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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Delta Oil and Gas Inc New (CE) | USOTC:DLTA | OTCMarkets | Common Stock |
Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 0.0001 | 0.00 | 01:00:00 |
Colorado
|
91-210350
|
|
(State or other jurisdiction of incorporation or organization)
|
(I.R.S. Employer Identification No.)
|
|
Suite 604 - 700 West Pender Street, Vancouver, British Columbia Canada, V6C 1G8
|
||
(Address of principal executive offices) (Zip Code)
|
||
Registrant’s telephone, including area code:
(866) 355-3644
|
Common Stock, $0.001 par value
|
Not Applicable
|
(Title of class)
|
(Name of each exchange on which registered)
|
Large accelerated filer
¨
|
Accelerated filer
¨
|
Non-accelerated filer
¨
(Do not check if a smaller reporting company)
|
Smaller reporting company
ý
|
Page
|
|||
3
|
|||
PART I
|
|||
Item 1.
|
Business
.
|
4
|
|
Item 1A.
|
10
|
||
Item 1B.
|
17
|
||
Item 2.
|
17
|
||
Item 3.
|
23
|
||
Item 4.
|
23
|
||
PART II
|
|||
Item 5.
|
24
|
||
Item 6.
|
25
|
||
Item 7.
|
26
|
||
Item 7A.
|
29
|
||
Item 8.
|
30
|
||
Item 9.
|
30
|
||
Item 9A.
|
30
|
||
Item 9B.
|
30
|
||
PART III
|
|||
Item 10.
|
31
|
||
Item 11.
|
31
|
||
Item 12.
|
31
|
||
Item 13.
|
31
|
||
Item 14.
|
31
|
||
PART IV
|
|||
Item 15.
|
32
|
||
·
|
risk that we will not be able to remediate identified material weaknesses in our internal control over financial reporting;
|
·
|
changes in our business strategy;
|
·
|
the uncertainty of reserve estimates and timing of development expenditures;
|
·
|
access and availability of materials, equipment, supplies, labor and supervision, power and water;
|
·
|
results of current and future exploration activities;
|
·
|
results of pending and future feasibility studies;
|
·
|
accidents and labor disputes;
|
·
|
disappointing results from our exploration or development efforts;
|
·
|
failure to meet our revenue or profit goals or operating budget;
|
·
|
decline in demand for our common stock;
|
·
|
changes in general market conditions;
|
·
|
investor perception of our industry or our prospects;
|
·
|
technological changes in the oil and gas exploration industry, including technological innovations by competitors or in competing technologies;
|
·
|
the proximity of natural gas production to natural gas pipelines;
|
·
|
the availability of pipeline capacity;
|
·
|
the demand for oil and natural gas by utilities and other end users;
|
·
|
the availability of alternate fuel sources;
|
·
|
the effect of inclement weather, such as hurricanes;
|
·
|
changes in oil and gas exploration, processing and overhead costs;
|
·
|
unexpected changes in business and economic conditions;
|
·
|
changes in interest rates and currency exchange rates;
|
·
|
commodity price fluctuations, including changes in the worldwide price for oil and gas;
|
·
|
state and federal regulation of oil and natural gas marketing;
|
·
|
federal regulation of natural gas sold or transported in interstate commerce; and
|
·
|
local and community impacts and issues.
|
·
|
Significant undeveloped reserves;
|
·
|
Close proximity to developed markets for oil and natural gas; and
|
·
|
Existing infrastructure or the ability to install our own infrastructure of oil and natural gas pipelines and production platforms.
