Attached files
file | filename |
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EX-10.12 - Triangle Petroleum Corp | v180495_ex10-12.htm |
EX-23.01 - Triangle Petroleum Corp | v180495_ex23-01.htm |
EX-32.01 - Triangle Petroleum Corp | v180495_ex32-01.htm |
EX-31.01 - Triangle Petroleum Corp | v180495_ex31-01.htm |
EX-10.11 - Triangle Petroleum Corp | v180495_ex10-11.htm |
EX-31.02 - Triangle Petroleum Corp | v180495_ex31-02.htm |
EX-14.02 - Triangle Petroleum Corp | v180495_ex14-02.htm |
UNITED
STATES
|
SECURITIES
AND EXCHANGE COMMISSION
|
WASHINGTON,
D.C. 20549
|
FORM
10-K
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For
the Fiscal Year Ended January 31,
2010
|
Commission
File Number 000-51321
TRIANGLE
PETROLEUM CORPORATION
(Exact
name of registrant as specified in its charter)
Nevada
|
98-0430762
|
|
(State
or other jurisdiction of incorporation
or
organization)
|
(IRS
Employer Identification No.)
|
Suite 750, 521 - 3 Avenue SW
Calgary, Alberta, Canada
|
T2P 3T3
|
(403) 262-4471
|
(Address of principal executive office)
|
(Zip Code)
|
(Registrant’s telephone number,
including area code)
|
Securities
registered pursuant to Section 12(b) of the Act: None.
Securities
registered pursuant to Section 12(g) of the Act:
Title
of each class
|
Name
of each exchange on which registered
|
Common
Stock, $0.0001 par value
|
Over-the-Counter
Bulletin Board
|
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined by
Rule 405 of the Securities Act. Yeso Nox
Indicate
by checkmark if the registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Act. Yeso Nox
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes
x No
o
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes o No
o
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K (§229.405 of this chapter) is not contained herein, and will not
be contained, to the best of the registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. o
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting company. See
definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.
Large
accelerated filer o
|
Accelerated
filer o
|
Non-accelerated
filer o
|
Smaller
reporting company x
|
(Do
not check if a smaller reporting company)
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes o No
x
The
aggregate market value of the voting common equity held by non-affiliates as of
July 31, 2009, based on the closing sales price of the Common Stock as quoted on
the Over-the-Counter Bulletin Board was $6,553,069. For purposes of this
computation, all officers, directors, and 5 percent beneficial owners of the
registrant are deemed to be affiliates. Such determination should not be
deemed an admission that such directors, officers, or 5 percent beneficial
owners are, in fact, affiliates of the registrant.
As of
April 8, 2010, there were 97,919,982 shares of registrant’s common stock
outstanding.
TRIANGLE
PETROLEUM CORPORATION
|
FORM
10-K
|
For
the Fiscal Year Ended January 31,
2010
|
Part I
|
||
Page
|
||
Item
1.
|
Business
|
3
|
Item
1A.
|
Risk
Factors
|
9
|
Item
1B.
|
Unresolved
Staff Comments
|
16
|
Item
2.
|
Properties
|
16
|
Item
3.
|
Legal
Proceedings
|
19
|
Item
4.
|
RESERVED
|
19
|
Part II
|
||
Page
|
||
Item
5.
|
Market
for Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
|
20
|
Item
6.
|
Selected
Financial Data
|
21
|
Item
7.
|
Management's
Discussion and Analysis of Financial Condition and Results of
Operations
|
21
|
Item
7A.
|
Quantitative
and Qualitative Disclosures about Market Risk
|
27
|
Item
8.
|
Financial
Statements and Supplementary Data
|
F-1
|
Item
9.
|
Changes
in and Disagreements With Accountants on Accounting and Financial
Disclosure
|
28
|
Item
9A.
|
Controls
and Procedures
|
28
|
Item
9B.
|
Other
Information
|
29
|
Part III
|
||
Page
|
||
Item
10.
|
Directors,
Executive Officers and Corporate Governance
|
30
|
Item
11.
|
Executive
Compensation
|
33
|
Item
12.
|
Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
|
36 |
Item
13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
37
|
Item
14.
|
Principal
Accounting Fees and Services
|
37
|
Part IV
|
||
Page
|
||
Item
15.
|
Exhibits;
Financial Statement Schedules
|
39
|
Signatures.
|
41
|
2
PART I
FORWARD-LOOKING
INFORMATION
This Annual Report of Triangle
Petroleum Corporation on Form 10-K includes a number of forward-looking
statements that reflect the current views of our management with respect to
future events and financial performance. You can identify these statements by
forward-looking words such as “may,” “will,” “expect,” “anticipate,” “believe,”
“estimate” and “continue,” or similar words. Those statements include statements
regarding our and members of our management team’s intent, belief or current
expectations as well as the assumptions on which such statements are based.
Prospective investors are cautioned that any such forward-looking statements are
not guarantees of future performance and involve risk and uncertainties, and
that actual results may differ materially from those contemplated by such
forward-looking statements.
ITEM
1. BUSINESS.
OVERVIEW
We are an
oil and gas exploration and development company focused primarily on the
acquisition, exploration and development of resource properties consisting
mainly of unconventional oil and gas reserves. We have recently undertaken a new
strategic investment strategy in the Bakken Shale play in North Dakota with our
entry into a joint participation agreement, effective January 15, 2010 (the
“Slawson Agreement”), with Slawson Exploration Company, Inc. (“Slawson”), aimed
at the acquisition and development of acreage in known areas of production in
McKenzie and Williams Counties of North Dakota. In addition, we have interests
in the Maritimes Basin in the Province of Nova Scotia. See “Our Operations”
below.
RECENT
TRANSACTIONS
In
November 2009, Palo Alto Investors, Inc. (“Palo Alto”), our largest shareholder,
initiated discussions with us regarding the potential for several proactive
measures, including changes to our board of directors (the “Board”) and
management and other strategic alternatives. On November 30, 2009, we entered
into a memorandum of understanding with a fund managed by Palo Alto, providing
for the restructuring of the Board and management, as well as our intention to
consider changes in our strategic direction and certain related
matters.
As part
of this memorandum of understanding, on November 30, 2009, we restructured the
Board and senior management team. Three new directors were appointed on November
30, 2009, including Gardner Parker, who was appointed Chairman of the Board, Dr.
Peter Hill and Jonathan Samuels. Two former directors also resigned from the
Board. The Board is currently comprised of five directors, each of whom, other
than Dr. Hill and Mr. Samuels, is independent under Canadian securities
laws.
The Board
also immediately restructured our senior management team. As part of the
memorandum of understanding with Palo Alto, Dr. Hill was appointed our new Chief
Executive Officer and Mr. Samuels was appointed our new Chief Financial
Officer.
The Board
and our senior management team have extensive knowledge of the oil and natural
gas industry, and have broad experience in acquiring early stage oil and natural
gas projects and exploring and developing oil and natural gas projects. Our
officers and directors also have extensive experience in raising capital through
the public equity markets and project finance. See “Item 10:
Directors, Executive Officers and Corporate Governance” for biographical
information on our officers and directors.
In March
2010, we completed a private placement with certain accredited investors,
pursuant to which such investors purchased an aggregate of 27,993,939 shares of
our common stock at a purchase price of $0.33 per share, yielding aggregate
gross proceeds to us of approximately $9,238,000 and net proceeds of
approximately $8,300,000.
3
OUR
OPERATIONS
During
fiscal 2010, we continued our exploration operations in the Maritimes Basin of
Eastern Canada on our Windsor Block. In the first half of fiscal 2010, we
finished the second phase of our Windsor Block exploration program by completing
three gross wells (1.71 net). In the second half of fiscal 2010, we acquired 30
kilometers of 2D seismic on the Windsor Block.
During
fiscal 2010, we had two producing wells in the Alberta Deep Basin, Canada, and
three producing wells in the Barnett Shale of Texas, U.S.A.
We refer
you to “Item 2: Properties”, of this Form 10-K for a more detailed discussion
our properties and their operations.
Williston
Basin
The
Bakken Shale play in the Williston Basin is our core area of operations in the
United States. Having identified what we believe is the prime Bakken Shale
fairway, we are continuing to explore further opportunities in the region. We
are constantly reviewing potential transactions and are actively pursuing the
acquisition of additional leases and acreage in North Dakota in furtherance of
our new strategic direction, with an ongoing acreage acquisition program
targeting 1,000 acres per month.
We have
entered into the Slawson Agreement to acquire and develop acreage in known areas
of production from the Middle Bakken Shale and Three Forks formations. Our
acreage is located in the Rough Rider area of the play, primarily McKenzie and
Williams Counties, North Dakota and consists of several drill-ready locations.
Under the terms of the Slawson Agreement, we have agreed to participate with a
30% working interest in the exploration and development of certain oil and gas
leasehold interests acquired by Slawson (the “Project”).
As part
of the Slawson Agreement, we have agreed to pay our participation interest share
of all costs incurred in the Project, plus (i) an additional amount equal to 20%
to 60% of our costs directly attributable to lease acquisitions, which amount
depends on the bonus cost of a lease per net acre, (ii) an additional amount
equal to 50% of our share of brokerage costs and other leasehold costs except
those direct lease costs set out above and except those included in an
applicable authorization for expenditure, and (iii) an additional 10% of our
share in costs proposed in the applicable authorizations for expenditure for
wells drilled under the Slawson Agreement.
The
Slawson Agreement also provides that Slawson will generally be responsible for
initiating well proposals, provided that we may recommend the drilling of a well
upon land which we own an interest in the leases. If a party to the Slawson
Agreement elects not to participate in a proposed well, then, subject to certain
condition, it forfeits all rights within the spacing unit boundaries for such
well, plus all contiguous sections. The Slawson Agreement also sets out a form
of joint operating agreement, pursuant to which all wells initiated under the
Slawson Agreement are to be operated.
Through
the signing of the Slawson Agreement, awards at a recent North Dakota state
lease sale, and the on-going success of our joint leasing program, we have
acquired approximately 13,000 gross (4,000 net) acres at a total cost to us of
$2.9 million. We are currently budgeting an additional minimum $7.0 million to
acquire additional leases in the Bakken Shale play in the Williston Basin over
the remainder of 2010. Under the terms of the Slawson Agreement, we have the
ability to limit our participation to no more than $25 million in any 12-month
period for total gross acreage acquisition capital, of which we are 30%.
However, this limitation may be exceeded at our option.
Eastern
Canadian Shale Gas Project (Windsor Block)
We have
an 87% working interest in 474,625 gross acres (412,924 net acres) in the
Windsor Sub-Basin of the Maritimes Basin located in the Province of Nova Scotia,
Canada (the “Windsor Block”) and serve as operator of the Windsor Block. Until
April 15, 2009, the land was governed by an exploration agreement between us and
the Province of Nova Scotia. On April 15, 2009, the Windsor Block exploration
agreement was transferred to a 10-year production lease. We acquired an
additional 30% working interest in the Windsor Block in June 2009 from Contact
Exploration Inc. (“Contact”) in exchange for a 5.75% non-convertible gross
overriding royalty interest, a cash payment of Cdn $270,000 and our assumption
of the liabilities related to the former working interest of Contact. This
acquisition increased our working interest to its current 87%
level.
4
In
October 2009, we acquired 30 kilometers of 2D seismic on the Windsor Block and
completed processing and interpreting the data in the fiscal quarter ending
January 31, 2010. We believe that this seismic program, combined with the three
completion operations on previously drilled vertical exploration wells,
satisfied the first-year requirements of our 10-year production
lease.
We are
continuing to evaluate the anticipated performance and viability of our working
interest in the Windsor Block. In moving forward with such property, we intend
to consider a range of options pursuant to our existing production
lease.
COMPETITORS
In the
Willison Basin in North Dakota, we compete with a number of larger public and
private companies such as Continental Resources, Brigham Exploration, XTO Energy
(now part of Exxon-Mobil), and Whiting Petroleum. All of these companies have
significantly more personnel and experience in the Williston Basin and greater
access to capital than we do.
In the
Maritimes Basin of Eastern Canada there are several specialized competitors who
have been pursuing their respective strategies for a number of
years. These companies include Contact, Stealth Ventures Ltd. and
Corridor Resources Inc. These companies have gained technical
expertise in the area as they have continued to advance their respective
exploration programs.
GOVERNMENTAL
REGULATIONS
Our
business is affected by numerous laws and regulations, including energy,
environmental, conservation, tax and other laws and regulations relating to the
oil and gas industry. We plan to develop internal procedures and policies to
ensure that our operations are conducted in full and substantial environmental
regulatory compliance.
Failure
to comply with any laws and regulations may result in the assessment of
administrative, civil and/or criminal penalties, the imposition of injunctive
relief or both. Moreover, changes in any of these laws and regulations could
have a material adverse effect on business. In view of the many uncertainties
with respect to current and future laws and regulations, including their
applicability to us, we cannot predict the overall effect of such laws and
regulations on our future operations.
We
believe that our operations comply in all material respects with applicable laws
and regulations and that the existence and enforcement of such laws and
regulations have no more restrictive an effect on our operations than on other
similar companies in the energy industry. Our future expenditures to comply with
environmental requirements have been estimated in the consolidated financial
statements, under the caption of asset retirement obligations.
Pricing
and Marketing Natural Gas
In
Canada, the price of natural gas sold in interprovincial and international trade
is determined by negotiation between buyers and sellers. Natural gas exported
from Canada is subject to regulation by the National Energy Board of Canada.
Exporters are free to negotiate prices and other terms with purchasers, provided
that the export contracts continue to meet certain criteria prescribed by the
National Energy Board of Canada. Natural gas export contracts for a term of less
than two years, or for a term of two to 20 years if in quantities of not more
than 30,000 m3/day (1,060 mcf/day), may be made pursuant to a National Energy
Board of Canada order. Natural gas export contracts for a term of greater than
20 years or for a term of greater than two years and in quantities of greater
than 30,000 m3/day (1,060 mcf/day) requires an exporter to obtain an export
license from the National Energy Board of Canada and the issuance of such a
license requires the approval of the Governor in Council. The export of natural
gas pursuant to an order or license shall be subject to the terms and conditions
included by the National Energy Board of Canada in such order or
license.
5
Also in
Canada, the government of Alberta regulates the volume of natural gas that may
be removed from the province for consumption elsewhere based on such factors as
reserve availability, transportation arrangements and market considerations.
Natural gas may not be removed from the Province of Alberta without a permit
from the Energy Resources Conservation Board of the Province of Alberta. The
Energy Resources Conservation Board of the Province of Alberta may grant a
permit for the removal of less than three billion cubic meters of natural gas
for a term not exceeding two years with the approval of the Minister. All other
permits for the removal of natural gas to be granted by the Energy Resources
Conservation Board of the Province of Alberta require the approval of the
Lieutenant Governor in Council. The removal of natural gas from the Province of
Alberta shall be subject to the terms and conditions included by the Energy
Resources Conservation Board of the Province of Alberta in the permit granted
for such removal.
In the
U.S., historically, the sale of natural gas in interstate commerce has been
regulated pursuant to the Natural Gas Act of 1938, or the NGA, the Natural Gas
Policy Act of 1978, or the NGPA, and regulations promulgated thereunder by the
Federal Energy Regulatory Commission, or the FERC. In 1989, Congress enacted the
Natural Gas Wellhead Decontrol Act, or the Decontrol Act. The Decontrol Act
removed all NGA and NGPA price and non-price controls affecting wellhead sales
of natural gas effective January 1, 1993 and sales by producers of natural gas
are uncontrolled and can be made at market prices. The natural gas industry
historically has been heavily regulated and from time to time proposals are
introduced by Congress and the FERC and judicial decisions are rendered that
impact the conduct of business in the natural gas industry. There can be no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue.
Pricing
and Marketing Oil
In
Canada, producers of oil negotiate sales contracts directly with oil purchasers,
with the result that the market determines the price of oil. The price depends
in part on oil quality, prices of competing fuels, distance to market, the value
of refined products and the supply/demand balance. Oil exports may be made
pursuant to export contracts with terms not exceeding two years in the case of
heavy crude and not exceeding one year in the case of oil other than heavy
crude, provided that an order approving any such export has been obtained from
the National Energy Board of Canada. Any oil export to be made pursuant to a
contract of longer duration (to a maximum of 25 years) requires an exporter to
obtain an export license from the National Energy Board of Canada and the issue
of such a license requires a public hearing and obtaining the approval of the
Governor in Council. The export of oil pursuant to an order or license shall be
subject to the terms and conditions included by the National Energy Board of
Canada in such order or license.
In the
U.S., sales of crude oil, condensate and gas liquids are not regulated and are
made at negotiated prices. Effective January 1, 1995, the FERC
implemented regulations establishing an indexing system for transportation rates
for oil that allowed for an increase in the cost of transporting oil to the
purchaser.
Royalties
and Incentives
The
royalty regime is a significant factor in the profitability of natural gas,
natural gas liquids and oil production. In the U.S., all royalties are
determined by negotiations between the mineral owner and the
lessee.
In
Canada, royalties payable on production from non-Crown lands (i.e.
non-government lands) are determined by negotiations between the mineral owner
and the lessee. However, crown royalties (i.e. government land royalties) are
determined by government regulation and are generally calculated as a percentage
of the value of the gross production, and the rate of royalties payable
generally depends in part on prescribed reference prices, well productivity,
geographical location, field discovery date and the type or quality of the
petroleum product produced. In addition to federal regulation, each province has
legislation and regulations that govern land tenure, royalties, production
rates, environmental protection and other matters. From time to time the
governments of Canada, Alberta, and Nova Scotia have established incentive
programs which have included royalty rate reductions, royalty holidays and tax
credits for the purpose of encouraging natural gas and oil exploration or
enhanced planning projects.
