire an
additional 16.67% working interest in our East Slopes Project from another
working interest owner. We financed the additional working interest purchase by
issuing, to a third party, a one-year convertible secured promissory note for
the principal amount of $750,000 (the Loan), subject to an annual interest
rate of 10% per annum, which was prepaid at closing. The third party may
convert up to 50% of the unpaid principal balance into the Companys common
stock at a conversion price of $0.16 per share at any time prior to the Loan
being paid in full.
We also issued 250,000 shares of the Companys common stock to the third party
as a loan origination fee. The fair value of these shares amounted to $23,750
which were deferred and amortized over the term of the Loan. Amortization
expense for the nine months ended November 30, 2010 amounted to $5,938.
The Loan is secured by a Mortgage, Deed of Trust, Assignment of
Production, Security Agreement and Financing Statement on the Sunday and Bear
leases in our East Slope Project. Furthermore, as a condition precedent to
the Loan, we entered into a Technical and Consulting Services Agreement with
the third party,
25
whereby we will provide operating, engineering and technical consulting
to the third party for a one-year period for the purpose of evaluating 22 wells
in Hutchinson County, Texas for the third party. After six months, Daybreak, at
its sole discretion, will have the right to obtain a 10% working interest in
the 22 wells in Hutchinson County, Texas at no additional cost.
As additional consideration for the Loan we executed an Assignment of
Net Profits Interest in favor of the third party, whereby we assigned two
percent of the net profits realized by us on our leases in the East Slopes
Project. The fair value of the two percent net profits interest was determined
to be $60,210 and has been recognized as a discount to the debt. The debt
discount is amortized over the term of the Loan. Amortization expense for the
nine months ended November 30, 2010 amounted to $15,053.
Changes in Financial Condition and Results of
Operations
Cash Balance
We maintain our cash balance by increasing or decreasing our
exploration and drilling expenditures as limited by availability of cash from
operations and investments. Our cash balances were $123,425 and $247,951 as of
November 30, 2010 and February 28, 2010, respectively. The decrease of
approximately $124,526 was due to the costs of drilling of four additional
wells in the nine months ended November 30, 2010; payment of outstanding
invoices acquired from certain original partners default; and payment of
ongoing LOE and G&A expenses incurred through normal operations of the
Company.
Operating Loss
During the nine months ended November 30, 2010, we reported an
operating loss of approximately $1,115,688 compared with an operating loss of
approximately $1,813,291 from the comparative nine month period ended November
30, 2009. This decrease of approximately $697,603 or 38.5% in the operating
loss was a result of increased revenue from oil sales and lower operating
expenses than in the comparative nine month period ended November 30, 2009.
Net Loss
Since entering the oil and gas exploration industry, we have incurred
recurring losses with negative cash flow and have depended on external
financing and the sale of oil and gas assets to sustain our operations. A net
loss of $1,206,809 was reported for the nine months ended November 30, 2010,
compared to a net loss of $1,807,377 for the nine months ended November 30,
2009. The decrease in net loss of $600,568 or 33.2% for the nine months ended
November 30, 2010 was primarily due to an increase of $472,221 in revenue
generated from oil sales; and a reduction of $225,382 in operating expenses in
comparison to the nine months ended November 30, 2009.
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 stock and
restricted stock unit awards. Subject to adjustment, the total number of shares
of Daybreaks 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.
26
Restricted stock and restricted stock units also enhance our ability to
attract and retain the services of qualified individuals.
On July 22, 2010, a total of 25,000 restricted shares were granted to
the five non-employee directors, as approved by the Compensation Committee of
the Board. These restricted shares were granted under the Companys director
compensation plan and pursuant to the 2009 Plan and fully vest equally over a
period of three years or upon the retirement of the Director from the Board.