|
Net Revenue Distribution
|
||
Before Payout
|
After Payout
|
|
Well #1
|
36%
|
20%
|
Well #2
|
36%
|
24%
|
Well #3
|
36%
|
24%
|
Well Name
|
Year ended
Dec 31, 2013
|
Year ended
Dec 31, 2012
|
||||||
Donner #1
|
$ | 243,614 | $ | 245,496 | ||||
Donner #2
|
$ | 120,097 | $ | 73,990 |
Well Name
|
Year ended
Dec 31, 2013
|
Year ended
Dec 31, 2012
|
||||||
Miss Gracie #1-18
|
$ | 30,089 | $ | 54,298 | ||||
Joe Murray Farms
|
$ | 9,020 | $ | 43,429 |
|
•
|
future production rates based on historical performance and expected future operating and investment activities;
|
|
•
|
future oil and gas prices and quality and location differentials; and
|
|
•
|
future development and operating costs.
|
·
|
Commodity prices.
Economic producibility of reserves is now based on the unweighted, arithmetic average of the closing price on the first day of the month for the 12-month period prior to fiscal year end, unless prices are defined by contractual arrangements;
|
·
|
Undeveloped oil and gas reserves.
Reserves may be classified as “proved undeveloped” for undrilled areas beyond one offsetting drilling unit from a producing well if there is reasonable certainty that the quantities will be recovered;
|
·
|
Reliable technology.
The rules now permit the use of new technologies to establish the reasonable certainty of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes;
|
·
|
Unproved reserves.
Probable and possible reserves may be disclosed separately on a voluntary basis;
|
·
|
Preparation of reserves estimates.
Disclosure is required regarding the internal controls used to assure objectivity in the reserves estimation process and the qualifications of the technical person primarily responsible for preparing reserves estimates; and
|
·
|
Third party reports.
We are now required to file the report of any third party used to prepare or audit our reserves estimates.
|
December 31,
|
||||||
2013
|
2012
|
2011
|
||||
Gas
(Mcf)
|
Oil
(Bbls)
|
Gas
(Mcf)
|
Oil
(Bbls)
|
Gas
(Mcf)
|
Oil
(Bbls)
|
|
Proved Producing &
Non-Producing Reserves
(1)
|
26,000
|
3,930
|
155,540
|
73,902
|
156,630
|
48,950
|
Present value of proved
reserves
(2)
|
366,992
|
4,739,991
|
2,589.824
|
|||
Standardized measure of discounted
future net cash flows
(3)
|
336,507
|
3,833,734
|
2,390,024
|
(1)
|
Estimates of reserves as of year-end 2013, 2012 and 2011 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period of the applicable year, in accordance with revised guidelines of the SEC applicable to reserves estimates beginning with the year-end 2009. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
|
(2)
|
Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our reserve reports dated December 31, 2013, 2012 and 2011 is priced based on the 12-month un-weighted arithmetic average of the first-day-of-the month price for the period January through December of the applicable year. PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP.
|
(3)
|
The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, abandonment, production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.
|
Reserves*
|
|||
Reserve Category
|
Oil & NGL’s
(Bbls)
|
Natural Gas
(Mcf)
|
Total
(BOE)
|
PROVED
|
|||
Developed:
|
3,930
|
26,000
|
8,263
|
Undeveloped:
|
-
|
-
|
-
|
TOTAL PROVED at December 31, 2013
|
3,930
|
26,000
|
8,263
|
Production Data
|
Year Ended December 31
|
|||||
2013 | 2012 | 2011 | ||||
USA
|
USA
|
USA
|
||||
Production -
|
||||||
Oil (Bbls)
|
3,442
|
4,424
|
8,228
|
|||
Gas (Mcf)
|
34,940
|
25,399
|
108,978
|
|||
Average Sales Price -
|
||||||
Oil (Bbls)
|
$104.61
|
$99.00
|
$96.00
|
|||
Gas (Mcf)
|
$3.41
|
$3.00
|
$4.01
|
|||
Average Production Costs
|
||||||
Oil (Bbls)
|
$8.65
|
$9.00
|
$8.00
|
|||
Gas (Mcf)
|
$1.76
|
$1.00
|
$1.00
|
1
|
We disposed of our interests in the Oklahoma prospect during 2013.