Nova
Scotia
In the
Province of Nova Scotia, the royalty rate for onshore oil and gas production has
been set at a flat rate of 10% of the petroleum that is produced based on the
fair market value of the petroleum at the wellhead. In determining the royalty
to be paid on any petroleum other than oil, there shall be deducted an allowance
for the cost of processing or separation as determined in any particular case by
the Minister. Notwithstanding the foregoing, no royalty shall be due with
respect to any oil or gas that is produced pursuant to the first production
lease that is granted with respect to lands subject to an exploration agreement,
for a period of two years from the date of commencement of such
lease.
6
Land
Tenure
In
Canada, natural gas and oil deposits located in Nova Scotia are owned by that
provincial government and natural gas and oil deposits located in the western
provinces of Canada are predominantly owned by the respective provincial
governments. Provincial governments grant rights to explore for and produce
natural gas and oil pursuant to leases, licenses and permits for varying terms
and on conditions set forth in provincial legislation including specific work
commitments or obligations to make rental, royalty or other payments. Where
natural gas and oil deposits are privately owned, such as in the U.S., rights to
explore for and produce such natural gas and oil are granted by lease on such
terms and conditions as may be negotiated.
The
North American Free Trade Agreement
On
January 1, 1994, NAFTA became effective among the governments of Canada, the
United States and Mexico. NAFTA carries forward most of the material energy
terms contained in the Canada - U.S. Free Trade Agreement. In the context of
energy resources, Canada continues to remain free to determine whether exports
to the United States or Mexico will be allowed provided that any export
restrictions do not: (i) reduce the proportion of energy resource exported
relative to domestic use (based upon the proportion prevailing in the most
recent 36 month period), (ii) impose an export price higher than the domestic
price, and (iii) disrupt normal channels of supply. All three countries are
prohibited from imposing minimum export or import price
requirements.
NAFTA
contemplates the reduction of Mexican restrictive trade practices in the energy
sector and prohibits discriminatory border restrictions and export taxes. NAFTA
also contemplates clearer disciplines on regulators to ensure fair
implementation of any regulatory changes and to minimize disruption of
contractual arrangements, which is important for Canadian natural gas
exports.
ENVIRONMENTAL
Canada
The oil
and natural gas industry is governed by environmental regulation under Canadian
federal and provincial laws, rules and regulations, which restrict and prohibit
the release or emission and regulate the storage and transportation of various
substances produced or utilized in association with oil and natural gas industry
operations. In addition, applicable environmental laws require that well and
facility sites be abandoned and reclaimed, to the satisfaction of provincial
authorities, in order to remediate these sites to near natural conditions. Also,
environmental laws may impose upon “responsible persons” remediation obligations
on property designated as a contaminated site. Responsible persons include
persons responsible for the substance causing the contamination, persons who
caused the release of the substance and any present or past owner, tenant or
other person in possession of the site. Compliance with such legislation can
require significant expenditures. A breach of environmental laws may result in
the imposition of fines and penalties and suspension of production, in addition
to the costs of abandonment and reclamation.
In Nova
Scotia, environmental laws are consolidated in the Nova Scotia Environment Act.
Under this Act, environmental standards and requirements applicable to
compliance, cleanup and reporting are contained and administered by the
Department of Environment.
In
December, 2002, the Government of Canada ratified the Kyoto Protocol, or the
Protocol. The Protocol calls for Canada to reduce its emissions of greenhouse
gas, or GHGs, to 6% below 1990 "business as usual" levels between 2008 and
2012. It remains uncertain whether the Kyoto target of 6% below 1990
GHG emission levels will be enforced in Canada. On April 26, 2007 the
Government of Canada released a "Regulatory Framework for Air Emissions", or the
Framework, which outlines proposed new requirements governing the emission of
GHGs and other industrial air pollutants, including sulfur oxides, volatile
organic compounds, particulate matter, and possibly additional sector-specific
pollutants, in accordance with the Canadian Federal Government’s Notice of
Intent to Develop and Implement Regulations and Other Measures to Reduce Air
Emissions released on October 19, 2006.
7
The
proposed compliance mechanisms include an emissions credit trading system for
GHGs and certain industrial air pollutants, and several options for companies to
choose among to meet GHG emission intensity reduction targets and encourage the
development of new emission reduction technologies, including the option of
making payments into a technology fund, an emissions and offset trading system,
limited credits for emission reductions created between 1992 and 2006, and
international emission credits under the clean development mechanism under the
Kyoto Protocol for up to 10% of each company’s regulatory
obligation.
Environmental
legislation in the Province of Alberta has been consolidated into the
Environmental Protection and Enhancement Act (Alberta), the Water Act (Alberta),
and the Oil and Gas Conservation Act (Alberta). These statutes impose
environmental standards, require compliance, reporting and monitoring
obligations, and impose penalties. In addition, the emission reduction
requirements in the Climate Change and Emissions Management Act (Alberta) came
into effect on July 1, 2007. Under this legislation, Alberta facilities emitting
more than 100,000 tonnes of GHGs a year must reduce their emissions intensity by
12%. Companies have four options to choose from in order to meet the
reduction requirements outlined in this legislation, and these are: (i) by
making improvement to operations that result in reductions; (ii) by purchasing
emission credits from other sectors or facilities that have reduced their
emissions below the required emission intensity reduction levels; (iii) by
purchasing off-set credits from other sectors or facilities that have emissions
below the 100,000 tonne threshold and are voluntarily reducing their emissions
in Alberta; or (iv) by contributing to the Climate Change and Emissions
Management Fund. Companies can choose one of these options or a
combination thereof.
United
States
Like the
oil and natural gas industry in general, our properties are subject to extensive
and changing federal, state and local laws and regulations designed to protect
and preserve our natural resources and the environment. The recent trend in
environmental legislation and regulation is generally toward stricter standards,
and this trend is likely to continue. These laws and regulations often require a
permit or other authorization before construction or drilling commences and for
certain other activities; limit or prohibit access, seismic acquisition,
construction, drilling and other activities on certain lands lying within
wilderness and other protected areas; impose substantial liabilities for
pollution resulting from our operations; and require the reclamation of certain
lands.
The
permits required for many of our operations are subject to revocation,
modification and renewal by issuing authorities. Governmental authorities have
the power to enforce compliance with their regulations, and violations are
subject to fines, injunctions, or both. In the opinion of management, we are in
substantial compliance with current applicable environmental laws and
regulations, and we have no material commitments for capital expenditures to
comply with existing environmental requirements. Nevertheless, changes in
existing environmental laws and regulations or in interpretations thereof could
have a significant impact on us, as well as the oil and natural gas industry in
general. The Comprehensive Environmental Response, Compensation and Liability
Act (CERCLA) and comparable state statutes impose strict and arguably joint and
several liabilities on owners and operators of certain sites and on persons who
disposed of or arranged for the disposal of “hazardous substances” found at such
sites. It is not uncommon for the neighboring landowners and other third parties
to file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment. The Resource Conservation
and Recovery Act (RCRA) and comparable state statutes govern the disposal of
“solid waste” and “hazardous waste” and authorize imposition of substantial
fines and penalties for noncompliance. Although CERCLA currently excludes
petroleum from its definition of “hazardous substance,” state laws affecting our
operations impose clean-up liability relating to petroleum and petroleum related
products. In addition, although RCRA classifies certain oil field wastes as
“non-hazardous,” such exploration and production wastes could be reclassified as
hazardous wastes, thereby making such wastes subject to more stringent handling
and disposal requirements.
8
Federal
regulations require certain owners or operators of facilities that store or
otherwise handle oil, such as us, to prepare and implement spill prevention,
control countermeasure and response plans relating to the possible discharge of
oil into surface waters. The Oil Pollution Act of 1990 (OPA) contains numerous
requirements relating to the prevention of and response to oil spills into
waters of the United States. For onshore and offshore facilities that may affect
waters of the United States, the OPA requires an operator to demonstrate
financial responsibility. Regulations are currently being developed under
federal and state laws concerning oil pollution prevention and other matters
that may impose additional regulatory burdens on us. In addition, the Clean
Water Act and analogous state laws require permits to be obtained to authorize
discharge into surface waters or to construct facilities in wetland areas. The
Clean Air Act of 1970 and its subsequent amendments in 1990 and 1997 also impose
permit requirements and necessitate certain restrictions on point source
emissions of volatile organic carbons (nitrogen oxides and sulfur dioxide) and
particulates with respect to certain of our operations. We are required to
maintain such permits or meet general permit requirements. The EPA and
designated state agencies have in place regulations concerning discharges of
storm water runoff and stationary sources of air emissions. These programs
require covered facilities to obtain individual permits, participate in a group
or seek coverage under an EPA general permit. Most agencies recognize the unique
qualities of oil and natural gas exploration and production operations. A number
of agencies including but not limited to the EPA, the BLM, the TCEQ, the LDNR,
the NDIC, the OCC, the WOGCC, the MBOGC and similar commissions within these
states and of other states in which we do business have adopted regulatory
guidance in consideration of the operational limitations on these types of
facilities and their potential to emit pollutants. We believe that we will be
able to obtain, or be included under, such permits, where necessary, and to make
minor modifications to existing facilities and operations that would not have a
material effect on us.
Climate
Change
Climate
change has emerged as an important topic in public policy debate regarding our
environment. It is a complex issue, with some scientific research suggesting
that rising global temperatures are the result of an increase in greenhouse gas
emissions (GHGs) which may ultimately pose a risk to society and the
environment. Products produced by the oil and natural gas exploration and
production industry is a source of certain GHGs, namely carbon dioxide and
methane, and future restrictions on the combustion of fossil fuels or the
venting of natural gas could have a significant impact on our future
operations.
EMPLOYEES
As of
April 6, 2010, we had five full time employees. We consider our relations with
our employees to be good.
ITEM
1A. RISK FACTORS.
You
should carefully consider the following risk factors and all other information
contained herein as well as the information included in this Annual Report in
evaluating our business and prospects. The risks and uncertainties described
below are not the only ones we face. Additional risks and uncertainties, other
than those we describe below, that are not presently known to us or that we
currently believe are immaterial, may also impair our business operations. If
any of the following risks occur, our business and financial results could be
harmed. You should refer to the other information contained in this Annual
Report, including our consolidated financial statements and the related
notes.
Risks
Relating to Our Business
We
Have a History Of Losses Which May Continue, Which May Negatively Impact Our
Ability to Achieve Our Business Objectives.
We
incurred net losses of $2,140,101 and $13,770,485 for the years ended January
31, 2010 and 2009, respectively. We cannot assure you that we can achieve or
sustain profitability on a quarterly or annual basis in the future. Our
operations are subject to the risks and competition inherent in the
establishment of a business enterprise. There can be no assurance that future
operations will be profitable. Revenues and profits, if any, will depend upon
various factors, including whether we will be able to continue expansion of our
revenue. We may not achieve our business objectives and the failure to achieve
such goals would have an adverse impact on us.
Natural
gas and oil drilling is a speculative activity and involves numerous risks and
substantial and uncertain costs that could adversely affect us.
An
investment in us should be considered speculative due to the nature of our
involvement in the exploration for, and the acquisition, development and
production of, oil and natural gas in North America. Oil and gas operations
involve many risks, which even a combination of experience and knowledge and
careful evaluation may not be able to overcome. There is no assurance that
commercial quantities of oil and natural gas will be discovered or acquired by
us.
9
We
depend on successful exploration, development and acquisitions to maintain
reserves and revenue in the future.
Acquisitions
of crude oil and natural gas issuers and crude oil and natural gas assets are
typically based on engineering and economic assessments made by independent
engineers and our own assessments. These assessments will include a series of
assumptions regarding such factors as recoverability and marketability of crude
oil and natural gas, future prices of crude oil and natural gas and operating
costs, future capital expenditures and royalties and other government levies
which will be imposed over the producing life of the reserves. Many of these
factors are subject to change and are beyond our control. In particular, the
prices of and markets for oil and natural gas products may change from those
anticipated at the time of making such assessment. In addition, all such
assessments involve a measure of geologic and engineering uncertainty that could
result in lower production and reserves than anticipated. Initial assessments of
acquisitions may be based on reports by a firm of independent engineers that are
not the same as the firm that we use for our year-end reserve evaluations.
Because each of these firms may have different evaluation methods and
approaches, these initial assessments may differ significantly from the
assessments of the firm used by us.
In
addition, our review of records and properties of potential acquisitions may not
necessarily reveal existing or potential problems, nor will we necessarily
become sufficiently familiar with the properties before we acquire them to
assess fully their deficiencies and potential. Environmental problems, such as
soil or ground water contamination, are not necessarily observable even when an
inspection on a well is undertaken and even when problems are identified, we may
often assume certain environmental and other risks and liabilities in connection
with acquired properties.
As
most of our properties are in the exploration stage, there can be no assurance
that we will establish commercial discoveries on our properties.
Exploration
for economic reserves of oil and gas is subject to a number of risk factors. Few
properties that are explored are ultimately developed into producing oil and/or
gas wells. Most of our properties are in the exploration stage only and we have
only limited revenues from operations. While we do have a limited amount of
production of gas, we may not establish commercial discoveries on any of our
properties. Failure to do so would have a material adverse effect on our
financial condition and results of operations.
We
cannot control the activities on properties we do not operate and are unable to
ensure their proper operation and profitability.
We do not
operate some of the properties in which we have an interest. As a result, we
have limited ability to exercise influence over, and control the risks
associated with, operations of these properties. The failure of an operator of
our wells to adequately perform operations, an operator’s breach of the
applicable agreements or an operator’s failure to act in ways that are in our
best interests could reduce our production and revenues. The success and timing
of our drilling and development activities on properties operated by others
therefore depend upon a number of factors outside of our control, including the
operator’s timing and amount of capital expenditures, expertise and financial
resources, inclusion of other participants in drilling wells and use of
technology.
We
have a limited operating history in the Bakken Shale play in North Dakota and if
we are not successful in continuing to grow our business, then we may have to
scale back or even cease our ongoing business operations.
We have a
limited operating history in the Bakken Shale play in North Dakota. Our success
is significantly dependent on a successful acquisition, drilling, completion and
production program. Our operations in the Bakken Shale play will be subject to
all the risks inherent in the establishment of a developing enterprise and the
uncertainties arising from the absence of a significant operating history. We
may be unable to locate recoverable reserves or operate on a profitable basis.
We are in the exploration stage and potential investors should be aware of the
difficulties normally encountered by enterprises in the exploration stage. If
our business plan is not successful, and we are not able to operate profitably,
investors may lose some or all of their investment.
10
Our
lack of diversification will increase the risk of an investment in us, and our
financial condition and results of operations may deteriorate if we fail to
diversify.
Our
current business focus is on the oil and gas industry in a limited number of
properties, initially in North Dakota. Larger companies have the ability to
manage their risk by diversification. However, we currently lack
diversification, in terms of both the nature and geographic scope of our
business. As a result, we will likely be impacted more acutely by factors
affecting our industry or the regions in which we operate, such as the Bakken
Shale play, than we would if our business were more diversified, enhancing our
risk profile.
We
have substantial capital requirements that, if not met, may hinder our
operations.
We
anticipate that we will make substantial capital expenditures for the
acquisition, exploration, development and production of oil and natural gas
reserves in the future and for future drilling programs, including our
obligations to Slawson under the Slawson Agreement. If we have insufficient
revenues, we may have limited ability to expend the capital necessary to
undertake or complete future drilling programs. There can be no assurance that
debt or equity financing, or cash generated by operations will be available or
sufficient to meet these requirements or for other corporate purposes, or if
debt or equity financing is available, that it will be on terms acceptable to
us. Moreover, future activities may require us to alter our capitalization
significantly. Our inability to access sufficient capital for our operations
could have a material adverse effect on our financial condition, results of
operations or prospects.
Because
we are small and have limited access to additional capital, we may have to limit
our exploration activity, which may result in a loss of investment.
We have a
small asset base and limited access to additional capital. Accordingly, we must
limit our exploration activity. As such, we may not be able to complete an
exploration program that is as thorough as our management would like. In that
event, existing reserves may go undiscovered. Without finding reserves, we
cannot generate revenues and investors may lose their investment.
We
face strong competition from other oil and gas companies.
We
encounter competition from other oil and gas companies in all areas of our
operations, including the acquisition of exploratory prospects and proven
properties. Our competitors include major oil and gas companies and numerous
independent oil and gas companies, individuals and drilling and income programs.
Many of our competitors have been engaged in the oil and gas business much
longer than we have and possess substantially larger operating staffs and
greater capital resources than us. These companies may be able to pay more for
exploratory projects and productive oil and gas properties and may be able to
define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial or human resources permit. In addition, these
companies may be able to expend greater resources on the existing and changing
technologies that we believe are and will be increasingly important to attaining
success in the industry. Such competitors may also be in a better position to
secure oilfield services and equipment on a timely basis or on favorable terms.
We may not be able to conduct our operations, evaluate and select suitable
properties and consummate transactions successfully in this highly competitive
environment.
Current
global financial conditions have been characterized by increased volatility
which could have a material adverse effect on our business, prospects, liquidity
and financial condition.
Current
global financial conditions and recent market events have been characterized by
increased volatility and the resulting tightening of the credit and capital
markets has reduced the amount of available liquidity and overall economic
activity. There can be no assurance that debt or equity financing, the ability
to borrow funds or cash generated by operations will be available or sufficient
to meet or satisfy our initiatives, objectives or requirements. Our inability to
access sufficient amounts of capital on terms acceptable to us for our
operations could have a material adverse effect on our business, prospects,
liquidity and financial condition.
The
potential profitability of oil and gas properties depends upon factors beyond
our control.