On July 22, 2010, a total of 425,000 restricted shares of the Companys
common stock were granted to five employees of the Company, as approved by the
Compensation Committee of the Board. These restricted shares were granted
pursuant to the 2009 Plan and generally vest equally over a period of four
years.
At November 30, 2010, a total of 1,000,000 shares remained available
for issuance pursuant to the 2009 Plan. A summary of the 2009 Plan issuances is
shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Grant
Date
|
|
Shares
Awarded
|
|
Vesting
Period
|
|
Shares
Vested
|
|
Shares
Outstanding
|
|
|
|
|
|
|
|
4/7/2009
|
|
|
1,900,000
|
|
|
3
Years
|
|
|
633,331
|
|
|
1,266,669
|
|
7/16/2009
|
|
|
25,000
|
|
|
3
Years
|
|
|
8,330
|
|
|
16,670
|
|
7/16/2009
|
|
|
625,000
|
|
|
4
Years
|
|
|
156,250
|
|
|
468,750
|
|
7/22/2010
|
|
|
25,000
|
|
|
3
Years
|
|
|
0
|
|
|
25,000
|
|
7/22/2010
|
|
|
425,000
|
|
|
4
Years
|
|
|
0
|
|
|
425,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,000,000
|
|
|
|
|
|
797,911
|
|
|
2,202,089
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three and nine months ended November 30, 2010, the Company
recognized compensation expense related to the above restricted stock grants of
$22,805 and $65,704, respectively. Unamortized compensation expense amounted to
$156,100 as of November 30, 2010.
Summary
We are continuing to execute the Companys business plan of developing
Daybreaks acreage position in Kern County, California. The production and
operating infrastructure is now in place and operating. We will continue to
focus our efforts on drilling development wells, as well as drilling several exploration
wells over the next twelve months; which, coupled with the completion of our
production and operating infrastructure and with the expectation for higher oil
prices, will increase our net cash flow.
We anticipate the need to obtain funds for our future exploration and
development activities 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. We are pursuing financing alternatives; however no assurance can
be given that we will be able to obtain any additional financing on favorable
terms, if at all.
Critical Accounting Policies
Refer to Daybreaks Annual Report on Form 10-K for the fiscal year
ended February 28, 2010.
Off-Balance Sheet Arrangements
As of November 30, 2010, 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.
27
I
TEM 3. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
As a smaller reporting company, we are not required to provide the
information otherwise required by this Item.
IT
EM 4T. CONTROLS
AND PROCEDURES
Managements
Evaluation of Disclosure Controls and Procedures
As of the end of the reporting period, November 30, 2010, an evaluation
was conducted by Daybreak management, including our President and Chief Executive
and interim principal finance and accounting officer, as to the effectiveness
of the design and operation of our disclosure controls and procedures pursuant
to Rule 13a-15(e) of the Exchange Act. Such disclosure controls and procedures
are designed to ensure that information required to be disclosed by a company
in the reports that it files under the Exchange Act is recorded, processed,
summarized and reported within required time periods specified by the SEC rules
and forms. Additionally, it is vital that such information is accumulated and
communicated to our management including our President and Chief Executive
Officer, in a manner to allow timely decisions regarding required disclosures.
Based on that evaluation, our management concluded that our disclosure controls
were effective as of November 30, 2010.
Changes in Internal
Control over Financial Reporting
There have not been any changes in the Companys internal control over
financial reporting during the three months ended November 30, 2010 that have
materially affected, or are reasonably likely to materially affect, the
Companys internal control over financial reporting.
Limitations
Our management does not expect that our disclosure controls or internal
controls over financial reporting will prevent all errors or all instances of
fraud. A control system, no matter how well designed and operated, can provide
only reasonable, not absolute, assurance that the control systems objectives
will be met. Further, the design of a control system must reflect the fact that
there are resource constraints, and the benefits of controls must be considered
relative to their costs.