|
2
|
We disposed of our interests in the Lonestar Prospect on December 1, 2011.
|
Producing Wells
3
|
Developed Acreage
|
|||||
Oil
|
Gas
|
|||||
Gross
1
|
Net
2
|
Gross
1
|
Net
2
|
Gross
1
|
Net
2
|
|
Garvin & Murray County, Oklahoma, USA
4
|
0
|
0
|
0
|
0
|
0
|
0
|
Newton County, Texas, USA
(Texas Prospect)
|
2
|
0.68
|
0
|
0
|
155
|
105
|
USA TOTALS
|
2
|
0.68
|
0
|
0
|
155
|
105
|
1
|
A gross well or acre is a well or acre in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.
|
2
|
A net well or acre is deemed to exist when the sum of fractional ownership working interests in gross wells or
acres equals one. The number of net wells or acres is the sum of the fractional working interest owned in gross wells or acres expressed as hole numbers and fractions thereof.
|
3
|
Productive wells are producing wells and wells capable of production.
|
4
|
Our properties in Garvin and Murray counties in Oklahoma consist of the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs referenced above in “Item 1, Business” were disposed during 2013.
|
Undeveloped Acreage
1
as of December 31, 2013
|
||
Gross
|
Net
|
|
Garvin & Murray County, Oklahoma, USA
2
|
0
|
0
|
Newton County, Texas, USA
(Texas Prospect)
|
209
|
75
|
USA TOTALS
|
209
|
75
|
1
|
"Undeveloped Acreage" includes leasehold interests on which wells have not been drilled or completed to the point that would permit the production of commercial quantities of natural gas and oil regardless of whether the leasehold interest is classified as containing proved undeveloped reserves.
|
2
|
Our properties in Garvin and Murray counties in Oklahoma consist of the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs referenced above in “Item 1, Business” were sold during 2013.
|
Geographical Area
|
Net Exploratory Wells Drilled
|
Net Development Wells Drilled
|
||
Productive
1
|
Dry
2
|
Productive
1
|
Dry
2
|
|
Garvin Murray Counties, Oklahoma, USA
3
|
||||
2013
|
0
|
0
|
0
|
0
|
2012
|
0
|
0
|
0
|
0
|
2011
|
0
|
0
|
0
|
0
|
Newton County, Texas, USA
(Texas Prospect)
|
||||
2013
|
0
|
0
|
0
|
0
|
2012
|
0
|
0
|
0
|
0
|
2011
|
0
|
0
|
0
|
0
|
Colusa County, California, USA
(Lonestar Prospect)
4
|
||||
2013
|
0
|
0
|
0
|
0
|
2012
|
0
|
0
|
0
|
0
|
2011
|
0.25
|
0
|
0
|
0
|
King City, California, USA
|
||||
2013
|
0
|
0
|
0
|
0
|
2012
|
0.20
|
0
|
0
|
0
|
2011
|
0
|
0
|
0
|
0
|
Geographical Area
|
Net Exploratory Wells Drilled
|
Net Development Wells Drilled
|
||
Productive
1
|
Dry
2
|
Productive
1
|
Dry
2
|
|
USA
|
||||
2013
|
0
|
0
|
0
|
0
|
2012
|
0
|
0
|
0
|
0
|
2011
|
0
|
0
|
0.32
|
0
|
1
|
A productive well is an exploratory or development well that is not a dry well. Although a well may be classified as productive upon completion, future changes in oil and gas prices, operating costs and production may result in the well becoming uneconomical.
|
2
|
A dry well (hole) is an exploratory or development well found to be incapable of producing either
oil or gas in sufficient quantities to justify completion as an oil or gas well.
|
3
|
Our properties in Garvin and Murray counties in Oklahoma consist of the 2006-3, 2007-1, 2009-1 and 2009-3 drilling programs referenced above in “Item 1, Business”, which were sold during 2013.