The
potential profitability of oil and gas properties is dependent upon many factors
beyond our control. For instance, world prices and markets for oil and gas are
unpredictable, highly volatile, potentially subject to governmental fixing,
pegging, controls, or any combination of these and other factors, and respond to
changes in domestic, international, political, social, and economic
environments. Additionally, due to worldwide economic uncertainty, the
availability and cost of funds for production and other expenses have become
increasingly difficult, if not impossible, to project. These changes and events
may materially affect our financial performance. In addition, a productive well
may become uneconomic in the event that water or other deleterious substances
are encountered which impair or prevent the production of oil and/or gas from
the well. In addition, production from any well may be unmarketable if it is
impregnated with water or other deleterious substances. These factors cannot be
accurately predicted and the combination of these factors may result in us not
receiving an adequate return on invested capital.
11
Seasonal
weather conditions and other factors could adversely affect our ability to
conduct drilling activities.
Our
operations could be adversely affected by seasonal weather conditions and
wildlife restrictions on federal leases. In some areas, certain drilling and
other oil and gas activities can only be conducted during limited times of the
year, typically during the summer months. This would limit our ability to
operate in these areas and could intensify competition during those times for
drilling rigs, oil field equipment, services, supplies and qualified personnel,
which may lead to periodic shortages. These constraints and the resulting
shortages or high costs could delay our operations and materially increase our
operating and capital costs, which could have a material adverse effect upon us
and our results of operations.
If
we are unable to retain the services of Messrs. Hill and Samuels or if we are
unable to successfully recruit qualified managerial and field personnel having
experience in oil and gas exploration, we may not be able to continue our
operations.
Our
success depends to a significant extent upon the continued services of our
directors and officers and, in particular: Peter Hill, our Chief Executive
Officer and Jonathan Samuels, our Chief Financial Officer and Corporate
Secretary. Loss of the services of Messrs. Hill and Samuels could have a
material adverse effect on our growth, revenues, and prospective business. We
have not and do not expect to obtain key man insurance on our management. In
addition, in order to successfully implement and manage our business plan, we
will be dependent upon, among other things, successfully recruiting qualified
managerial and field personnel having experience in the oil and gas exploration
business. Competition for qualified individuals is intense. There can be no
assurance that we will be able to find, attract and retain existing employees or
that we will be able to find, attract and retain qualified personnel on
acceptable terms.
The
marketability of natural resources will be affected by numerous factors beyond
our control.
The
markets and prices for oil and gas depend on numerous factors beyond our
control. These factors include demand for oil and gas, which fluctuate with
changes in market and economic conditions, and other factors,
including:
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worldwide
and domestic supplies of oil and
gas;
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actions
taken by foreign oil and gas producing
nations;
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political
conditions and events (including instability or armed conflict) in
oil-producing or gas-producing
regions;
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the
level of global and domestic oil and gas
inventories;
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the
price and level of foreign imports;
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the
level of consumer demand;
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the
price and availability of alternative
fuels;
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the
availability of pipeline or other takeaway
capacity;
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weather
conditions;
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domestic
and foreign governmental regulations and taxes;
and
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the
overall worldwide and domestic economic
environment.
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Significant
declines in oil and gas prices for an extended period may have the following
effects on our business:
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adversely
affect our financial condition, liquidity, ability to finance planned
capital expenditures and results of
operations;
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cause
us to delay or postpone some of our capital
projects;
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reduce
our revenues, operating income and cash flow;
and
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limit
our access to sources of capital.
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12
We
may have difficulty distributing our oil and gas production, which could harm
our financial condition.
In order
to sell the oil and gas that we are able to produce, we may have to make
arrangements for storage and distribution to the market. We will rely on local
infrastructure and the availability of transportation for storage and shipment
of our products, but infrastructure development and storage and transportation
facilities may be insufficient for our needs at commercially acceptable terms in
the localities in which we operate. This situation could be particularly
problematic to the extent that our operations are conducted in remote areas that
are difficult to access, such as areas that are distant from shipping and/or
pipeline facilities. These factors may affect our ability to explore and develop
properties and to store and transport our oil and gas production and may
increase our expenses.
Furthermore,
weather conditions or natural disasters, actions by companies doing business in
one or more of the areas in which we will operate, or labor disputes may impair
the distribution of oil and/or gas and in turn diminish our financial condition
or ability to maintain our operations.
Our
significant shareholders may have substantial influence over our business and
affairs.
As of
April 6, 2010, Cambrian Capital, Palo Alto Investors, and Sprott Asset
Management each own greater than 10% of our issued and outstanding shares of
common stock. As a result, each these three investors individually will have
substantial influence over the outcome of certain matters requiring shareholder
approval, including the power to, among other things:
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amend
our articles of incorporation;
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elect
and remove our directors and control the appointment of our senior
management; and
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prevent
our ability to be acquired and complete other significant corporate
transactions.
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Oil
and gas operations are subject to comprehensive regulation which may cause
substantial delays or require capital outlays in excess of those anticipated,
causing an adverse effect on us.
Oil and
gas operations are subject to federal, state, provincial and local laws relating
to the protection of the environment, including laws regulating removal of
natural resources from the ground and the discharge of materials into the
environment. Oil and gas operations are also subject to federal, state,
provincial and local laws and regulations which seek to maintain health and
safety standards by regulating the design and use of drilling methods and
equipment. Various permits from government bodies are required for drilling
operations to be conducted; no assurance can be given that such permits will be
received. Further, hydraulic fracturing, the process used for
releasing natural gas from shale rock, has recently come under increased
scrutiny and could be the subject of further regulation that could impact the
timing and cost of development.
Exploration
activities are subject to certain environmental regulations which may prevent or
delay the commencement or continuance of our operations.
In
general, our exploration activities are subject to certain federal, state and
local laws and regulations relating to environmental quality and pollution
control. Such laws and regulations increase the costs of these activities and
may prevent or delay the commencement or continuance of a given operation.
Compliance with these laws and regulations has not had a material effect on our
operations or financial condition to date. Specifically, we are subject to
legislation regarding emissions into the environment, water discharges and
storage and disposition of hazardous wastes. In addition, legislation has been
enacted which requires well and facility sites to be abandoned and reclaimed to
the satisfaction of state authorities. However, such laws and regulations are
frequently changed and we are unable to predict the ultimate cost of compliance.
Generally, environmental requirements do not appear to affect us any differently
or to any greater or lesser extent than other companies in the
industry.
With the
introduction of the Kyoto Protocol, oil and gas producers may be required to
reduce greenhouse gas emissions. This could result in, among other things,
increased operating and capital expenditures for those producers. This could
also make certain production of crude oil or natural gas by those producers
uneconomic, resulting in reductions in such production. We are unable to predict
the effect on our future earnings of the ratification of the Kyoto Protocol by
the Canadian Federal Government. However, in order to mitigate this risk, we are
committed to maximizing shareholder value in an environmentally, socially
responsible and safe manner.
13
We
believe that our operations comply, in all material respects, with all
applicable environmental regulations. Our operating partners generally maintain
insurance coverage customary to the industry; however, we are not fully insured
against all possible environmental risks.
Exploratory
drilling involves many risks and we may become liable for pollution or other
liabilities which may have an adverse effect on our financial
position.
Drilling
operations generally involve a high degree of risk. Hazards such as unusual or
unexpected geological formations, power outages, labor disruptions, blow-outs,
sour gas leakage, fire, inability to obtain suitable or adequate machinery,
equipment or labor, and other risks are involved. We may become subject to
liability for pollution or hazards against which we cannot adequately insure or
for which we may elect not to insure. Incurring any such liability may have a
material adverse effect on our financial position and operations.
Any
change in government regulation and/or administrative practices may have a
negative impact on our ability to operate and on our profitability.
The laws,
regulations, policies or current administrative practices of any government
body, organization or regulatory agency in the U.S. or Canada or any other
jurisdiction may be changed, applied or interpreted in a manner which will
fundamentally alter our ability to carry on our business. The actions, policies
or regulations, or changes thereto, of any government body or regulatory agency,
or other special interest groups, may have a detrimental effect on us. Any or
all of these situations may have a negative impact on our ability to operate
and/or our profitability.
Aboriginal
claims could have an adverse effect on us and our operations.
Aboriginal
peoples have claimed aboriginal title and rights to portions of Canada. We are
not aware that any claims have been made in respect of our property and assets.
However, if a claim arose and was successful, it could have an adverse effect on
us and our operations.
No
assurance can be given that defects in our title to natural gas and oil
interests do not exist.
Title to
natural gas and oil interests is often not possible to determine without
incurring substantial expense. An independent title review was completed with
respect to certain of the more valuable natural gas and oil rights acquired by
us and the interests in natural gas and oil rights owned by us. Also, legal
opinions have been obtained with respect to the spacing units for the wells
which have been drilled to date and which have been operated by us. However, no
assurance can be given that title defects do not exist. If a title defect does
exist, it is possible that we may lose all or a portion of the properties to
which the title defect relates. Our actual interest in certain properties may
therefore vary from our records.
Risks
Relating to our Common Stock
If
we fail to remain current in our reporting requirements, we could be removed
from the OTC Bulletin Board and/or the TSX Venture Exchange which would limit
the ability of broker-dealers to sell our securities and the ability of
stockholders to sell their securities in the secondary market.
Companies
trading on the OTC Bulletin Board, such as us, must be reporting issuers under
Section 12 of the Securities Exchange Act of 1934, as amended, and must be
current in their reports under Section 13, in order to maintain price quotation
privileges on the OTC Bulletin Board. We are also listed on the TSX Venture
Exchange. In order to remain listed on the TSX Venture Exchange, we
must remain a reporting issuer in good standing in each jurisdiction in which we
are a reporting issuer. We are a reporting issuer in each of British
Columbia, Alberta and Ontario and have continuous disclosure obligations under
securities laws and regulations in those jurisdictions (arising primarily under
National Instrument 51-102). If we fail to remain current on our reporting
requirements, we could be removed from the OTC Bulletin Board and/or the TSX
Venture Exchange. As a result, the market liquidity for our securities could be
severely adversely affected by limiting the ability of broker-dealers to sell
our securities and the ability of stockholders to sell their securities in the
secondary market.
14
The
market price for our common stock may be highly volatile.
The
market price for our common stock may be highly volatile and could be subject to
wide fluctuations. Some of the factors that could negatively affect such share
price include:
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actual
or anticipated fluctuations in our quarterly results of
operations;
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liquidity;
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sales
of common stock by our
shareholders;
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changes
in oil and natural gas prices;
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changes
in our cash flows from operations or earnings
estimates;
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publication
of research reports about us or the exploration and production industry
generally;
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increases
in market interest rates which may increase our cost of
capital;
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changes
in applicable laws or regulations, court rulings and enforcement and legal
actions;
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changes
in market valuations of similar
companies;
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adverse
market reaction to any increased indebtedness we incur in the
future;
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additions
or departures of key management
personnel;
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actions
by our shareholders;
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commencement
of or involvement in litigation;
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news
reports relating to trends, concerns, technological or competitive
developments, regulatory changes and other related issues in our
industry;
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speculation
in the press or investment community regarding our
business;
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general
market and economic conditions; and
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domestic
and international economic, legal and regulatory factors unrelated to our
performance.
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Financial
markets have recently experienced significant price and volume fluctuations that
have affected the market prices of equity securities of companies and that have,
in many cases, been unrelated to the operating performance, underlying asset
values or prospects of such companies. Accordingly, the market price
of our common stock may decline even if our operating results, underlying asset
values or prospects have not changed. Additionally, these factors, as well as
other related factors, may cause decreases in asset values that are deemed to be
other than temporary.
We do not
anticipate paying dividends on our common stock in the
foreseeable future.
We do not
expect to declare or pay any cash or other dividends in the foreseeable future
on our common stock, as we intend to use cash flow generated by operations to
develop our business.
Our
common stock is subject to the “penny stock” rules of the SEC and the trading
market in our securities is limited, which makes transactions in our common
stock cumbersome and may reduce the value of an investment in our common
stock.
The SEC
has adopted Rule 3a51-1 which establishes the definition of a “penny stock,” for
the purposes relevant to us, as any equity security that (i) has a market price
of less than $5.00 per share or with an exercise price of less than $5.00 per
share, or (ii) is not registered on a national securities exchange or listed on
an automated quotation system sponsored by a national securities exchange. For
any transaction involving a penny stock, unless exempt, Rule 15g-9 of the
Exchange Act requires:
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that
a broker or dealer approve a person’s account for transactions in penny
stocks; and
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the
broker or dealer receive from the investor a written agreement to the
transaction, setting forth the identity and quantity of the penny stock to
be purchased.
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In order
to approve a person’s account for transactions in penny stocks, the broker or
dealer must:
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obtain
financial information and investment experience objectives of the person;
and
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make
a reasonable determination that the transactions in penny stocks are
suitable for that person and the person has sufficient knowledge and
experience in financial matters to be capable of evaluating the risks of
transactions in penny stocks.
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15
The
broker or dealer must also deliver, prior to any transaction in a penny stock, a
disclosure schedule prescribed by the SEC relating to the penny stock market,
which, in highlight form:
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sets
forth the basis on which the broker or dealer made the suitability
determination; and
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attests
that the broker or dealer received a signed, written agreement from the
investor prior to the transaction.
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Disclosure
also has to be made about the risks of investing in penny stocks in both public
offerings and in secondary trading, and about the commissions payable to both
the broker-dealer and the registered representative. Current quotations for the
securities and the rights and remedies and to be available to an investor in
cases of fraud in penny stock transactions. Finally, monthly statements have to
be sent disclosing recent price information for the penny stock held in the
account and information on the limited market in penny stocks. Generally,
brokers may be less willing to execute transactions in securities subject to the
“penny stock” rules. This may make it more difficult for investors to dispose of
the Common Shares and cause a decline in the market value of the Common
Shares.
Investors
may be unable to enforce Canadian statutory remedies against us.
Securities
legislation in certain of the Provinces and Territories of Canada provides
investors with various rights and remedies where a public disclosure contains a
misrepresentation. We are incorporated under the laws of the State of Nevada. It
may be difficult for investors to collect from us judgments obtained in courts
in Canada predicated on the civil liability provisions of Canadian securities
legislation.
Investors
may be unable to enforce judgments against us and certain of our directors and
officers.
Certain
of our directors and officers, as well as our independent auditors, reside
principally in Canada. Because a portion of our assets and all or substantially
all of the assets of these persons are located outside the U.S., it may not be
possible for you to effect service of process within the U.S. upon us or those
persons. Furthermore it may not be possible for you to enforce judgments
obtained in U.S. courts based upon the civil liability provisions of the U.S.
federal securities laws or other laws of the U.S. against us or those persons.
There is doubt as to the enforceability in original actions in Canadian courts
of liabilities based upon the U.S. federal securities laws, and as to the
enforceability in Canadian courts of judgments of U.S. courts obtained in
actions based upon the civil liability provisions of the U.S. federal securities
laws. Therefore, it may not be possible to enforce those actions against us and
certain of our directors and officers.
ITEM
1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM
2. PROPERTIES.
We
maintain our principal office at Suite 750, 521 – 3rd Ave SW,
Calgary, Alberta, Canada T2P 3T3. Our telephone number at that office
is (403) 262-4471 and our facsimile number is (403) 262-4472. Our current office
space consists of approximately 1,944 square feet. The lease runs
until April 30, 2010 at a cost of $1 per month. We have paid our
share of building operating costs and taxes, and are currently seeking new
office space in the Calgary market. We do not anticipate any difficulty securing
alternative space on terms acceptable to us.
All of
our oil and gas properties are located in the United States and Canada. We are
currently participating in oil and gas exploration activities in the States of
North Dakota and Montana and the province of Nova Scotia. The Bakken Shale play
in the Williston Basin is our core area of operations in the United States. Our
other project is a conventional and shale gas opportunity located in the
Maritimes Basin in the province of Nova Scotia. We intend to execute our
operating plan in order to realize the full value of the land base that has been
established in the Maritimes Basin in the province of Nova Scotia. We are also
in the process of evaluating a potential secondary shale gas project in Western
Canada. Our remaining four project areas (Fayetteville Shale, Rocky Mountain
Program, Barnett Shale and Alberta Deep Basin) are currently designated as
non-core due to our desire to focus our limited manpower resources on one core
and one secondary project.
16
United
States
Williston
Basin - Bakken Shale play
We have
entered into the Slawson Agreement to acquire and develop acreage in known areas
of production from the Middle Bakken Shale and Three Forks formations. Our
acreage is located in the Rough Rider area of the play, primarily McKenzie and
Williams Counties, North Dakota and consists of several drill ready locations.
Under the terms of the Slawson Agreement, we have agreed to participate with a
30% working interest in the Project.
As part
of the Slawson Agreement, we have agreed to pay our participation interest share
of all costs incurred in the Project, plus (i) an additional amount equal to 20%
to 60% of our costs directly attributable to lease acquisitions, which amount
depends on the bonus cost of a lease per net acre, (ii) an additional amount
equal to 50% of our share of brokerage costs and other leasehold costs except
those direct lease costs set out above and except those included in an
applicable authorization for expenditure, and (iii) an additional 10% of our
share in costs proposed in the applicable authorizations for expenditure for
wells drilled under the Slawson Agreement.
The
Slawson Agreement also provides that Slawson will generally be responsible for
initiating well proposals, provided that we may recommend the drilling of a well
upon land which we own an interest in the leases. If a party to the Slawson
Agreement elects not to participate in a proposed well, then, subject to certain
condition, it forfeits all rights within the spacing unit boundaries for such
well, plus all contiguous sections. The Slawson Agreement also sets out a form
of joint operating agreement, pursuant to which all wells initiated under the
Slawson Agreement are to be operated.
Through
the signing of the Slawson Agreement, awards at a recent North Dakota state
lease sale, and the on-going success of our joint leasing program, we have
acquired approximately 13,000 gross (4,000 net) acres at a total cost to us of
$2.9 million. We are currently budgeting an additional minimum $7.0 million to
acquire additional leases in the Bakken Shale play in the Williston Basin over
the remainder of 2010. Under the terms of the Slawson Agreement, we have the
ability to limit our participation to no more than $25 million in any 12-month
period for total gross acreage acquisition capital, of which we are 30%.
However, this limitation may be exceeded at our option.