Because of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all control issues
and instances of fraud, if any, within our company have been detected. These
inherent limitations include the realities that judgments in decision-making
can be faulty, and that breakdowns can occur because of simple error or
mistake. Controls can also be circumvented by the individual acts of some
persons, by collusion of two or more people, or by management override of the
controls. The design of any system of controls is based in part upon certain
assumptions about the likelihood of future events, and any design may not
succeed in achieving its stated goals under all potential future conditions.
Over time, controls may become inadequate because of changes in
conditions or deterioration in the degree of compliance with policies or
procedures. Because of the inherent limitation of a cost-effective control
system, misstatements due to error or fraud may occur and not be detected.
28
P
ART II
OTHER INFORMATION
I
TEM 1. LEGAL
PROCEEDINGS
None.
I
TEM 1A. RISK
FACTORS
The following risk factor updates the Risk Factors included in our Form
10-K for the fiscal year ended February 28, 2010. Except as set forth below,
there have been no material changes to the risks described in Part I, Item 1A,
of the Form 10-K for the fiscal year ended February 28, 2010.
The amount of our outstanding indebtedness
continues to increase and our ability to make payments towards such
indebtedness could have adverse consequences on future operations.
Our outstanding indebtedness at November 30, 2010 was $1,345,000, which
constituted the $750,000 Loan and the $595,000 principal amount outstanding on
the Notes. Our level of indebtedness affects our operations in a number of
ways. The Notes and the secured convertible promissory note governing our Loan
contain covenants resulting in a substantial portion of our cash flow from
operations to be dedicated to the payment of interest on our indebtedness.
Accordingly, these funds will not be available for other purposes, such as
future exploration, development or acquisition activities. Our ability to meet
our debt service obligations and reduce our total indebtedness will depend upon
our future performance. Our future performance, in turn, is dependent upon many
factors that are beyond our control such as general economic, financial and
business conditions. We cannot guarantee that our future performance will not
be adversely affected by such economic conditions and financial, business and
other factors.
The $750,000 Loan is secured by a Mortgage, Deed of Trust, Assignment
of Production, Security Agreement and Financing Statement on the Sunday and
Bear leases in the Companys East Slopes Project. If the Company were to
default on this Loan, the Company would lose two of its primary leases.
I
TEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
On October 26, 2010 and November 16, 2010, the Company issued 120,000
and 60,000 shares of common stock, respectively, to accredited investors
pursuant to the terms of a Daybreak private placement offering held in July
2006, during which the accredited investors received shares of Daybreak Series
A Convertible Preferred Stock, the terms of which are disclosed in the
Companys Amended and Restated Articles of Incorporation. The Series A
Convertible Preferred Stock can be converted by the shareholder at any time
into three shares of the Companys common stock. Pursuant to the terms of the
Series A Convertible Preferred Stock, the common stock was issued to the
accredited investors upon the conversion of 40,000 and 20,000 shares of Series
A Convertible Preferred Stock by the accredited investors, respectively, in
reliance on an exemption from registration provided by Section 3(a)(9) of the
Securities Act of 1933 relating to securities exchanged by the issuer with its
existing security holders exclusively where no commission or other remuneration
is paid or given directly or indirectly for soliciting such exchange.
As of November 30, 2010, there have been 29 accredited investors
convert 483,200 Series A Convertible Preferred shares into 1,449,600 shares of
Daybreak common stock. At November 30, 2010, there were 916,565 Series A
Convertible Preferred shares outstanding, held by accredited investors that had
not been converted into the Companys common stock. The table below shows the
conversions of Series A
29
Convertible Preferred that have occurred since the Series A Convertible
Preferred was first issued in July 2006.