|
4
|
We disposed of our interests in the Lonestar Prospect on December 1, 2011.
|
Plan Category
|
A
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
|
B
Weighted-average
exercise price of
outstanding options,
warrants and right
|
C
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (A))
|
Equity compensation
plans approved by security holders
|
n/a
|
n/a
|
n/a
|
Equity compensation plans not approved by security holders
(1)
|
600,000
600,000
400,000
400,000
|
$0.135
$0.13
$0.085
$0.05
|
1,600,000
|
Total
|
2,000,000
|
$0.119
|
1,600,000
|
(1)
|
All awards represented in this table were made under the 2010 & 2013 Incentive Compensation Plan.
|
·
|
General and administrative costs for the year ended December 31, 2013 decreased to $599,966 from $691,999 for the year ended December 31, 2012, a decrease
of 13%. The decrease in general and administrative costs was caused by a decrease in stock based compensation expense attributable to the issuances of stock options and shares of common stock to management and consultants. Stock based compensation expense for the year ended December 31, 2013 was $77,337 as compared to $155,161 for the year ended December 31, 2012. Excluding stock-based compensation the general and administration costs for the year ended December 31, 2013 was $522,629 compared to $536,838 for the corresponding year. A decrease of 2% was caused by a reduction in costs related to investor relation services, which were partially offset by an increase in costs relating to filing and transfer fees.
|
·
|
Legal and Professional fees for the year ended December 31, 2013 decreased to $63,555 from $68,401 for the year ended December 31, 2012, a decrease of 7%. The decrease in professional fees was attributable to the Company cost reduction drive.
|
·
|
Consulting fees for the year ended December 31, 2013 increased to $282,285 from $270,189 for the year ended December 31, 2012, an increase of 4%. The increase in consulting fees was attributable to an increase due to the addition of a director to the Board of Directors.
|
·
|
Natural gas and oil operating costs for the year ended December 31, 2013 decreased to $113,350 from $147,837 for the year ended December 31, 2012, a decrease of 23%. The decrease in natural gas and oil operating costs is attributable to a decrease in the revenue from producing wells for the year ended December 31, 2013, as compared to the year ended December 31, 2012, as well the disposal of the Oklahoma wells.
|
·
|
Depreciation and depletion expense
for the year ended December 31, 2013 increased to $457,004 from $166,370 for the year ended December 31, 2012, an increase of 175%. The increase in depreciation and depletion expense is attributable to the reduction in reserves. Depletion is calculated referencing total production to total reserves.
|
·
|
Impairment of natural gas and oil properties for the year ended December 31, 2013 is $521,082 (2012: $nil). The impairment was caused by the disposal of the reserves in Oklahoma and the natural decline in reserves related to the Donner properties due to the surrounding geological base, and in particular the nature of water driven reservoirs of oil.