Canada
Maritimes
Basin - Eastern Canadian Shale Gas Projects
Windsor Block – We have an 87% working
interest in 474,625 gross acres (412,924 net acres) in the Windsor Sub-Basin of
the Maritimes Basin located in the Province of Nova Scotia, Canada and serve as
operator of the Windsor Block; Zodiac Exploration Corp. has earned a 13% working
interest in the Windsor Block. We acquired an additional 30% working interest in
the Windsor Block in June 2009 from Contact in exchange for agreeing to provide
Contact a 5.75% non-convertible gross overriding royalty interest. Contact also
received a cash payment of Cdn $270,000 (approximately US$254,000) and we
assumed the liabilities related to Contact's former working interest. Until
April 15, 2009, the land was governed by an exploration agreement. On April 15,
2009, the Windsor Block exploration agreement was transferred to a 10-year
production lease. Under the terms of this lease:
|
·
|
The
production lease grants rights to 474,625 gross acres (412,924 net acres),
covering substantially all of the land which we had leased previously
under the terms of the exploration agreement. Fringe acreage deemed
non-prospective was voluntarily
surrendered;
|
|
·
|
We
hold rights to conventional oil and gas within the lease, which includes
shale gas, in the Windsor and Horton Groups, excluding natural gas from
coal. We believe coals are not prospective within the Windsor
Block;
|
|
·
|
To
retain rights to this land block, we have agreed to continue to evaluate
the lands during the first five years of the lease by drilling seven
wells, completing three exploration wells previously drilled, and
acquiring seismic, which was estimated to cost Cdn $12.7 million gross
(approximately US$11.9 million). These wells are to be distributed across
the land block to fully evaluate conventional and shale resources. In
addition to annual progress reporting to maintain the lease in good
standing, on the second anniversary of the lease, we are obliged to
provide a detailed report to the Nova Scotia government to assess our
evaluation activities to maintain certain lands. After the
fifth anniversary, leased areas not adequately drilled or otherwise
evaluated may be subject to
surrender;
|
17
|
·
|
During
the first year of the lease, we agreed to complete the three exploration
wells that were drilled in the prior year and acquire seismic, which was
estimated to cost Cdn $2 million gross (approximately US$1.9 million). A
Cdn $200,000 (US$188,000) gross refundable deposit was posted related to
the first year commitment; should the work not be competed, a portion or
all of the deposit could be
forfeited.
|
|
·
|
Current
royalty rates are set at 10% in Nova Scotia;
and
|
|
·
|
Tenure
on some or all of the lands is eligible for renewal after the first 10
years, based on the establishment of commercial production and/or the
satisfaction of certain drilling and evaluation
criteria.
|
From May
2007 to June 2008, we executed the first phase of the Windsor Block exploration
program consisting of a 2D and 3D seismic program, geological studies, and
drilling and completing two vertical test wells (Kennetcook #1 and Kennetcook
#2). From July 2008 to September 2009, we executed the second phase of the
Windsor Block shale gas exploration program, which consisted of drilling three
vertical exploration wells (N-14-A, O-61-C and E-38-A) and undertaking
completion operations on all three of these wells.
During
the first quarter of fiscal 2010, we tested the N-14-A well, which was completed
in early December 2008 with a four-stage perforation and fracture treatment. The
frac flowback operations were suspended in April 2009 after the well recovered
15% of load fluid but negligible gas production. Subsequent analysis
indicated an unusually high insitu stress regime in the immediate vicinity of
the well, which contributed to fracture ineffectiveness. Completion operations
on the O-61-C well commenced in March 2009 and continued into early May. Several
tight sand and carbonate intervals were perforated but have not yet been
fracture-treated. No hydrocarbons flowed from the well.
During
the second and third quarters of fiscal 2010, three intervals in the E-38-A well
were perforated and treated with diagnostic “micro-fracs.” The two
lower intervals appeared to have high insitu stress and a tendency to fracture
horizontally. The upper tested interval indicated lower stress and
the likelihood of desirable vertical fracturing. As this was a diagnostic frac
in a very low permeability zone, no gas flow was expected, and none was
detected. We are continuing to work with these results to determine future
completion operations as well looking for future drilling locations and
completion strategies.
Also
during the second quarter of fiscal 2010, the two wells drilled in 2007,
Kennetcook #1 and Kennetcook #2, were re-entered to isolate and test individual
zones to try to identify the “gassiest” intervals in each well and eliminate
water inflow. From these tests, it appears the fracture treatments undertaken
previously had commingled multiple zones together, making it difficult to
determine which zone is contributing to the water inflow.
All three
of our most recent wells (N-14-A, O-61-C, and E-38-A) still have a variety of
completion and testing opportunities. Our technical team is in the
process of evaluating and ranking these opportunities with a goal of
demonstrating hydrocarbon production and providing further direction to the
ongoing exploration drilling program in the Windsor Block.
In
October 2009, we acquired 30 kilometers of 2D seismic on the Windsor Block. The
seismic program assessed a geologic structure in the west-central area of the
Windsor Block, where no seismic had yet been acquired. We believe that the best
potential for both Horton Bluff gas shales and conventional reservoirs exists in
areas with geologic structure. This seismic program, combined with the three
completion operations on previously drilled vertical exploration wells,
satisfied the first-year requirements of our 10-year production
lease.
Non-Core
Properties
In fiscal
2010, there was no exploration activity on our non-producing and undeveloped
land positions and we continue to plan not to participate in any exploration
activity for these projects in fiscal 2011. We are in the process of
rationalizing our non-core properties. During fiscal 2010, we sold:
|
·
|
our
25% working interest in 4,327 non-operated net acres in the U.S. Rocky
Mountains for gross proceeds of $83,325 in June
2009;
|
|
·
|
our
50% working interest in 5,900 non-operated net acres in the Fayetteville
Shale and all the related seismic data for gross cash proceeds of $767,000
in September 2009 and our remaining 3,380 non-operated net acres of the
Fayetteville Shale acreage for gross cash proceeds of $247,000 in November
2009. Costs related to these sales were approximately $30,000;
and
|
18
|
·
|
one
of the producing wells and our 12% working interest in 154 non-operated
net undeveloped acres in the Alberta Deep Basin for $426,600 in January
2010.
|
Our
remaining non-core producing properties include one well in the Alberta Deep
Basin of Canada and three low working interest shale gas wells in the Barnett
Shale trend. Our remaining non-core acreage holdings includes 5,165 net acres in
the Alberta Deep Basin of Canada, 4,747 non-operated net acres
in the U.S. Rocky Mountains, and 61 non-operated net acres in the Barnett Shale
trend.
Information with regard to
oil and gas producing activities follows:
Net
Reserves of Crude Oil and Natural Gas Liquids and Natural Gas at Fiscal Year-End
2010
At
January 31, 2010, our proved reserves estimates and future discounted cash flow
at 10% was valued at an inconsequential amount. We did not obtain a reserve
report at January 31, 2010 as the reserve were not material. Our 12 month
production for the year ended January 31, 2010 for these wells was:
Alberta Deep
Basin, Canada
|
Texas Barnett
Shale, U.S.A
|
Total
|
||||||||||
Fiscal
2010 Working Interest Production (MMcfe)
|
22 | 18 | 40 |
MMcfe –
Millions cubic feet equivalent
We refer
you to Note 5 in the consolidated financial statements for a more detailed
discussion of our proved natural gas and oil reserves as well as our
standardized measure of discounted future cash flows related to our proved
natural gas and oil reserves. We also refer you to “Management’s
Discussion and Analysis of Financial Condition and Results of Operations —
Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of
this Form 10-K for a discussion of the risks inherent in utilization of
standardized measures and estimated reserve data.
In 2008,
the SEC adopted major revisions to its required oil and gas reporting
disclosures which became effective as of January 1, 2010. Among other
things, the amendments provide for the use of the 12-month average price,
calculated as the unweighted arithmetic average of the first-day-of-the-month
price for each month within the 12-month period prior to the end of the
reporting period for purposes of both the disclosure and full-cost accounting
rules. The use of new technologies to determine proved reserves is permitted
under the new rules, and allows companies to disclose probable and possible
reserves to investors unlike previous rules which limit disclosure to only
proved reserves. The new disclosure requirements also require companies to
report the independence and qualifications of the auditor of the reserve
estimates and file reports when a third party is relied upon to prepare reserve
estimates. The requirements were effective for annual reports on Form 10-K for
fiscal years ending on or after December 31, 2009 and have been included
throughout this Form 10-K.
ITEM
3. LEGAL PROCEEDINGS.
From time
to time, we may become involved in various lawsuits and legal proceedings which
arise in the ordinary course of business. However, litigation is subject to
inherent uncertainties, and an adverse result in these or other matters may
arise from time to time that may harm our business. We are currently not aware
of any such legal proceedings or claims that we believe will have, individually
or in the aggregate, a material adverse affect on our business, financial
condition or operating results.
ITEM
4. RESERVED
19
PART II
ITEM
5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES.
MARKET
INFORMATION
Our
common stock is quoted on the OTC Bulletin Board under the symbol “TPLM” and,
starting on December 8, 2008, the TSX Venture Exchange under the symbol
“TPE”.
For the
periods indicated, the following table sets forth the high and low bid prices
per share of common stock on the OTC Bulletin Board. These prices represent
inter-dealer quotations without retail markup, markdown, or commission and may
not necessarily represent actual transactions.
Fiscal Year 2010
|
||||||||
TPLM
|
||||||||
High
|
Low
|
|||||||
First
Quarter
|
$ | 0.25 | $ | 0.11 | ||||
Second
Quarter
|
$ | 0.21 | $ | 0.15 | ||||
Third
Quarter
|
$ | 0.18 | $ | 0.07 | ||||
Fourth
Quarter
|
$ | 0.40 | $ | 0.08 |
Fiscal Year 2009
|
||||||||
TPLM
|
||||||||
High
|
High
|
|||||||
First
Quarter
|
$ | 1.63 | $ | 1.63 | ||||
Second
Quarter
|
$ | 2.40 | $ | 2.40 | ||||
Third
Quarter
|
$ | 1.08 | $ | 1.08 | ||||
Fourth
Quarter
|
$ | 0.35 | $ | 0.35 |
HOLDERS
As of March 29, 2010, we had
approximately 43 registered holders of our common stock. The number of record
holders was determined from the records of our transfer agent and does not
include beneficial owners of common stock whose shares are held in the names of
various security brokers, dealers, and registered clearing agencies. The
transfer agent of our common stock is Continental Stock Transfer & Trust
Company, 17 Battery Place, New York, New York 10004.
DIVIDENDS
We do not
anticipate paying any cash dividends to stockholders in the foreseeable future.
Any future determination to pay cash dividends will be at the discretion of the
Board of Directors and will be dependent upon our financial condition, results
of operations, capital requirements, and such other factors as the Board of
Directors deem relevant.
RECENT
SALE OF UNREGISTERED SECURITIES AND EQUITY PURCHASES BY THE COMPANY
None.
20
Equity
Compensation Plan Information
The
following table sets forth certain information about the common stock that may
be issued upon the exercise of options under the equity compensation plans as of
January 31, 2010.
Plan Category
|
Number of Shares
to be Issued
Upon Exercise of
Outstanding
Options,
Warrants and
Rights
|
Weighted-Average
Exercise
Price of
Outstanding
Options,
Warrants and
Rights
|
Number of Shares
Remaining
Available for
Future Issuance
Under Equity
Compensation
Plans (Excluding
Shares Reflected
in the First
Column)
|
|||||||||
Equity
compensation plans approved by shareholders
|
5,700,000 | $ | 0.52 | 1,292,604 | ||||||||
Equity
compensation plans not approved by shareholders
|
- | $ | - | - | ||||||||
Total
|
5,700,000 | $ | 0.52 | 1,292,604 |
ITEM
6. SELECTED FINANCIAL DATA.
Not
required under Regulation S-K for “smaller reporting companies.”
ITEM
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
This
Management's Discussion and Analysis of Financial Condition and Results of
Operations includes a number of forward-looking statements that reflect
Management's current views with respect to future events and financial
performance. You can identify these statements by forward-looking words such as
“may,” “will,” “expect,” “anticipate,” “believe,” “estimate” and “continue,” or
similar words. Those statements include statements regarding the
intent, belief or current expectations of us and members of our management team
as well as the assumptions on which such statements are based. Prospective
investors are cautioned that any such forward-looking statements are not
guarantees of future performance and involve risk and uncertainties, and that
actual results may differ materially from those contemplated by such
forward-looking statements.
Readers
are urged to carefully review and consider the various disclosures made by us in
this report and in our other reports filed with the Securities and Exchange
Commission. The following Management’s Discussion and Analysis of Financial
Condition and Results of Operations of the Company should be read in conjunction
with the Consolidated Financial Statements and notes related thereto included in
this Annual Report on Form 10-K.
Important factors currently known to
Management could cause actual results to
differ materially from those in
forward-looking statements. We undertake no obligation to
update or revise forward-looking statements to reflect changed assumptions, the
occurrence of unanticipated events or changes in the future operating results
over time. We believe that our assumptions are based upon reasonable data
derived from and known about our business and operations. No
assurances are made that actual results of operations or the results of our
future activities will not differ materially from our
assumptions. Factors that could cause differences include, but are
not limited to, expected market demand for our products, fluctuations in pricing
for materials, and competition.
Overview
We are an
oil and gas exploration company focused on emerging shale oil reserves. We have
recently undertaken a new strategic investment strategy in the Bakken Shale play
with our Slawson Agreement involving 4,000 net acres in McKenzie and Williams
Counties of North Dakota. The Bakken Shale formation in the Williston Basin
underlies much of North Dakota and eastern Montana. In addition, we have
interests in the Maritimes Basin in the Province of Nova
Scotia.
21
Plan
of Operations
Williston
Basin
The
Bakken Shale play in the Williston Basin is our core area of operations in the
United States. Having identified what we believe is the prime Bakken Shale
fairway, we are continuing to explore further opportunities in the region. We
are constantly reviewing potential transactions and are actively pursuing the
acquisition of additional leases and acreage in North Dakota in furtherance of
our new strategic direction, with an ongoing acreage acquisition program
targeting 1,000 acres per month.
Eastern Canadian Shale Gas
Project (Windsor Block)
We have
an 87% working interest in 474,625 gross acres (412,924 net acres) in the
Windsor Block and serve as operator of the Windsor Block. We are continuing to
evaluate the anticipated performance and viability of our working interest in
the Windsor Block. In moving forward with such property, we intend to consider a
range of options pursuant to our existing production lease.
Results
of operations for the year ended January 31, 2010 compared to the year ended
January 31, 2009
Daily Sales Volumes, Working
Interest before royalties
2010
|
2009
|
||||||||
Barnett
Shale in Texas, USA
|
Mcfpd
|
50 | 65 | ||||||
Deep
Basin in Alberta, Canada
|
Mcfpd
|
61 | 99 | ||||||
Total
Company
|
Mcfpd
|
111 | 164 | ||||||
Total
Company
|
Boepd*
|
19 | 27 |
* Mcf
converted into BOE on a basis of 6:1
Net Operating
Results
2010
|
2009
|
||||||||
Volumes
|
Mcf
|
40,744 | 59,854 | ||||||
Price
|
$/Mcf
|
3.75 | 7.97 | ||||||
Revenue
|
$ | 152,938 | $ | 476,996 | |||||
Royalties
|
21,693 | 90,104 | |||||||
Revenue,
net of royalties
|
131,245 | 386,892 | |||||||
Production
expenses
|
95,852 | 125,777 | |||||||
Net
|
$ | 35,393 | $ | 261,115 |
For the
year ended January 31, 2010, we realized $152,938 in revenue from sales of
natural gas and natural gas liquids, as compared to $476,996 in the prior year.
Revenue decreased mainly due to reduced natural gas prices, and to a lesser
effect, due to reduced production volumes. Royalties as a percent of revenue
were 14% for the year ended January 31, 2010 as compared to 19% in the prior
year. The decrease in royalty rates is due to the sliding scale of royalty rates
as gas prices decrease. Production expenses related to this revenue were
$14.12/BOE for the year ended January 31, 2010 compared to $12.61/BOE in the
prior year; the increase in the per BOE rate was mainly the effect of fixed
production costs being spread over reduced production volumes.
22
Depletion, Depreciation and Accretion
2010
|
2009
|
|||||||
Depletion
– oil and gas properties
|
$
|
38,781
|
$
|
92,747
|
||||
Accretion
|
150,007
|
107,303
|
||||||
Depletion
and Accretion
|
188,788
|
200,050
|
||||||
Depreciation
– property and equipment
|
26,198
|
39,448
|
||||||
Total
|
$
|
214,986
|
$
|
239,498
|
||||
Depletion
per BOE
|
$
|
5.71
|
$
|
9.30
|
Unproven
property costs of $18,783,375 (2009 – $16,869,995) were excluded from costs
subject to depletion at January 31, 2010. Depletion expense related to oil and
gas properties decreased in the year ended January 31, 2010 compared to the
prior year mainly as a result of the ceiling test write-downs on proved
properties in the previous year which decreased the depletion base.