|
|
|
|
|
|
|
|
|
|
|
Fiscal Period
|
|
Shares of Series
A Preferred
Converted to
Common Stock
|
|
Shares of
Common Stock
Issued from
Conversion
|
|
Number of
Accredited
Investors
|
|
|
|
|
|
|
|
|
|
Year Ended February 29,
2008
|
|
|
102,300
|
|
|
306,900
|
|
|
10
|
|
Year Ended February 28,
2009
|
|
|
237,000
|
|
|
711,000
|
|
|
12
|
|
Year Ended February 28,
2010
|
|
|
51,900
|
|
|
155,700
|
|
|
4
|
|
Nine Months Ended November
30, 2010
|
|
|
92,000
|
|
|
276,000
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
483,200
|
|
|
1,449,600
|
|
|
29
|
|
On September 17, 2010, the Company exercised a preferential right to
acquire an additional 16.67% working interest in its East Slopes Project from
another working interest owner. The Company financed the additional working
interest by issuing, to an accredited third party, a one-year convertible
secured promissory note. The Company agreed to pay the third party a loan
origination fee equal to 250,000 shares of the Companys common
stock within 60 days after September 17, 2010. These shares were issued on
October 8, 2010. The closing price of the Companys common stock on September
17, 2010 was $0.095 and the stock issuance was valued at $23,750. The shares
were issued in reliance on an exemption from registration provided by Section
4(2) of the Securities Act of 1933, as amended.
30
I
TEM 6. EXHIBITS
The following Exhibits are filed as part of the report:
|
|
|
Exhibit
Number
|
|
Description
|
|
|
|
10.1
(1)
|
|
Secured Convertible Promissory Note, dated September 17, 2010, by and
between Daybreak Oil and Gas, Inc. and Well Works, LLC.
|
|
|
|
10.2
(1)
|
|
Mortgage, Deed of Trust, Assignment of Production, Security Agreement
and Financing Statement, dated September 17, 2010, by and between Daybreak
Oil and Gas, Inc., as mortgagor, and Well Works, LLC, as trustee and
beneficiary.
|
|
|
|
10.3
(1)
|
|
Technical and Consulting Services Agreement, dated September 17,
2010, by and between Daybreak Oil and Gas, Inc. and Well Works, LLC.
|
|
|
|
10.4
(1)
|
|
Assignment of Net Profits Interest, dated September 17, 2010, by and
between Daybreak Oil and Gas, Inc., as assignor, and Well Works, LLC, as
assignee.
|
|
|
|
10.5
(2)
|
|
Asset Purchase and Sale Agreement with Chevron U.S.A. Inc., effective
July 1, 2010.
|
|
|
|
10.6
(2)
|
|
Assignment of Oil and Gas Leases and Agreements among Chevron U.S.A.
Inc., as assignor, and Daybreak Oil and Gas, Inc. and San Joaquin
Investments, Inc., as assignees, effective July 1, 2010.
|
|
|
|
10.7
(2)
|
|
Bill of Sale among Chevron U.S.A. Inc., as seller, and Daybreak Oil
and Gas, Inc. and San Joaquin Investments, Inc., as buyers, effective July 1,
2010.
|
|
|
|
31.1
(3)
|
|
Certification of principal executive and principal financial officer
as required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
32.1
(3)
|
|
Certification of principal executive and principal financial officer
as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
|
(1)
|
Previously
filed as exhibits to Form 8-K on September 23, 2010, and incorporated by
reference herein.
|
|
|
|
|
(2)
|
Previously
filed as exhibits to Form 10-Q on October 15, 2010, and incorporated by
reference herein.
|
|
|
|
|
(3)
|
Filed
herewith.
|
31
S
IGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
|
|
|
|
|
DAYBREAK OIL
AND GAS, INC.
|
|
By:
|
/s/ JAMES F.
WESTMORELAND
|
|
|
|
|
|
|
|
James F. Westmoreland, its
|
|
|
President, Chief Executive Officer and
interim
|
|
|
principal finance and accounting officer
|
|
|
(Principal Executive
Officer, Principal Financial
|
|
|
Officer and Principal Accounting Officer)
|
|
|
|
Date:
January 13, 2011
|
32
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