|
·
|
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;
|
·
|
Provide reasonable assurance that the transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
|
·
|
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
|
Page (s)
|
||||
F-1
|
||||
Financial Statements:
|
||||
F-3
|
||||
F-4
|
||||
F-5
|
||||
F-6
|
||||
F-7
|
December 31, 2013
|
December 31, 2012
|
|||||||
Basic and Diluted earnings per share computation:
|
||||||||
Loss from continuing operations and net loss
|
$ | (1,211,462 | ) | $ | (480,254 | ) | ||
Weighted Average Basic shares outstanding
|
15,111,324 | 14,466,686 | ||||||
Basic and Diluted loss per share
|
$ | (0.08 | ) | $ | (0.03 | ) |
Properties
|
December 31, 2012
|
Additions
|
Disposals
|
Transfer
from unproved properties |
Depletion
for the year
|
Impairment
|
December 31, 2013
|
|||||||||||||||||||||
USA properties
|
$ | 1,103,877 | $ | 26,510 | $ | (168,214 | ) | $ | 363,231 | $ | (457,004 | ) | $ | (521,082 | ) | $ | 347,318 |
Properties
|
December 31, 2012
|
Addition
|
Disposals
|
Transfer
to
proved
properties
|
December 31, 2013
|
|||||||||||||||
USA properties
|
$ | 517,299 | $ | 6,670 | $ | - | $ | (363,231 | ) | $ | 160,738 |
Total | 2013 | 2012 | 2011 | 2010 & Prior | ||||||||||||||||
Property acquisition costs and transfer to proved property pool
|
(363,231 | ) | (363,231 | ) | - | - | - | |||||||||||||
Exploration and development
|
523,969 | 6,670 | (77,803 | ) | 406,335 | 188,767 | ||||||||||||||
Capitalized interest
|
- | - | - | - | - | |||||||||||||||
Total | 160,738 | (356,561 | ) | (77,803 | ) | 406,335 | 188,767 |
December 31,
|
December 31,
|
|||||||
2013
|
2012
|
|||||||
US
|
||||||||
Federal statutory income tax rate
|
35.00 | % | 35.00 | % | ||||
State income taxes (average), net of federal benefit
|
- | - | ||||||
Permanent Differences
|
(0.14 | %) | (0.21 | %) | ||||
Foreign Rate Difference
|
(14.66 | %) | (21.25 | %) | ||||
Valuation allowance
|
(20.20 | %) | (13.54 | %) | ||||
Net income tax provision (benefit)
|
- | - |
Canada
|
||||||||
Federal statutory income tax rate
|
15.00
|
%
|
15.00
|
%
|
||||
Provincial income taxes
|
12.00
|
%
|
12.00
|
%
|
||||
Valuation allowance
|
(27.00
|
%)
|
(27.00
|
%)
|
||||
Net income tax provision (benefit)
|
-
|
-
|
December 31,
|
December 31,
|
|||||||
US
|
2013
|
2012
|
||||||
US Operating loss carry forward
|
$ | 1,065,523 | $ | 703,074 | ||||
US Capital Loss carry forward
|
407,869 | 407,869 | ||||||
Non-Qualified Stock Options
|
61,227 | 61,227 | ||||||
Canadian Operating loss carry forward | 907,909 | 809,262 | ||||||
Resources pools Canada – available for expense | 686,011 | 646,987 | ||||||
Resource Assets capitalized
|
426,094 | 401,856 | ||||||
Total
|
$ | 3,554,633 | $ | 3,030,275 |
Valuation Allowance
|
$ | (3,483,553 | ) | $ | (2,994,618 | ) | ||
Defferred Tax Assets (Net of Allowance)
|
71,079 | 35,658 | ||||||
Net deferred tax liabilities Accumulated Depletion | (71,079 | ) | (35,658 | ) | ||||
Total | (71,079 | ) | (35,658 | ) | ||||
Net Deferred asset/liabilities | $ | - | $ | - |
December 31,
2013
|
December 31, 2012
|
|||||||
Balance, beginning of the year
|
$ | 28,115 | $ | 16,567 | ||||
Liabilities assumed
|
- | - | ||||||
Revisions
|
(1,607 | ) | 9,560 | |||||
Accretion expense
|
3,373 | 1,988 | ||||||
Balance, end of the year
|
$ | 29,881 | $ | 28,115 |
Number
|
Weighted average
exercise price
|
|||||||
Balance outstanding, December 31, 2012
|
1,600,000 | $ | 0.119 | |||||
Granted | 400,000 | 0.085 | ||||||
Granted
|
400,000 | 0.050 | ||||||
Exercised
|
(200,000 | ) | 0.080 | |||||
Expired
|
(200,000 | ) | 0.080 | |||||
Balance outstanding, December 31, 2013
|
2,000,000 | $ | 0.107 |
December 31, 2013
|
December 31, 2012
|
|||||||
Risk-fee interest rate
|
0.075 - 0.84 | % | 1.15 | % | ||||
Expected life of the option
|
5 years
|
5 years
|
||||||
Expected volatility
|
260 - 278 | % | 228 | % | ||||
Expected dividend yield
|
- | - |
Options outstanding | Options exercisable | |||||
Exercise price
|
Number of shares
|
Remaining
contractual
life (years)
|
Number
of shares
|
|||
$0.135
|
600,000
|
2.05
|
600,000
|
|||
$0.130
|
600,000
|
3.22
|
600,000
|
|||
$0.085 | 400,000 | 4.10 | 400,000 | |||
$0.050
|
400,000
|
4.16
|
400,000
|
December 31,
2013
|
December 31, 2012
|
|||||||
Unsecured loan CAD$20,000, unconditionally promises to pay
with accrued interest equal to the Bank of Montreal’s Prime
Lending Rate plus 5.5% per annum.