General and Administrative
(“G&A”)
2010
|
2009
|
|||||||
Salaries,
benefits and consulting fees
|
$
|
1,844,226
|
$
|
1,728,907
|
||||
Office
costs
|
844,605
|
892,270
|
||||||
Professional
fees
|
245,235
|
449,236
|
||||||
Public
company costs
|
303,809
|
558,020
|
||||||
Operating
overhead recoveries
|
(45,224
|
)
|
(180,709
|
)
|
||||
Stock-based
compensation
|
794,361
|
598,182
|
||||||
Total
G&A
|
$
|
3,987,012
|
$
|
4,045,906
|
General
and administrative expenses have decreased $58,894 in the year ended January 31,
2010 compared to the prior year primarily due management implementing cost
reductions in the current year.
|
·
|
Salaries,
benefits and consulting fees increased $115,319 in the year ended January
31, 2010 compared to the prior year partially due to severances paid to
the officers in late 2009 of approximately $465,000 as part of our new
strategic direction that was announced December 1, 2009, offset in part by
lower salaries of $296,000 during the year due to reduced staff and no
staff bonuses in the year ended January 31,
2010.
|
|
·
|
Office
costs decreased $47,665 compared to the prior year partially due to
reduced travel, software, insurance and telephone costs offset in part by
higher rent since we bought out the remaining 3.5 year term of our
Canadian head office lease for approximately
$265,000.
|
|
·
|
Professional
fees decreased $204,001 mainly due to reduced audit and accounting fees,
which were higher in the prior year due to fees for the restatements of
our 10-K and 10-Q filings with the SEC, and due to a fee paid in the prior
year to market our Fayetteville acreage for
sale.
|
|
·
|
Public
company costs decreased $254,211 in the year ended January 31, 2010
compared to the prior year mainly due to reduced investor relation costs
related to management implementing cost reductions. Public company costs
consist mainly of fees for investor relations and also include directors'
fees, press release and SEC and Toronto Stock Exchange filing costs,
printing costs and transfer agent
fees.
|
|
·
|
Stock-based
compensation increased $196,179 mainly due to the granting of stock
options in January 2009.
|
Accretion of Discounts on
Convertible Debentures
Agreement Date
|
2010
|
2009
|
||||||
December
8, 2005
|
$
|
-
|
$
|
815,337
|
||||
December
28, 2005
|
-
|
2,107,572
|
||||||
Total
accretion of discounts
|
$
|
-
|
$
|
2,922,909
|
23
The
accretion of discounts was fully recognized in the year ended January 31, 2009
since the December 8, 2005 debentures were fully converted and repaid June 5,
2008 and the December 28, 2005 debentures were settled December 18,
2008.
Interest
Expense
Agreement Date
|
2010
|
2009
|
||||||
December
8, 2005
|
$
|
-
|
$
|
91,360
|
||||
December
28, 2005
|
-
|
661,644
|
||||||
Total
interest expense
|
$
|
-
|
$
|
753,004
|
There was
no interest expense in the year ended January 31, 2010 since the December 8,
2005 debentures were fully converted and repaid June 5, 2008 and the December
28, 2005 debentures were settled December 18, 2008.
Gain on Debt
Extinguishment
On
December 8, 2005, we issued $15,000,000 principal face amount of convertible
debentures that were convertible at the lower of (i) $5.00 or (ii) 90% of the
average of the three lowest daily volume weighted average prices of our common
stock of the 10 trading days immediately preceding the date of conversion.
Through June 2008, $11,000,000 of the debentures were converted into shares of
common stock. In June 2008, we repaid the $4,000,000 in remaining debt, which
was subject to a 20% early redemption fee of $800,000. A loss of $160,662 was
recorded on this debt extinguishment.
On
December 28, 2005, we issued $10,000,000 principal face amount of convertible
debentures that were convertible at the option of the holder at $4.00 per share.
In December 2008, the debentures were settled by (i) reducing the conversion
price to $1.40 per share and $3,500,000 of the debentures was converted into
2,500,000 shares of common stock and (ii) the convertible debenture holders
accepted cash of $6,500,000 to settle the remaining debt plus $2,204,792 in
accrued interest. A gain of $4,083,375 was recorded on this debt
extinguishment.
Oil and Gas
Properties
Net Book Value
January 31,
2009
|
Additions
|
Depletion
|
Dispositions
|
Gain
(Loss)
|
Net Book Value
January 31,
2010
|
|||||||||||||||||||
Unproven
|
||||||||||||||||||||||||
Windsor
Block Maritimes Shale – Nova Scotia, Canada
|
$ | 16,818,586 | $ | 1,964,789 | $ | - | $ | - | $ | - | $ | 18,783,375 | ||||||||||||
Western
Canadian Shale – Alberta and B.C., Canada
|
51,409 | 171,508 | - | - | (222,917 | ) | - | |||||||||||||||||
Fayetteville
and Rocky Mountains
|
- | 4,500 | - | (1,117,860 | ) | 1,113,360 | - | |||||||||||||||||
Proved
|
||||||||||||||||||||||||
Canada
|
72,869 | 2,207 | (24,327 | ) | (426,600 | ) | 375,851 | - | ||||||||||||||||
U.S.A.
|
- | 14,454 | (14,454 | ) | - | - | - | |||||||||||||||||
Net
|
$ | 16,942,864 | $ | 2,157,458 | $ | (38,781 | ) | $ | (1,544,460 | ) | $ | 1,266,294 | $ | 18,783,375 |
During
the year ended January 31, 2010, we focused on the Windsor Block and spent
$1,964,789 primarily for:
|
·
|
completing
the second phase of the Windsor Block exploration program consisting of
testing the N-14-A well (approximately $164,000), completion operations on
the O-61-C well (approximately $208,000), and completion operations on the
E-38-A well (approximately
$208,000);
|
|
·
|
retesting
the Kennetcook #1 and #2 wells (approximately $250,000) and increasing the
related non-cash asset retirement costs (approximately
$213,000);
|
24
|
·
|
acquiring
Contact’s 30% working interest in the Windsor Block for cash of $245,000
and the assumption of future estimated non-cash asset retirement costs of
$144,750. We also agreed to provide Contact a 5.75% non-convertible gross
overriding royalty interest on our resulting 87% working interest;
and
|
|
·
|
acquiring
2D seismic (approximately
$476,000).
|
During
the year ended January 31, 2010, we sold our:
|
·
|
25%
working interest 4,327 non-operated net acres in the U.S. Rocky Mountains
for gross proceeds of $83,325 in June
2009;
|
|
·
|
50%
working interest in 5,900 non-operated net acres in the Fayetteville Shale
and all the related seismic data for net cash proceeds of $744,408 in
September 2009. Furthermore, a $50,000 drilling deposit was refunded
related to the Fayetteville Shale
properties;
|
|
·
|
50%
working interest in the remaining 3,880 non-operated net acres in the
Fayetteville Shale for net cash proceeds of $240,127 in November 2009;
and
|
|
·
|
18%
working interest in one well and 12% working interest in 896 gross acres
of undeveloped land in Alberta for cash proceeds of
$426,600.
|
Net Cash Oil and Gas
Additions:
Year Ended
January 31,
2010
|
Year Ended
January 31,
2009
|
|||||||
Net
additions, per above table
|
$ | 2,157,458 | $ | 4,448,883 | ||||
Non-cash
ARO net additions
|
(326,600 | ) | (360,544 | ) | ||||
Changes
in investing working capital
|
1,202,396 | 1,976,950 | ||||||
Net
oil and gas additions, per Statement of Cash Flows
|
$ | 3,033,254 | $ | 6,065,289 |
Liquidity
and Capital Resources
As at
January 31, 2010, we had working capital of $4,841,074, resulting primarily from
our cash of $4,878,601, prepaid expenses of $342,635 and other receivables of
$313,785, offset by payables and accrued liabilities of $693,947. For the year
ended January 31, 2010, we had a net cash outflow from operating activities
before changes in working capital of $3,187,203, mainly related to $3,192,651 of
cash general and administrative expenses, which is equal to general and
administrative expenses net of non-cash stock based compensation
expense.
We expect
significant capital expenditures during the next 12 months for land acquisitions
and drilling programs on our U.S. oil shale program, overhead and working
capital purposes. We believe we have sufficient cash to fund budgeted capital
expenditures in fiscal 2011. However, if during that period, or
thereafter, we are not successful in generating sufficient liquidity from
operations or in raising sufficient capital resources, on terms acceptable to
us, this could have a material adverse effect on our business, results of
operations, liquidity and financial condition. We presently do not have any
available credit, bank financing or other external sources of liquidity. Due to
our brief history and historical operating losses, our operations have not been
a source of liquidity. We will need to obtain additional capital in order to
expand operations and become profitable. In order to obtain capital, we may need
to sell additional shares of our common stock or borrow funds from private
lenders. There can be no assurance that we will be successful in obtaining
additional funding. Additional capital is being sought, but we cannot guarantee
that we will be able to obtain such investments. Financing transactions may
include the issuance of equity or debt securities, obtaining credit facilities,
or other financing mechanisms. However, the trading price of our common stock
and a downturn in the North American stock and debt markets could make it more
difficult to obtain financing through the issuance of equity or debt securities.
Even if we are able to raise the funds required, it is possible that we could
incur unexpected costs and expenses, fail to collect significant amounts owed to
us, or experience unexpected cash requirements that would force us to seek
alternative financing. Furthermore, if we issue additional equity or debt
securities, stockholders may experience additional dilution or the new equity
securities may have rights, preferences or privileges senior to those of
existing holders of our common stock. If additional financing is not available
or is not available on acceptable terms, we will have to curtail our
operations.
25
On April
15, 2009 we converted the Windsor Block exploration agreement to a 10 year
production lease for 474,625 gross acres (412,924 net acres) of land. At the end
of the second year of the lease, a technical report is due and the Nova Scotia
government may request the surrender of certain lands they deem not adequately
evaluated. During the first five years of the lease, we agreed to continue to
evaluate the Windsor Block by drilling seven wells, completing three exploration
wells previously drilled and acquiring seismic at a total gross estimate cost of
Cdn $12.7 million (US$11.7 million). At the end of the fifth year of the lease,
areas of the land block not adequately drilled or otherwise evaluated may be
subject to surrender. Since April 15, 2009, we have completed the three
exploration wells drilled in the 2009 and acquired the seismic towards the
production lease commitments. There is a risk that our joint venture partner in
the Windsor Block will not be able to pay for their portion (13%) of the well
costs, which would slow down or stop exploration on the Windsor Block. We
will have to raise additional funds or secure a new joint operating partner in
the Windsor Block to complete the exploration and development phase of our
programs and, while we have been successful in doing so in the past, there can
be no assurance that we will be able to do so in the future. There is a risk
that we may not obtain the necessary additional funds or new joint venture
partner to continue operations and to determine the existence, discovery and
successful exploitation of economically recoverable reserves and the attainment
of profitable operations on our Windsor Block.
Critical
Accounting Policies
Use of
Estimates
The
preparation of financial statements in conformity with U.S. generally accepted
accounting principles requires us to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual results
could differ from those estimates. We base our estimates and assumptions on
current facts, historical experience and various other factors that we believe
to be reasonable under the circumstances, the results of which form the basis
for making judgments about the carrying values of assets and liabilities and the
accrual of costs and expenses that are not readily apparent from other sources.
The actual results experienced by us may differ materially and adversely from
our estimates. To the extent there are material differences between the
estimates and the actual results, future results of operations will be
affected.
Investment in Oil and Gas
Properties
We
utilize the full cost method to account for our investment in oil and gas
properties. Accordingly, all costs associated with acquisition and exploration
of oil and gas reserves, including such costs as leasehold acquisition costs,
interest costs relating to unproven properties, geological expenditures and
direct internal costs are capitalized into the full cost pools. We have two full
costs pools (Canada and U.S.). The full costs pools capitalized costs, including
estimated future costs to develop the reserves and estimated abandonment costs,
net of salvage, are depleted on the units-of-production method using estimates
of proved reserves. Investments in unproven properties and major development
projects including capitalized interest, if any, are not amortized until proved
reserves associated with the projects can be determined or, if the future
exploration of unproven properties is determined uneconomical, the amounts of
such properties are added to the capitalized cost to be amortized. The
capitalized costs included in the full cost pool are subject to a ceiling
test.
Asset Retirement
Obligations
We
recognize a liability for future retirement obligations associated with our oil
and gas properties. The estimated fair value of the asset retirement obligations
is based on the current estimated cost escalated at an inflation rate and
discounted at a credit adjusted risk-free rate. This liability is capitalized as
part of the cost of the related asset and amortized over its useful life. The
liability accretes until we settle the obligation. The costs are estimated by
management based on its knowledge of industry practices, current laws and past
experiences. The costs could increase significantly from management’s current
estimate.
Stock-Based
Compensation
We record
compensation expense in the consolidated financial statements for stock options
granted to employees, consultants and directors using the fair value method.
Fair values are determined using the Black Scholes option pricing model, which
is sensitive to the estimate of our stock price volatility and the options
expected life. Compensation costs are recognized over the vesting
period.
26
Recently Issued Accounting
Pronouncements
Refer to
Note 2(q) of the Financial
Statements.
ITEM
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK.
Not
required under Regulation S-K for “smaller reporting
companies.”
27
ITEM
8. FINANCIAL STATEMENTS.
TRIANGLE
PETROLEUM CORPORATION
INDEX TO
FINANCIAL STATEMENTS
Page
|
||
Report
of Independent Registered Public Accounting Firm
|
F-2
|
|
Consolidated
Balance Sheets as of January 31, 2010 and 2009
|
F-3
|
|
Consolidated
Statements of Operations for each of the years ended January 31, 2010 and
2009
|
F-4
|
|
Consolidated
Statements of Cash Flows for each of the years ended January 31, 2010 and
2009
|
F-5
|
|
Consolidated
Statement of Stockholders' Equity for each of the years ended January 31,
2010 and 2009
|
F-6
|
|
Notes
to the Consolidated Financial Statements
|
F-7
to
F-20
|
F–1
Report
of Independent Registered Public Accounting Firm
The Board
of Directors and Stockholders
Triangle
Petroleum Corporation
We have
audited the accompanying consolidated balance sheets of Triangle Petroleum
Corporation and its subsidiaries as of January 31, 2010 and 2009, and the
related consolidated statements of operations, stockholders’ equity, and cash
flows for the years then ended. These consolidated financial statements are the
responsibility of the Company’s management. Our responsibility is to express an
opinion on these consolidated financial statements based on our
audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our
opinion the consolidated financial statements referred to above present fairly,
in all material respects, the financial position of the Company and its
subsidiaries as of January 31, 2010 and 2009, and the results of its operations
and its cash flows for the years then ended, in conformity with U.S. generally
accepted accounting principles.
/s/ KPMG LLP
|
Calgary,
Canada
|
April
8, 2010
|
F–2
Triangle
Petroleum Corporation
Consolidated
Balance Sheets
(Expressed
in U.S. dollars)
January 31,
2010
$
|
January 31,
2009
$
|
|||||||
ASSETS
|
||||||||
Current
Assets
|
||||||||
Cash
|
4,878,601 | 8,449,471 | ||||||
Prepaid
expenses
|
342,635 | 339,839 | ||||||
Other
receivables
|
313,785 | 998,511 | ||||||
Total
Current Assets
|
5,535,021 | 9,787,821 | ||||||
Property
and Equipment (Note 3)
|
39,296 | 39,765 | ||||||
Oil
and Gas Properties (Note 4)
|
18,783,375 | 16,942,864 | ||||||
Total
Assets
|
24,357,692 | 26,770,450 | ||||||
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
||||||||
Current
Liabilities
|
||||||||
Accounts
payable
|
574,723 | 2,123,079 | ||||||
Accrued
liabilities
|
119,224 | 90,539 | ||||||
Total
Current Liabilities
|
693,947 | 2,213,618 | ||||||
Asset
Retirement Obligations (Note 6)
|
1,180,515 | 727,862 | ||||||
Total
Liabilities
|
1,874,462 | 2,941,480 | ||||||
Commitments
(Note 12)
|
||||||||
Subsequent
Events (Note 14)
|
||||||||
Stockholders’
Equity
|
||||||||
Common
Stock (Note 9)
Authorized: 150,000,000 shares,
par value $0.00001
Issued: 69,926,043 shares (2009
– 69,926,043 shares)
|
699 | 699 | ||||||
Additional
Paid-In Capital (Note 9)
|
81,950,076 | 81,155,715 | ||||||
Warrants
(Note 10)
|
4,237,100 | 4,237,100 | ||||||
Deficit
|
(63,704,645 | ) | (61,564,544 | ) | ||||
Total
Stockholders’ Equity
|
22,483,230 | 23,828,970 | ||||||
Total
Liabilities and Stockholders’ Equity
|
24,357,692 | 26,770,450 |
The
accompanying notes are an integral part of these consolidated financial
statements
F-3
Triangle
Petroleum Corporation
Consolidated
Statements of Operations
(Expressed
in U.S. dollars)
Year
Ended
January 31,
|
Year
Ended
January 31,
|
|||||||
2010
|
2009
|
|||||||
$
|
$
|
|||||||
Revenue,
net of royalties
|
131,245 | 386,892 | ||||||
Operating
Expenses
|
||||||||
Oil
and gas production
|
95,852 | 125,777 | ||||||
Depletion
and accretion
|
188,788 | 200,050 | ||||||
Depreciation
– property and equipment
|
26,198 | 39,448 | ||||||
General
and administrative
|
3,987,012 | 4,045,906 | ||||||
Foreign
exchange (gain) loss
|
(753,950 | ) | 2,682,873 | |||||
Gain
on sale of assets (Note 4)
|
(1,266,294 | ) | (126,314 | ) | ||||
Ceiling
test write-down on oil and gas properties (Note 4)
|
- | 8,308,229 | ||||||
2,277,606 | 15,275,969 | |||||||
Loss
from Operations
|
(2,146,361 | ) | (14,889,077 | ) | ||||
Other
Income (Expense)
|
||||||||
Accretion
of discounts on convertible debentures (note 7)
|
- | (2,922,909 | ) | |||||
Amortization
of debt issue costs
|
- | (182,637 | ) | |||||
Interest
expense
|
- | (753,004 | ) | |||||
Gain
on debt extinguishment (Note 7)
|
- | 3,922,713 | ||||||
Interest
and royalty income
|
6,260 | 260,840 | ||||||
Unrealized
gain on fair value of derivatives (Note 8)
|
- | 793,589 | ||||||
Total
Other Income
|
6,260 | 1,118,592 | ||||||
Loss
for the Year
|
(2,140,101 | ) | (13,770,485 | ) | ||||
Loss
Per Share – Basic and Diluted
|
(0.03 | ) | (0.23 | ) | ||||
Weighted
Average Number of Shares Outstanding – Basic and Diluted
|
69,926,043 | 61,113,000 |
The
accompanying notes are an integral part of these consolidated financial
statements
F-4
Triangle
Petroleum Corporation
Consolidated
Statements of Cash Flows
(Expressed
in U.S. dollars)
Year Ended
January 31,
|
Year Ended
January 31,
|
|||||||
2010
|
2009
|
|||||||
$
|
$
|
|||||||
Operating
Activities
|
||||||||
Loss
for the year
|
(2,140,101 | ) | (13,770,485 | ) | ||||
Adjustments
to reconcile net loss to net cash provided by (used in) operating
activities:
|
||||||||
Accretion
of discounts on convertible debentures (Note 7)
|
- | 2,922,909 | ||||||
Amortization
of debt issue costs
|
- | 182,637 | ||||||
Depletion
and accretion
|
188,788 | 200,050 | ||||||
Depreciation
– property and equipment
|
26,198 | 39,448 | ||||||
Ceiling
test write-down on oil and gas properties (Note 4)
|
- | 8,308,229 | ||||||
Stock-based
compensation (Note 11)
|
794,361 | 598,182 | ||||||
Gain
on sale of assets (Note 4)
|
(1,266,294 | ) | (126,314 | ) | ||||
Gain
on debt extinguishments (Note 7)
|
- | (3,922,713 | ) | |||||
Unrealized
gain on fair value of derivatives (Note 8)
|
- | (793,589 | ) | |||||
Foreign
exchange changes
|
(766,200 | ) | 3,183,463 | |||||
Asset
retirement costs (Note 6)
|
(23,956 | ) | (743,338 | ) | ||||
Changes
in operating assets and liabilities
|
||||||||
Foreign
exchange changes
|
(8,652 | ) | (70,443 | ) | ||||
Prepaid
expenses
|
(22,146 | ) | 129,982 | |||||
Other
receivables
|
706,517 | 691,648 | ||||||
Accounts
payable
|
364,383 | (134,401 | ) | |||||
Accrued
interest on convertible debentures
|
- | (546,302 | ) | |||||
Accrued
liabilities
|
47,162 | (47,058 | ) | |||||
Cash
Used in Operating Activities
|
(2,099,940 | ) | (3,898,095 | ) | ||||
Investing
Activities
|
||||||||
Purchase
of property and equipment
|
(25,729 | ) | (13,090 | ) | ||||
Oil
and gas property expenditures
|
(3,033,254 | ) | (6,065,289 | ) | ||||
Cash
advanced on behalf of partners for oil and gas property
expenditures
|
(677,842 | ) | 677,842 | |||||
Proceeds
received from sale of oil and gas properties (Note 4)
|
1,544,460 | 4,210,306 | ||||||
Cash
Used in Investing Activities
|
(2,192,365 | ) | (1,190,231 | ) | ||||
Financing
Activities
|
||||||||
Proceeds
from issuance of common stock (Note 9)
|
- | 25,560,500 | ||||||
Common
stock issuance costs (Note 9)
|
- | (2,257,959 | ) | |||||
Convertible
debenture repayment (Note 7)
|
- | (11,300,000 | ) | |||||
Cash
Provided by Financing Activities
|
- | 12,002,541 | ||||||
Foreign
exchange change on cash
|
721,435 | (3,046,333 | ) | |||||
Increase
(Decrease) in Cash
|
(3,570,870 | ) | 3,867,882 | |||||
Cash–
Beginning of Year
|
8,449,471 | 4,581,589 | ||||||
Cash–
End of Year
|
4,878,601 | 8,449,471 | ||||||
Non-cash
Investing and Financing Activities
|
||||||||
Common
stock issued for conversion of debentures (Note 9)
|
- | 2,600,140 | ||||||
Supplemental
Disclosures:
|
||||||||
Interest
paid (Note 7)
|
- | 1,299,860 |
The accompanying notes are an integral part of
these consolidated financial statements
F-5
Triangle
Petroleum Corporation
Statement
of Stockholders’ Equity
Years
ended January 31, 2010 and 2009
(Expressed
in U.S. dollars)
Additional
|
||||||||||||||||||||||||
Common Stock
|
Paid-in
|
|||||||||||||||||||||||
Shares
|
Amount
|
Capital
|
Warrants
|
Deficit
|
Total
|
|||||||||||||||||||
#
|
$
|
$
|
$
|
$
|
$
|
|||||||||||||||||||
Balance
– January 31, 2008
|
46,794,530 | 468 | 57,852,277 | – | (47,794,059 | ) | 10,058,686 | |||||||||||||||||
Issuance
of common stock and warrants for cash pursuant to private placement at
$1.40 per unit in June 2008 (Notes 9 and 10)
|
18,257,500 | 182 | 21,323,218 | 4,237,100 | – | 25,560,500 | ||||||||||||||||||
Share
issuance costs (Note 9)
|
– | – | (2,257,959 | ) | – | (2,257,959 | ) | |||||||||||||||||
Issuance
of common stock on conversion of convertible debentures at a weighted
average price of $0.53 per share (Note 9)
|
4,874,013 | 49 | 2,600,091 | – | – | 2,600,140 | ||||||||||||||||||
Fair
value of conversion features of convertible debentures
converted (Note 9)
|
– | – | 1,039,906 | – | – | 1,039,906 | ||||||||||||||||||
Stock
based compensation (Note 11)
|
– | – | 598,182 | – | – | 598,182 | ||||||||||||||||||
Net
loss for the year
|
– | – | – | – | (13,770,485 | ) | (13,770,485 | ) | ||||||||||||||||
Balance
– January 31, 2009
|
69,926,043 | 699 | 81,155,715 | 4,237,100 | (61,564,544 | ) | 23,828,970 | |||||||||||||||||
Stock
based compensation (Note 11)
|
– | – | 794,361 | – | – | 794,361 | ||||||||||||||||||
Net
loss for the year
|
– | – | – | – | (2,140,101 | ) | (2,140,101 | ) | ||||||||||||||||
Balance
– January 31, 2010
|
69,926,043 | 699 | 81,950,076 | 4,237,100 | (63,704,645 | ) | 22,483,230 |
The
accompanying notes are an integral part of these consolidated financial
statements
F-6
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
Triangle
Petroleum Corporation, together with its consolidated subsidiaries (“Triangle”
or the “Company”), is an independent oil and gas company focused primarily on
the acquisition, exploration and development of resource properties consisting
mainly of shale gas reserves. The Company’s primary exploration and
development acreage is located in the Horton Bluff formation of the Maritimes
Basin in Canada. The Company also has minor producing properties in the Fort
Worth Basin and in the Alberta Deep Basin.
1.
|
Nature
of Operations
|
The
Company is primarily engaged in the acquisition, exploration and development of
oil and gas resource properties and has a limited number of producing wells that
generate cash flows from operations. The Company has not generated significant
revenues from operations. The Company expects that significant additional
exploration and development activities will be necessary to established proved
reserves and to commercialize the oil and gas properties.
The
Company believes that it has sufficient funds, including those raised subsequent
to year end (note 14), to maintain its interest in the existing properties and
to maintain core operating, exploration and development activities through to
January 31, 2011. The Company monitors its expenditure budgets and adjusts its
expenditure plans to conform to available funding. However, additional funding
will be required to complete exploration and development activities. The Company
plans to fund future exploration and development activities by offering debt or
equity securities, farm-out arrangements or other means.
2.
|
Summary
of Significant Accounting Policies
|
a)
|
Basis
of Presentation
|
These
financial statements and related notes are presented in accordance with
accounting principles generally accepted in the United States, and are expressed
in U.S. dollars. These consolidated financial statements include the accounts of
the Company and its two wholly-owned subsidiaries, Elmworth Energy Corporation,
incorporated in the Province of Alberta, Canada, and Triangle USA Petroleum
Corporation, incorporated in the State of Colorado, USA. All significant
intercompany balances and transactions have been eliminated. The Company’s
fiscal year-end is January 31.
The
Company’s oil and gas operations are generally conducted jointly with others as
such these financial statements reflect the Company’s proportionate share of
these operations.
b)
|
Use
of Estimates
|
The
preparation of financial statements in conformity with U.S. generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates. The Company regularly
evaluates estimates and assumptions related to the recoverability of proved and
unproven oil and gas expenditures, asset retirement obligations and stock-based
compensation. The Company bases its estimates and assumptions on current facts,
historical experience and various other factors that it believes to be
reasonable under the circumstances, the results of which form the basis for
making judgments about the carrying values of assets and liabilities and the
accrual of costs and expenses that are not readily apparent from other sources.
The actual results experienced by the Company may differ materially and
adversely from the Company’s estimates. To the extent there are material
differences between the estimates and the actual results, future results of
operations will be affected.
c)
|
Foreign
Currency Translation
|
The
Company's functional currency is the United States dollar. Monetary assets and
liabilities denominated in foreign currencies are translated into United States
dollars at rates of exchange in effect at the balance sheet date and gains and
losses are recorded in earnings. Non-monetary assets, liabilities and items
recorded in income arising from transactions denominated in foreign currencies
are translated at rates of exchange in effect at the date of the transaction.
Foreign currency transactions are primarily undertaken in Canadian dollars. The
Company has not, to the date of these financial statements, entered into
derivative instruments to offset the impact of foreign currency
fluctuations.
F-7
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
d)
|
Cash
and Cash Equivalents
|
The
Company considers all highly liquid instruments with maturity of three months or
less at the time of acquisition to be cash equivalents.
e)
|
Property
and Equipment
|
Property
and equipment consists of computer hardware, geophysical software, furniture and
equipment and leasehold improvements, and is recorded at cost. Computer hardware
and geophysical software are depreciated on a straight-line basis over their
estimated useful lives of three years. Furniture and equipment and leasehold
improvements are depreciated on a straight-line basis over their estimated
useful lives of five years.
f)
|
Oil
and Gas Properties
|
The
Company utilizes the full-cost method of accounting for petroleum and natural
gas properties. Under this method, the Company capitalizes all costs
associated with acquisition, exploration and development of oil and natural gas
reserves, including leasehold acquisition costs, geological and geophysical
expenditures, lease rentals on undeveloped properties and costs of drilling
productive and non-productive wells into the full cost pool on a country by
country basis. When the Company obtains proved oil and gas reserves, capitalized
costs, including estimated future costs to develop the proved reserves and
estimated abandonment costs, net of salvage, will be depleted on the
units-of-production method using estimates of proved reserves.
The
Company applies a ceiling test to the capitalized costs in the full cost pool.
The ceiling test limits such costs to the estimated present value, using a ten
percent discount rate, of the future net revenue from proved reserves, based on
current economic and operating conditions. Specifically, the Company computes
the ceiling test so that capitalized cost, less accumulated depletion and
related deferred income tax, do not exceed an amount (the ceiling) equal to the
sum of: (A) the present value of estimated future net revenue computed by
applying prices of oil and gas reserves as prescribed by U.S. standards (with
consideration of price changes only to the extent provided by contractual
arrangements) to estimated future production of proved oil and gas reserves as
of the date of the latest balance sheet presented, less estimated future
expenditures (based on current cost) to be incurred in developing and producing
the proved reserves computed using a discount factor of ten percent and assuming
continuation of existing economic conditions; plus (B) the cost of property not
subject to depletion; plus (C) the lower of cost or estimated fair value of the
unproven properties included in the costs subject to depletion; less (D) income
tax effects related to differences between the book and tax basis of the
property.
For
unproven properties, the Company excludes from capitalized costs subject to
depletion, all costs directly associated with the acquisition and evaluation of
the unproven property until it is determined whether or not proved reserves can
be assigned to the property. Until such a determination is made, the Company
assesses the property to ascertain whether impairment has occurred. In assessing
impairment the Company considers factors such as historical experience and other
data such as primary lease terms of the property, average holding periods of
unproven property, and geographic and geologic data. The Company adds the amount
of impairment assessed to the costs that are subject to depletion and the
ceiling test.
g)
|
Asset
Retirement Obligations
|
The
Company recognizes a liability for future retirement obligations associated with
the Company’s oil and gas properties. The estimated fair value of the
asset retirement obligation is based on the estimated cost escalated at an
inflation rate and discounted at the Company’s credit adjusted risk-free
rate. This liability is capitalized as part of the cost of the
related asset and amortized over its useful life. The liability
accretes until the Company settles the obligation.
F-8
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
h)
|
Debt
Issue Costs
|
The
Company recognizes debt issue costs on the balance sheet as deferred charges,
and amortizes the balance over the term of the related debt using the effective
interest rate method.
i)
|
Revenue
Recognition
|
The
Company recognizes oil and gas revenue when production is sold at a fixed or
determinable price, persuasive evidence of an arrangement exists, delivery has
occurred and title has transferred, and collectability is reasonably assured.
Gas-balancing arrangements are accounted for using the sales
method.
j)
|
Income
Taxes
|
The
Company follows the asset and liability method for recording deferred income
taxes. Under this method, deferred taxes are recognized based on temporary
differences at the balance sheet date using the enacted tax rates. The Company
is required to compute tax asset benefits for net operating losses carried
forward. Potential benefits of deferred income tax assets are not recognized in
the accounts until realization is more likely than not. As of January 31, 2010
and 2009, the Company did not have any amounts recorded pertaining to uncertain
tax positions.
The
Company files federal and provincial income tax returns in Canada and federal,
state and local income tax returns in the U.S., as applicable. The Company may
be subject to a reassessment of federal and provincial income taxes by Canadian
tax authorities for a period of three years from the date of the original notice
of assessment in respect of any particular taxation year. For Canadian income
tax returns, the open tax years range from 2006 to 2010. The U.S. federal
statute of limitations for assessment of income tax is closed for the tax years
ending on or prior to January 31, 2005. In certain circumstances, the U.S.
federal statute of limitations can reach beyond the standard three year period.
U.S. state statutes of limitations for income tax assessment vary from state to
state. Tax authorities of Canada and U.S. have not audited any of the Company’s,
or its subsidiaries’, income tax returns for the open taxation years noted
above.
The
Company recognizes interest and penalties related to uncertain tax positions in
tax expense. During the years ended January 31, 2010 and 2009, there were no
charges for interest or penalties.
k)
|
Basic
and Diluted Net Loss Per Share
(“EPS”)
|
Basic EPS
is computed by dividing net loss available to common stock (numerator) by the
weighted average number of shares outstanding (denominator) during the period.
Diluted EPS gives effect to all dilutive instruments outstanding during the
period including stock options and warrants, using the treasury stock method,
and convertible securities, using the if-converted method. In computing diluted
EPS, the average stock price for the period is used in determining the number of
shares assumed to be purchased from the exercise of stock options or warrants.
Diluted EPS excludes instruments if their effect is anti-dilutive.
l)
|
Financial
Instruments
|
The fair
values of financial instruments, which include cash and cash equivalents, other
receivables, accounts payable and accrued liabilities approximate their carrying
values due to the relatively short time to maturity of these
instruments.
m)
|
Concentration
of Risk
|
The
Company maintains its cash accounts predominately in one commercial bank located
in Calgary, Alberta, Canada. The Company's cash accounts consist of uninsured
and insured business checking accounts and deposits maintained in Canadian and
U.S. dollars. Financial instruments that potentially subject the Company to
concentrations of credit risk consist primarily of cash in excess of insured
amounts. To date, the Company has not incurred a loss relating to this
concentration of credit risk.
F-9
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
n)
|
Derivative
Liabilities
|
The
Company records derivatives at their fair values on the date that they meet the
requirements of a derivative instrument and at each subsequent balance sheet
date. Any change in fair value is recorded as non-operating, non-cash
income or expense at each reporting date. As at January 31, 2010, the Company
has not engaged in any transactions that would be considered derivative
instruments or hedging activities.
o)
|
Comprehensive
Loss
|
As at
January 31, 2010 and 2009, the Company has no items that would be included in
comprehensive loss other than the net loss and, therefore, has not included a
statement of comprehensive loss in the financial statements.
p)
|
Stock-Based
Compensation
|
The
Company records stock based compensation based on the estimated fair values of
all share-based awards made to employees, consultants and directors. All
transactions in which goods or services are received for the issuance of equity
instruments are accounted for based on the fair value of the consideration
received or the fair value or the equity instrument issued, whichever is the
more reliable measure.
The fair
value of share-based awards is estimated on the date of grant using an
option-pricing model and for consultants each period until the award is vested.
The Company uses the Black-Scholes option-pricing model to estimate the fair
value of stock-based awards. This model is affected by the Company’s stock price
as well as assumptions regarding a number of subjective variables. These
subjective variables include, but are not limited to the Company’s expected
stock price volatility over the term of the awards, and actual and projected
employee stock option exercise behaviors. The value of the portion of the award
that is ultimately expected to vest is recognized as an expense in the
consolidated statement of operations over the requisite service
period.
No tax
benefits were attributed to stock-based compensation expense because a full
valuation allowance was maintained for all net deferred tax assets.
q)
|
Recently
Adopted Accounting
Pronouncements
|
U.S.
accounting standards setters have implemented new standards in December 2007
with respect to accounting for business combinations. These new standards
require an acquirer to be identified for all business combinations and applies
the same method of accounting for business combinations – the acquisition method
– to all transactions. In addition, transaction costs associated with
acquisitions are required to be expensed. The revised statement was effective to
business combinations after February 1, 2009. No business combinations were
completed in fiscal 2010. There was no impact that arose from adopting the new
business combination standard.
In
December 2007, new accounting standards were issued with respect to
non-controlling interests in consolidated financial statements. These new
standards require the Company to report non-controlling interest in subsidiaries
as equity in the consolidated financial statements; and all transactions between
equity and non controlling interests as equity. These new standards were
effective for the Company commencing on February 1, 2009. The adoption of these
standards did not affect the Company's financial statements.