|
$ | 18,804 | $ | 20,102 |
2010
|
||||||||
USA
|
Canada
|
|||||||
Property acquisition costs
|
||||||||
Proved
|
17,900
|
-
|
||||||
Unproved
|
(17,900
|
)
|
-
|
|||||
Development costs
|
||||||||
Exploratory costs
|
1,741,655
|
(180,681
|
)
|
|||||
Oil and gas expenditures
|
1,741,655
|
(180,681
|
)
|
2011
|
||||||||
USA
|
Canada
|
|||||||
Property acquisition costs
|
||||||||
Proved
|
-
|
-
|
||||||
Unproved
|
-
|
-
|
||||||
Development costs
|
||||||||
Exploratory costs
|
919,131
|
-
|
||||||
Oil and gas expenditures
|
919,131
|
-
|
2012
|
||||||||
USA
|
Canada
|
|||||||
Property acquisition costs
|
||||||||
Proved
|
- | - | ||||||
Unproved
|
- | - | ||||||
Development costs
|
- | - | ||||||
Exploratory costs
|
360,974 | - | ||||||
Oil and gas expenditures
|
360,974 | - |
2013
|
||||||||
USA
|
Canada
|
|||||||
Property acquisition costs
|
||||||||
Proved
|
- | - | ||||||
Unproved
|
- | - | ||||||
Development costs
|
31,573 | - | ||||||
Exploratory costs
|
- | - | ||||||
Oil and gas expenditures
|
- | - |
Crude Oil
|
Natural Gas
|
|||||||
Changes in proved reserves
|
(Bbls)
|
(MCF)
|
||||||
Estimated quantity, December 31, 2011
|
48,950
|
156,630
|
||||||
Revisions of previous estimate
|
29,376
|
24,209
|
||||||
Discoveries
|
-
|
-
|
||||||
Reserves sold to third party
|
-
|
-
|
||||||
Production
|
(4,424
|
)
|
(25,399
|
)
|
||||
Estimated quantity, December 31, 2012
|
73,902
|
155,440
|
||||||
Revisions of previous estimate
|
(48,417)
|
(62,811)
|
||||||
Discoveries
|
-
|
-
|
||||||
Reserves sold to third party
|
(18,110)
|
(31,690)
|
||||||
Production
|
(3,445
|
)
|
(34,939
|
)
|
||||
Estimated quantity, December 31, 2013
|
3,930
|
26,000
|
Proved Reserves at year end
|
Developed
|
Undeveloped
|
Total
|
|||||||||
Crude Oil (Bbls)
|
||||||||||||
December 31, 2013
|
3,930
|
-
|
3,930
|
|||||||||
December 31, 2012
|
24,536
|
49,366
|
73,902
|
|||||||||
Gas (MCF)
|
||||||||||||
December 31, 2013
|
26,000
|
-
|
26,000
|
|||||||||
December 31, 2012
|
151,820
|
3.620
|
155,440
|
December 31, 2013
|
December 31, 2012
|
|||||||
Future Cash inflows
|
$
|
463,521
|
$
|
7,872,934
|
||||
Future production costs
|
(96,529
|
)
|
(1,529,471
|
)
|
||||
Future development costs
|
-
|
(858,700
|
)
|
|||||
Future income tax expense
|
-
|
-
|
||||||
Future cash flows
|
366,992
|
5,484,763
|
||||||
10% annual discount for estimated timing of cash flows
|
(30,485)
|
(1,651,029
|
)
|
|||||
Standardized measure of discounted future net cash
|
$
|
336,507
|
$
|
3,833,734
|
Standardized measure of discounted cash flows:
|
December 31, 2013
|
December 31 ,2012
|
||||||
Beginning of year
|
$
|
3,833,734
|
$
|
2,390,024
|
||||
Sales and transfers of oil and gas produced, net production costs
|
(7,409,413)
|
2,729,448
|
||||||
Net changes in prices and production costs and other
|
1,432,942
|
71,391
|
||||||
Net changes due to discoveries
|
-
|
-
|
||||||