In March
2008, new accounting standards were issued with respect to disclosures about
derivative instruments and hedging activities, which require disclosures about
how and why an entity uses derivative instruments, how derivative instruments
and related hedged items are accounted for, and how derivative instruments and
related hedged items affect an entity’s financial position, financial
performance and cash flows. These new standards were effective on February 1,
2009. No business combinations were completed in fiscal 2010; therefore, there
was no impact that arose from adopting the new business combination
standard.
F-10
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
In May
2009, new accounting standards were issued with respect to subsequent events,
which are intended to establish general standards of accounting for and
disclosure of events that occur after the balance sheet date but before
financial statements are issued or are available to be issued. In
particular, these standards set forth the period after the balance sheet date
during which management of a reporting entity should evaluate events or
transactions that may occur for potential recognition or disclosure in the
financial statements; the circumstances under which an entity should recognize
events or transactions occurring after the balance sheet date in its financial
statements; and the disclosures that an entity should make about events or
transactions that occurred after the balance sheet date. These standards are
effective for interim and annual periods ending after June 15, 2009. The
adoption of this standard did not significantly impact the disclosures in the
Company’s financial statements.
The
Securities and Exchange Commission adopted major revisions to its required oil
and gas reporting disclosures which became effective as of December 31,
2009. Among other things, the amendments provide for the use of the
12-month average price, calculated as the unweighted arithmetic average of the
first-day-of-the-month price for each month within the 12-month period prior to
the end of the reporting period for purposes of both the disclosure and
full-cost accounting rules. These amendments did not have a
significant impact on the Company’s financial statements.
3.
|
Property
and Equipment
|
January 31, 2010
|
January 31, 2009
|
|||||||||||||||||||||||
Cost
$
|
Accumulated
Depreciation
$
|
Net
Carrying
Value
$
|
Cost
$
|
Accumulated
Depreciation
$
|
Net
Carrying
Value
$
|
|||||||||||||||||||
Computer
hardware
|
81,280 | 73,805 | 7,475 | 80,748 | 65,706 | 15,042 | ||||||||||||||||||
Furniture
and equipment
|
50,398 | 38,296 | 12,102 | 49,674 | 28,289 | 21,385 | ||||||||||||||||||
Computer
software
|
37,010 | 17,291 | 19,719 | 12,537 | 9,199 | 3,338 | ||||||||||||||||||
Leasehold Improvements
|
7,927 | 7,927 | – | 7,927 | 7,927 | – | ||||||||||||||||||
176,615 | 137,319 | 39,296 | 150,886 | 111,121 | 39,765 |
4.
|
Oil
and Gas Properties
|
All of
the Company’s oil and gas properties are located in the United States and
Canada. The following table summarizes information regarding the Company's oil
and gas acquisition, exploration and development activities:
January 31, 2010
|
January 31, 2009
|
|||||||||||||||||||||||
Canada
|
US
|
Total
|
Canada
|
US
|
Total
|
|||||||||||||||||||
|
$
|
$
|
$
|
$
|
$
|
$
|
||||||||||||||||||
Proved
Properties:
|
||||||||||||||||||||||||
Opening
net costs
|
72,869 | - | 72,869 | 324,162 | 89,747 | 413,909 | ||||||||||||||||||
Additions
|
2,207 | 14,454 | 16,661 | 13,984 | 40,450 | 54,434 | ||||||||||||||||||
Depletion
|
(24,327 | ) | (14,454 | ) | (38,781 | ) | (86,825 | ) | (5,922 | ) | (92,747 | ) | ||||||||||||
Proceeds
on dispositions
|
(426,600 | ) | (1,117,860 | ) | (1,544,460 | ) | (2,943,510 | ) | (1,266,796 | ) | (4,210,306 | ) | ||||||||||||
Costs
transferred from unproven properties
|
222,917 | 4,500 | 227,417 | 3,073,287 | 9,016,207 | 12,089,494 | ||||||||||||||||||
Ceiling
test write-downs
|
- | - | - | (308,229 | ) | (8,000,000 | ) | (8,308,229 | ) | |||||||||||||||
Gain on sale of assets
|
152,934 | 1,113,360 | 1,266,294 | - | 126,314 | 126,314 | ||||||||||||||||||
Closing
net proved costs
|
- | - | - | 72,869 | - | 72,869 | ||||||||||||||||||
Closing net unproven costs
|
18,783,375 | - | 18,783,375 | 16,869,995 | - | 16,869,995 | ||||||||||||||||||
Closing Oil and Gas
Properties
|
18,783,375 | - | 18,783,375 | 16,942,864 | - | 16,942,864 |
F-11
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
During
the year ended January 31, 2010:
Canada:
|
·
|
In
January 2010, the Company sold its interests in an Alberta gas well and
896 gross acres of undeveloped land (108 net acres) for gross proceeds of
$426,600. The net book value of the Canadian full cost pools subject to
depletion at the time of the sale was $273,666. As such, the Company
recorded a gain on the sale of assets of
$152,934.
|
U.S.
|
·
|
In
June 2009, the Company sold its 25% working interest in 17,307 gross acres
(4,327 net acres) of undeveloped land in the Nugget area of Colorado
(Rocky Mountains project) for cash of $83,325 and recovered a drilling
deposit in the Fayetteville area of Arkansas for cash of $50,000. The net
book value of the U.S. properties at the time of sale was $8,704. As such,
the Company recorded a gain on sale of assets of
$124,621.
|
|
·
|
In
September 2009, the Company sold its 50% working interest in 11,800 gross
acres (5,900 net acres) of undeveloped land in the Fayetteville area of
Arkansas and all the related seismic rights for net cash proceeds of
$744,408. The acquirer also assumed the non-cash asset retirement
obligations pertaining thereto of $39,375. The net book value of the U.S.
properties at the time of sale was $171. As such, the Company recorded a
gain on sale of assets of $783,612.
|
|
·
|
In
November 2009, the Company sold its 50% working interest in its remaining
6,760 gross acres (3,880 net acres) of undeveloped land in the
Fayetteville area of Arkansas for net cash proceeds of $240,127. The net
book value of the U.S. properties at the time of sale was $35,000. As
such, the Company recorded a gain on sale of assets of
$205,127.
|
During
the year ended January 31, 2009:
Canada:
|
·
|
At
January 31, 2009, the Company’s proved properties in Alberta exceeded the
ceiling test limit as described in Note 2(f), which resulted in a $308,229
non-cash ceiling test write-down being
recognized.
|
|
·
|
In
July 2008, the Company received cash of $2,943,510 for a partner’s share
of its 30% working interest in exploration costs associated with the
Windsor Block of Nova Scotia.
|
U.S.
|
·
|
In
June 2008, the Company sold its interests in a Barnett shale well for
gross proceeds of $164,985. The acquirer also assumed the related asset
retirement obligation of $7,545. Also in June 2008, the Company sold its
25% working interest in 38,768 gross acres (9,692 net acres) of
undeveloped land in the Phat City area of Montana (Rocky Mountains
project) for cash of $800,503. The net book value of the U.S. full cost
pools subject to depletion at the time of the sales was $962,328. As such,
the Company recorded a gain on the sale of assets of
$10,705.
|
|
·
|
In
September 2008, the Company sold 20 of its 10,437 net Fayetteville acres
for $13,000. The net book value of the U.S. full cost pools subject to
depletion at the time of the sales was $8,013,000. As such, an $8,000,000
non-cash ceiling test write-down was
recognized.
|
|
·
|
In
November 2008, the Company sold 240 of its 10,417 net Fayetteville acres
for cash of $288,308. The net book value of the U.S. full cost pools
subject to depletion at the time of the sale was $172,699. As a result,
the Company recorded a gain on the sale of assets of
$115,609.
|
F-12
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
Unproven
Properties
Canada
|
U.S.
|
|||||||||||||||||||||||
Nova
Scotia
|
New
Brunswick
|
Western
Canada
Shale
|
Fayetteville
|
Rocky
Mountains
|
Total
|
|||||||||||||||||||
$
|
$
|
$
|
$
|
$
|
$
|
|||||||||||||||||||
Opening,
January 31, 2008
|
15,441,144 | 21,975 | - | 8,289,901 | 812,020 | 24,565,040 | ||||||||||||||||||
Additions
|
4,320,952 | 107,802 | 51,409 | (104,202 | ) | 18,488 | 4,394,449 | |||||||||||||||||
Costs transferred to depletion
base
|
(2,943,510 | ) | (129,777 | ) | - | (8,185,699 | ) | (830,508 | ) | (12,089,494 | ) | |||||||||||||
Closing,
January 31, 2009
|
16,818,586 | - | 51,409 | - | - | 16,869,995 | ||||||||||||||||||
Additions
|
1,964,789 | - | 171,508 | 4,500 | - | 2,140,797 | ||||||||||||||||||
Costs transferred to depletion
base
|
- | - | (222,917 | ) | (4,500 | ) | - | (227,417 | ) | |||||||||||||||
Closing, January 31, 2010
|
18,783,375 | - | - | - | - | 18,783,375 |
Canada
|
·
|
In
Canada, $18,783,375 (2009 - $16,869,995) of unproven property costs were
excluded from costs subject to depletion which relate to Canadian shale
gas exploration costs mainly in the Windsor Block of the Maritimes Basin.
The Company anticipates that these costs will be subject to depletion in
fiscal 2013, when the Company anticipates having confirmed commerciality
of the Windsor Block and pipelines are built and commissioned to market
potential gas from the Windsor
Block.
|
|
·
|
In
July 2008, the Company received cash of $2,943,510 for a partner’s share
of its 30% working interest in exploration costs associated with the
Windsor Block of Nova Scotia. As such, the related costs of the properties
disposed of $2,943,510 became subject to amortization in the Canadian full
cost pool.
|
|
·
|
In
December 2008, the Company elected to not drill a test well on the Beech
Hill Block thus forfeiting its right to earn on the Block. The carrying
value of these unproven property costs of $129,777 was considered impaired
and became subject to amortization in the Canadian full cost
pool.
|
|
·
|
In
June 2009, the Company acquired an additional 30% working interest in the
Windsor Block of the Maritimes Basin in Nova Scotia from Contact
Exploration Inc. (“Contact”) for a cash payment of approximately $245,000.
The Company also agreed to provide Contact a 5.75% non-convertible gross
overriding royalty interest and assumed the liabilities related to
Contact's former working interest.
|
|
·
|
At
January 31, 2010, the Western Canada Shale costs of $222,917 were
considered impaired and became subject to amortization in the Canadian
full cost pool.
|
United
States
|
·
|
In
June 2008, the Company sold its 25% working interest in 9,692 net acres in
the Phat City area of Montana (Rocky Mountains project). The net book
value of the Rocky Mountains project at the time of the sale was $830,508
which became subject to amortization in the U.S. full cost
pool.
|
|
·
|
In
September 2008, the Company sold 20 of its 10,437 net Fayetteville acres.
The related unproven Fayetteville land costs of $8,013,000 became subject
to amortization in the U.S. full cost
pool.
|
|
·
|
In
November 2008, the Company sold 240 of its 10,417 net Fayetteville acres
for cash of $288,308. The related remaining unproven Fayetteville land
costs $172,699 became subject to amortization in the U.S. full cost
pool.
|
F-13
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
5.
|
Natural
gas and oil reserves (unaudited)
|
The gas
and oil reserve quantities owned by the Company were estimated by the
independent petroleum engineering firm of Ryder Scott, Inc. at January 31,
2009. The Company did not obtain a reserve report at January 31, 2010
as the proved reserves are not material. The following table summarizes the
changes in the Company’s proved natural gas and oil reserves for the years ended
January 31, 2009 and 2010:
Gas (MMcf)
|
Liquids (Bbls)
|
Total (MMcfe)
|
||||||||||||||||||||||||||||||||||
Canada
|
US
|
Total
|
Canada
|
US
|
Total
|
Canada
|
US
|
Total
|
||||||||||||||||||||||||||||
Proved
reserves, February 1, 2008
|
103 | 7 | 111 | 1,846 | - | 1,846 | 114 | 7 | 122 | |||||||||||||||||||||||||||
Revisions
of previous estimates
|
(34 | ) | 66 | 32 | (29 | ) | 12 | (17 | ) | (34 | ) | 66 | 32 | |||||||||||||||||||||||
Production
|
(27 | ) | (17 | ) | (44 | ) | (639 | ) | (12 | ) | (651 | ) | (31 | ) | (17 | ) | (48 | ) | ||||||||||||||||||
Proved
reserves, February 1, 2009
|
42 | 56 | 98 | 1,178 | - | 1,178 | 49 | 56 | 105 | |||||||||||||||||||||||||||
Revisions
of previous estimates
|
(20 | ) | (38 | ) | (58 | ) | - | - | - | (20 | ) | (38 | ) | (58 | ) | |||||||||||||||||||||
Sales
of reserves
|
(5 | ) | - | (5 | ) | (334 | ) | - | (334 | ) | (7 | ) | - | (7 | ) | |||||||||||||||||||||
Production
|
(17 | ) | (18 | ) | (35 | ) | (844 | ) | - | (844 | ) | (22 | ) | (18 | ) | (40 | ) | |||||||||||||||||||
Proved
reserves, February 1, 2010
|
- | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||
Proved
developed reserves:
|
||||||||||||||||||||||||||||||||||||
Beginning
of year
|
42 | 56 | 98 | 1,178 | - | 1,178 | 49 | 56 | 105 | |||||||||||||||||||||||||||
End
of year
|
- | - | - | - | - | - | - | - | - |
MMcf
– Millions of cubic feet
|
Bbls
– Barrels
|
MMcfe
– Millions of cubic feet equivalent
|
(1
Bbls = 6 Mcfe = 0.006 MMcfe)
|
The
“Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Natural Gas and Oil Reserves” (standardized measure) is a disclosure required
under U.S. GAAP. The standardized measure does not purport to present the
fair market value of a company’s proved gas and oil reserves. In addition, there
are uncertainties inherent in estimating quantities of proved
reserves.
The
following table is the standardized measure relating to proved gas and oil
reserves at January 31, 2010 and, 2009:
Year Ended January 31, 2010
|
Year Ended January 31, 2009
|
|||||||||||||||||||||||
Canada
|
US
|
Total
|
Canada
|
US
|
Total
|
|||||||||||||||||||
Future
cash inflows
|
$ | - | $ | - | $ | - | $ | 257,474 | $ | 331,049 | $ | 588,523 | ||||||||||||
Future production costs
|
- | - | - | 179,509 | 236,863 | 416,372 | ||||||||||||||||||
Future
net cash flows
|
- | - | - | 77,965 | 94,186 | 172,151 | ||||||||||||||||||
10% annual discount for estimated timing of cash
flows
|
- | - | - | 4,675 | 11,063 | 15,738 | ||||||||||||||||||
Standardized measure of discounted future net cash
flows
|
$ | - | $ | - | $ | - | $ | 73,290 | $ | 83,123 | $ | 156,413 |
Under the
standardized measure at January 31, 2009, future cash inflows were estimated by
applying year-end prices, adjusted for known contractual changes, to the
estimated future production of year-end proved reserves. Year-end market prices
used for the standardized measures above were $5.62 per Mcf for Canadian
gas, $5.78 per Mcf for U.S. gas and $30.52 per barrel for liquids in 2009.
Future cash inflows were reduced by estimated future production and
development costs based on year-end costs to determine pre-tax cash inflows.
Future income taxes were computed by applying the year-end statutory rate, after
consideration of permanent differences, to the excess of pre-tax cash inflows
over the Company’s tax basis in the associated proved gas and oil properties.
Future net cash inflows after income taxes were discounted using a 10% annual
discount rate to arrive at the standardized measure.
F-14
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
The
Company had three producing wells at the end of 2010 that were not assigned any
proved reserves. The following table is an analysis of changes in the
standardized measure during the year ended January 31, 2010 and
2009:
Canada
|
US
|
Total
|
||||||||||
Standardized
measure, January 31, 2008
|
$ | 329,979 | $ | 16,711 | $ | 346,690 | ||||||
Sales
and transfers of gas and oil produced, net of production
costs
|
(185,499 | ) | (75,617 | ) | (261,116 | ) | ||||||
Accretion
of discount
|
32,998 | 1,671 | 34,669 | |||||||||
Other
|
(104,188 | ) | 140,358 | 36,170 | ||||||||
Standardized
measure, January 31, 2009
|
73,290 | 83,123 | 156,413 | |||||||||
Sales
and transfers of gas and oil produced, net of production
costs
|
(21,270 | ) | (14,123 | ) | (35,393 | ) | ||||||
Accretion
of discount
|
7,329 | 8,312 | 15,641 | |||||||||
Other
|
(59,349 | ) | (77,312 | ) | (136,661 | ) | ||||||
Standardized measure, January 31,
2010
|
$ | - | $ | - | $ | - |
6.
|
Asset
Retirement Obligations
|
A
reconciliation of the changes in the asset retirement obligations is as
follows:
January 31,
2010
$
|
January 31,
2009
$
|
|||||||
Balance,
beginning of year
|
727,862 | 1,003,353 | ||||||
Liabilities
incurred
|
357,807 | 548,312 | ||||||
Liabilities
settled as part of disposition
|
(31,205 | ) | (187,768 | ) | ||||
Liabilities
settled in cash
|
(23,956 | ) | (743,338 | ) | ||||
Accretion
|
150,007 | 107,303 | ||||||
Total asset retirement
obligations
|
1,180,515 | 727,862 |
The asset
retirement obligations were estimated based on a discount rate of 15%-30%, an
inflation rate of 2.5%-3.3% and settlement from 1 to 24 years. The total cost
estimate prior to discounting was approximately $1.5 million at January 31, 2010
(2009 - $1.1 million).