Changes in future development costs
|
858,700
|
(575,023)
|
||||||
Revisions of previous estimates
|
-
|
-
|
||||||
Other
|
-
|
-
|
||||||
Net change in income taxes
|
-
|
-
|
||||||
Accretion discount
|
1,620,544
|
(782,106)
|
||||||
Total change in standardized measure during the year
|
(3,497,227)
|
1,443,710
|
||||||
End of year
|
$
|
336,507
|
$
|
3,833,734
|
Signature and Title
|
Date
|
|
/s/
Christopher Paton-Gay
|
April 11, 2014
|
|
Christopher Paton-Gay, Chief Executive Officer and Director
(Principal Executive Officer)
|
||
/s/ Douglas N. Bolen
|
April 11, 2014
|
|
Douglas N. Bolen, President and Director
|
||
/s/ Kulwant Sandher
|
April 11, 2014
|
|
Kulwant Sandher, Chief Financial Officer and Director
(Principal Financial Officer and Principal Accounting Officer)
|
Exhibit
Number
|
Description
|
Incorporated by Reference to:
|
Filed
Herewith |
|||
3.1
|
Amended and Restated Articles of Incorporation of Delta Oil & Gas, Inc.
|
Exhibit 3 of the Company’s Form SB-2 filed on February 13, 2002
|
||||
3.2
|
Articles of Amendment to the Restated Articles of Incorporation of Delta Oil & Gas, Inc.
|
Exhibit 3.1 of the Company’s Quarterly Report of Form 10-Q for the period ended September 30, 2009.
|
||||
3.3
|
Articles of Amendment to the Restated Articles of Incorporation of Delta Oil & Gas, Inc.
|
Exhibit 3.1 of the Company’s Form 8-K dated October 21, 2009.
|
||||
3.4
|
By-laws of Delta Oil & Gas, Inc., as amended
|
Exhibit 3.4 of the Company’s Form 10-K for the year ended December 31, 2009
|
||||
10.1
|
Letter Agreement by and between Delta Oil & Gas, Inc. and Ranken Energy Corporation dated September 10, 2007
|
Exhibit 10.1 of the Company’s Form 10QSB dated November 7, 2007
|
||||
10.2
|
Farmout Agreement by and between Sunset Exploration, Inc. and Delta Oil & Gas, Inc., effective May 25, 2009
|
Exhibit 10.1 of the Company’s Quarterly Report of Form 10-Q dated June 30, 2009
|
||||
10.3
|
Letter Agreement by and between Ranken Energy Corporation and Delta Oil & Gas, Inc. relating to 2009-1 Drilling Program
|
Exhibit 10.2 of the Company’s Quarterly Report of Form 10-Q dated June 30, 2009
|
||||
10.4
|
Assignment of Oil, Gas, & Liquid Hydrocarbon Leases dated July 15, 2009, relating to the Texas Prospect
|
Exhibit 10.1 of the Company’s Quarterly Report of Form 10-Q dated September 30, 2009
|
||||
10.5
|
Letter Agreement by and between Delta Oil & Gas, Inc. and Ranken Energy Corporation dated August 7, 2009
|
Exhibit 10.2 of the Company’s Quarterly Report of Form 10-Q dated September 30, 2009
|
||||
10.6*
|
Amended and Restated Consulting Agreement, dated as of March 8, 2010, by and between Delta Oil & Gas, Inc. and Warwick Management Services
|
Exhibit 10.1 of the Company’s Form 8-K filed March 9, 2010
|
||||
10.7*
|
Amended and Restated Consulting Agreement, dated as of March 8, 2010, by and between Delta Oil & Gas, Inc. and Last Mountain Management Ltd.
|
Exhibit 10.2 of the Company’s Form 8-K filed March 9, 2010
|
||||
10.8*
|
Amended and Restated Consulting Agreement, dated as of March 8, 2010, by and between Delta Oil & Gas, Inc. and CPG Consulting Ltd.
|
Exhibit 10.3 of the Company’s Form 8-K filed March 9, 2010
|
||||
10.9*
|
Delta Oil & Gas, Inc. 2010 Incentive Compensation Plan
|
Exhibit 10.1 of the Company’s Form 8-K filed March 12, 2010
|
||||
10.10*
|
Delta Oil & Gas, Inc. 2013 Incentive Compensation Plan
|
Exhibit 10.1 of the Company’s Form 8-K filed March 6, 2013
|
||||
10.11
|
Exploration Agreement by and between Barry Lasker and Delta Oil & Gas, Inc., dated March 27, 2009
|
Exhibit 10.12 of the Company’s Form 10-K for the year ended December 31, 2009
|
||||
10.12
|
Assignment and Assumption Agreement, dated as of December 8, 2009, between Delta Oil & Gas, Inc. and Hillcrest Resources, Ltd.
|
Exhibit 10.13 of the Company’s Form 10-K for the year ended December 31, 2009
|
Exhibit
Number
|
Description
|
Incorporated by Reference to:
|
Filed
Herewith
|
|||
10.13
|
Purchase and Sale Agreement, dated as of July 1, 2010, between Delta Oil & Gas, Inc. and Petrex Energy Ltd.
|
Exhibit 10.1 of the Company’s Form 8-K dated August 9, 2010.
|
||||
10.14
|
Lonestar Prospect Exploration Agreement, dated September 1, 2010
|
Exhibit 10.9 of the Company’s Quarterly Report of Form 10-Q dated September 30, 2010
|
||||
10.15
|
Farm-out Agreement, dated as of September 7, 2012, between Delta Oil & Gas, Inc. and MPG King City Project, L.P.
|
Exhibit 10.1 of the Company’s Quarterly Report of Form 10-Q dated September 30, 2012
|
||||
14.1
|
Code of Ethics and Conduct
|
Exhibit 10.1 of the Company’s Form 10-KSB filed on April 19, 2004
|
||||
21.1
|
X
|
|||||
23.1
|
X
|
|||||
23.3
|
X
|
|||||
31.1
|
|
X
|
||||
31.2
|
|
X
|
||||
32.1
|
X
|
|||||
32.2
|
|
X
|
||||
99.1
|
X
|
|||||
101.INS
†
|
XBRL Instance Document
|
X | ||||
101.SCH
†
|
XBRL Taxonomy Extension Schema Document
|
X | ||||
101.CAL
†
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
X | ||||
101.DEF
†
|
XBRL Taxonomy Extension Definition Linkbase Document
|
X | ||||
101.LAB
†
|
XBRL Extension Labels Linkbase Document
|
X | ||||
101.PRE
†
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
X |
1 Year Delta Oil and Gas (CE) Chart |
1 Month Delta Oil and Gas (CE) Chart |
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