7.
|
Convertible
Debentures
|
Agreement Date
|
December 8,
2005
$
|
December 28,
2005
$
|
Total
$
|
|||||||||
Balance,
January 31, 2008
|
4,778,271 | 6,770,721 | 11,548,992 | |||||||||
Converted
|
(2,100,140 | ) | (3,500,000 | ) | (5,600,140 | ) | ||||||
Accretion
– expensed
|
815,052 | 2,107,857 | 2,922,909 | |||||||||
Repaid
|
(4,000,000 | ) | (6,500,000 | ) | (10,500,000 | ) | ||||||
Accretion – settled on
repayment
|
506,817 | 1,121,422 | 1,628,239 | |||||||||
Balance, January 31, 2009 and
2010
|
- | - | - | |||||||||
Interest rate
|
5 | % | 7.5 | % |
F-15
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
December 8, 2005
Debentures
On June
5, 2008, the Company repaid the remaining unconverted convertible debentures
that were issued on December 8, 2005 of $4,000,000 plus an early redemption fee
of $800,000 and accrued interest of $1,299,860. The carrying value of the
debentures at the time of repayment, including the conversion feature of the
debenture that was accounted for as a derivative, was $4,639,338, which is equal
to the face value of $4,000,000, less unamortized discounts of $506,817 and
deferred financing costs of $283,196, plus the derivative liability of
$1,429,351. The Company paid $4,800,000 on settlement ($4,000,000 face value
plus a 20% early redemption fee of $800,000); therefore a $160,662 loss was
recorded on the extinguishment of the debenture.
December 28, 2005
Debentures
In
December 2008, the Company settled the $10,000,000 December 28, 2005 convertible
debentures through a reduction in the conversion price from $4.00 per share to
$1.40 per share whereby $3,500,000 of the debentures were converted into
2,500,000 common shares, which had a fair value on the date of conversion of
$500,000. In addition, the Company also entered into settlement agreements for
the remaining debenture of $6,500,000 plus $2,204,792 in accrued interest,
whereby the convertible debentures holders agreed to accept $6,500,000 in cash
for the final settlement of the debentures and the accrued interest. A gain of
$4,083,375 was recorded on this debt extinguishment.
8.
|
Derivative
Liabilities
|
The
Company was required to bifurcate and separately account for the embedded
conversion feature contained in the December 8, 2005 convertible debenture as a
derivative. The Company was required to record the derivative at the estimated
fair value on each balance sheet date with changes in fair values reflected in
the statement of operations.
Fair Value
$
|
||||
January
31, 2008
|
3,262,846 | |||
-Conversion
features settled
|
(1,039,906 | ) | ||
-Change
in fair value
|
(793,589 | ) | ||
-Conversion features settled on
repayment
|
(1,429,351 | ) | ||
January 31, 2009 and 2010
|
- |
9.
|
Common
Stock
|
Shares
|
Common
Stock
|
Additional
Paid-In
Capital
|
||||||||||
#
|
$
|
$
|
||||||||||
January
31, 2008
|
46,794,530 | 468 | 57,852,277 | |||||||||
Private
Placement, net of share issuance costs of $2,257,959 (a)
|
18,257,500 | 182 | 19,065,259 | |||||||||
Conversion
of debentures (b)
|
4,874,013 | 49 | 3,639,997 | |||||||||
Stock Based Compensation (Note
11)
|
- | - | 598,182 | |||||||||
January
31, 2009
|
69,926,043 | 699 | 81,155,715 | |||||||||
Stock Based Compensation (Note
11)
|
- | - | 794,361 | |||||||||
January 31, 2010
|
69,926,043 | 699 | 81,950,076 |
F-16
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
(a)
|
On
June 3, 2008, 18,257,500 units were issued in a private placement for
gross proceeds of $25,560,500. The net proceeds after deducting expenses
were $23,302,541. The Company paid the placement agents of the offering a
cash fee of 7% of the gross proceeds of the offering. Each unit was priced
at $1.40 per unit and consists of one share of common stock (relative fair
value of $21,323,400 or $1.168 per share) and one-half share purchase
warrant (relative fair value of $4,237,100 or $0.232 per unit – see Note
10). One full warrant can be exercised into one share of common stock for
a period of two years at a price of $2.25 per share. Pursuant to the terms
of the sale, the Company was required, on a best efforts basis, to file a
registration statement with the SEC, and to cause such registration
statement to be declared effective by the SEC, within 150 days after
closing, to permit the public resale of the shares underlying the
warrants. The registration statement was declared effective by
the SEC on July 14, 2008. Also, pursuant to the terms of the sale, the
Company was required, on a best efforts basis, to list the Company’s
shares on the Toronto Stock Exchange (which includes the TSX Venture
Exchange) on or before December 31, 2008. The Company’s shares
of common stock commenced trading on the TSX Venture Exchange on December
5, 2008.
|
(b)
|
During
the year ended January 31, 2009, $2,100,140 convertible debentures that
were issued December 8, 2005 were converted into 2,374,013 shares of
common stock. The fair value of the conversion feature related to the
converted debentures was $1,039,906, which was transferred from the
derivative liability to additional paid-in capital upon conversion. Also,
during the year ended January 31, 2009, $3,500,000 convertible debentures
that were issued December 28, 2005 were converted into 2,500,000 shares of
common stock, which had a fair value on the date of conversion of $500,000
and was recorded to additional paid-in
capital.
|
10.
|
Warrants
|
As at
January 31, 2010, the Company had 9,128,750 warrants outstanding that can be
exercised into 9,128,750 shares of common stock at a price of $2.25 per share,
which expire on June 3, 2010. The warrants were granted on June 3, 2008, at
which time they had a relative fair value compared to the common stock issued of
$4,237,100.
11.
|
Stock
Options
|
Effective
August 5, 2005, the Company approved the 2005 Incentive Stock Plan (the “2005
Plan”) to issue up to 2,000,000 shares of common stock. Effective August 17,
2007, the Company approved the 2007 Incentive Stock Plan (the “2007 Plan”) to
issue up to 2,000,000 shares of common stock. Pursuant to the 2005 Plan and 2007
Plan, stock options vest 20% upon granting and 20% every six months, and allowed
for the granting of stock options at a price of not less than fair value of the
stock and for a term not to exceed five years. As at January 31, 2009, the
Company had no stock options available for granting pursuant to the 2005 Plan
and 2007 Plan since, in connection with the TSX Venture Exchange listing in
December 2008, the Company agreed it would not issue any more stock options
under the 2005 Plan and 2007 Plan.
Effective
January 28, 2009, the Company’s Board of Directors approved a Stock Option Plan
(the “Rolling Plan”) whereby the number of authorized but unissued Common Shares
that may be issued upon the exercise of stock options granted under the Rolling
Plan at any time plus the number of Common Shares reserved for issuance under
the outstanding 2005 Plan and the 2007 Plan shall not exceed 10% of the issued
and outstanding Common Shares on a non-diluted basis at any time, and such
aggregate number of Common Shares shall automatically increase or decrease as
the number of issued and outstanding common shares change. Pursuant to the
Rolling Plan, stock options become exercisable as to one-third on each of the
first, second and third anniversaries of the date of the grant, and allow for
the granting of stock options at a price of not less than fair value of the
common shares and for a term not to exceed ten years. As at January 31, 2010,
the Company had 1,292,604 stock options available for granting pursuant to the
Rolling Plan.
The
weighted average grant date fair value of the 3,050,000 (2009 -
3,800,000) stock options granted during the year ended January 31, 2010 was
$0.10 per share (2009 – $0.35 per share). No stock options were exercised during
the years ended January 31, 2010 and 2009. During the year ended January 31,
2009, the Company granted, to non-executives/directors, 775,000 stock options
under the Rolling Plan (“New Options”) to replace 950,000 forfeited stock
options under the 2005 Plan and 2007 Plan (“Old Options”), which was treated as
a modification. Under modification rules, the remaining unamortized original
grant date fair value of the Old Options at modification date, along with the
incremental fair value of the New Options over the Old Options at modification
date, is expensed over the New Options vesting period of three years. During the
year ended January 31, 2010 and 2009, the Company recorded stock-based
compensation related to stock option grants of $794,361 and $598,182,
respectively, as general and administrative expense.
F-17
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
A summary
of the Company’s stock option activity is as follows:
Options
#
|
Weighted
Average Exercise
Price
$
|
Aggregate
Intrinsic
Value
$
|
||||||||||
Outstanding,
January 31, 2008
|
2,580,000 | 2.54 | ||||||||||
Granted
|
3,800,000 | 0.67 | ||||||||||
Cancelled
|
(950,000 | ) | 2.61 | |||||||||
Forfeited
|
(445,000 | ) | 2.30 | |||||||||
Outstanding,
January 31, 2009
|
4,985,000 | 1.14 | - | |||||||||
Granted
|
3,050,000 | 0.14 | ||||||||||
Cancelled
|
(50,000 | ) | 1.40 | |||||||||
Forfeited
|
(2, 285,000 | ) | 1.35 | |||||||||
Outstanding, January 31,
2010
|
5,700,000 | 0.52 | 675,357 | |||||||||
Exercisable, January 31,
2010
|
1,836,667 | 1.26 | 50,267 |
A summary
of the Company’s stock options outstanding is as follows:
Exercise price
$
|
Options
Outstanding
#
|
Weighted
Average
Remaining
Contractual
Life (years)
|
Options
Exercisable
#
|
Aggregate
Intrinsic
Value
$
|
||||||||||||
0.125
|
2,800,000 | 4.83 | - | 675,357 | ||||||||||||
0.25
(CDN$0.30)
|
2,050,000 | 3.27 | 1,016,667 | - | ||||||||||||
1.40
|
150,000 | 3.42 | 120,000 | - | ||||||||||||
2.00
|
300,000 | 2.52 | 300,000 | - | ||||||||||||
3.23
|
400,000 | 0.78 | 400,000 | - | ||||||||||||
Balance, end of year
|
5,700,000 | 3.83 | 1,836,667 | 675,357 |
The fair
value of each option grant was estimated on the date of the grant using the
Black-Scholes option pricing model with the following weighted average
assumptions:
Year Ended
January 31,
2010
|
Year Ended
January 31,
2009
|
|||||||
Expected
dividend yield
|
0 | % | 0 | % | ||||
Expected
volatility
|
130 | % | 104 | % | ||||
Expected
life (in years)
|
4.0 | 3.5 | ||||||
Risk-free
interest rate
|
1.60 | % | 1.71 | % |
F-18
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
As at
January 31, 2010, there was $468,260 (2009 - $1,082,880) of total unrecognized
compensation costs related to non-vested share-based compensation arrangements
granted under the 2005 Plan, 2007 Plan and Rolling Plan which are expected to be
recognized over a weighted-average period of 2.6 years. The total fair value of
shares vested during the years ended January 31, 2010 and 2009 was $676,067 and
$1,079,397, respectively.
A summary
of the status of the Company’s non-vested shares as of January 31, 2010, and
changes during the years ended January 31, 2010 and 2009, is presented
below:
Non-vested shares
|
Shares
#
|
Weighted-Average
Grant-Date Fair Value
$
|
||||||
January
31, 2008
|
1,250,000 | 0.93 | ||||||
Granted
|
3,800,000 | 0.33 | ||||||
Vested
|
(1,165,000 | ) | 0.93 | |||||
Cancelled
|
(290,000 | ) | 0.70 | |||||
Forfeited
|
(70,000 | ) | 0.69 | |||||
January
31, 2009
|
3,525,000 | 0.31 | ||||||
Granted
|
3,050,000 | 0.10 | ||||||
Vested
|
(1,711,667 | ) | 0.39 | |||||
Cancelled
|
(10,000 | ) | 0.78 | |||||
Forfeited
|
(990,000 | ) | 0.28 | |||||
January 31, 2010
|
3,863,333 | 0.11 |
12.
|
Commitments
|
The
Company entered into a 10-year production lease for 474,625 gross acres on the
Windsor Block in Nova Scotia, Canada on April 15, 2009. During the first five
years of the lease, Triangle has agreed to continue to evaluate the Windsor
Block by drilling seven wells, completing three wells previously drilled and
acquiring seismic, which was estimated to cost Cdn $12.7 million gross
(approximately US$11.8 million). At the end of the fifth year of the lease,
areas of the block not adequately drilled or otherwise evaluated may be subject
to surrender. Furthermore, at the end of the second year of the lease, a
technical report is required to be provided to and assessed by the Nova Scotia
government to maintain certain lands.
During
the first year of the lease, the Company has agreed to perform completion
operations on the three wells drilled in the prior year and acquire seismic,
which was estimated to cost Cdn $2 million gross (approximately US$1.9 million).
The Company posted a Cdn $200,000 (approximately US$189,000) gross refundable
deposit related to the first year commitment; should the Company not perform the
work, a portion or all of the deposit could be forfeited. As of January 31,
2010, all three of the required well completions have been performed and the
seismic has been acquired, which satisfied the first year lease
requirements.
13.
|
Income
Taxes
|
Income
tax expense differs from the amount that would result from applying the U.S
federal, state and Canadian income tax rates to the loss before income taxes.
The reconciliation of the provision for income taxes to the expected tax
provision based on the loss for the year multiplied by the weighted average
statutory tax rate of 32.37% (2009 – 37.52%) is as follows:
F-19
Triangle
Petroleum Corporation
Notes to
the Consolidated Financial Statements
(Expressed
in U.S. dollars, except as noted)
2010
$
|
2009
$
|
|||||||
Expected
income tax benefit
|
692,804 | 5,058,194 | ||||||
Stock-based
compensation
|
(301,857 | ) | (227,309 | ) | ||||
Non-deductible
interest and accretion for convertible debentures
|
- | (1,396,847 | ) | |||||
Non-taxable
gain on change in fair value of derivatives
|
- | 301,564 | ||||||
Non-taxable
portion of gain on debt extinguishment
|
- | 762,355 | ||||||
Change
in tax rates
|
(557,126 | ) | (680,014 | ) | ||||
Changes
in valuation allowance
|
1,066,015 | (3,904,783 | ) | |||||
Other
|
(899,836 | ) | 86,840 | |||||
Provision for income taxes
|
– | – |
The
significant components of the Company’s deferred tax assets and liabilities as
at January 31, 2010 and 2009 are as follows:
2010
$
|
2009
$
|
|||||||
Deferred
income tax assets
|
||||||||
Resource
properties
|
2,697,192 | 8,659,221 | ||||||
Net losses carried forward (expire from 2023 to
2029)
|
12,769,031 | 7,873,017 | ||||||
Gross
deferred income tax assets
|
15,466,223 | 16,532,238 | ||||||
Valuation allowance
|
(15,466,223 | ) | (16,532,238 | ) | ||||
Net deferred income tax
asset
|
– | – |
The
Company has recognized a valuation allowance for the deferred income tax asset
since the Company cannot be assured that it is more likely than not that such
benefit will be utilized in future years. The valuation allowance is reviewed
quarterly. When circumstances change and which cause a change in management's
judgment about the realizability of deferred income tax assets, the impact of
the change on the valuation allowance is generally reflected in
earnings.
14.
|
Subsequent
Events
|
In
February 2010, the Company purchased 4,000 net acres in the Williston Basin of
North Dakota that is prospective for the Bakken Shale from Slawson Exploration
for $2,973,000.
In
February 2010, the Company issued 2,100,000 Deferred Stock Units to employees
and directors of the Company, which vest one year after issuance. Once the
Deferred Stock Units vest on February 2, 2011, they will automatically be
exchanged for shares of Triangle Petroleum common stock on a one-for-one basis
without any action required by the holder. Also in February 2010, the Company
cancelled 850,000 stock options that were granted to directors of the Company
under the 2005 Plan and 2007 Plan that had exercise prices ranging from
$1.40-$3.23.
In March
2010, the Company sold an aggregate of 27,993,939 shares of common stock to
certain accredited investors for aggregate proceeds of $9,238,000 (net proceeds
of approximately $8,300,000).
F-20
ITEM
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
ITEM
9A – CONTROLS AND PROCEDURES
MANAGEMENT’S
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Disclosure
controls and procedures have been designed to ensure that information required
to be disclosed by the Company is collected and communicated to the management
to allow timely decisions regarding required disclosures. The Chief
Executive Officer and the Chief Financial Officer have concluded, based on their
evaluation as of January 31, 2010 that, as a result of the material weaknesses
described below, disclosure controls and procedures were ineffective in
providing reasonable assurance that material information is made known to them
by others within the Corporation.
MANAGEMENT’S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with US GAAP. Management has
assessed the effectiveness of internal control over financial reporting based on
the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission (“COSO”) in Internal Control-Integrated
Framework. A
material weakness, as defined by SEC rules, is a control deficiency, or
combination of control deficiencies, such that there is a reasonable possibility
that a material misstatement of the annual or interim financial statements will
not be prevented or detected on a timely basis. The material weakness in
internal control over financial reporting that was identified is:
|
a)
|
We
did not have sufficient personnel in our accounting and financial
reporting functions. Specifically as a result, the Company was
not able to achieve adequate segregation of duties and were not able to
provide adequate reviews of the financial statements. This control
deficiency, which is pervasive in nature, results in a reasonable
possibility that material misstatements of the financial statements will
not be prevented or detected on a timely
basis.
|
As a
result of the existence of this material weakness as of January 31, 2010,
management has concluded that we did not maintain effective internal control
over financial reporting as of January 31, 2010, based on the criteria set forth
by COSO in Internal
Control-Integrated Framework.
This
Annual Report does not include an attestation report of the Company’s registered
public accounting firm regarding internal control over financial reporting.
Management’s report was not subject to attestation by our registered public
accounting firm pursuant to temporary rules of the Securities and Exchange
Commission.
Changes
to Internal Controls and Procedures Over Financial Reporting
We
regularly review our system of internal control over financial reporting and
make changes to our processes and systems to improve controls and increase
efficiency, while ensuring that we maintain an effective internal control
environment. Changes may include such activities as implementing new, more
efficient systems, consolidating activities, and migrating processes. At January
31, 2010, due to the reduced complexity of our financial accounting and
reporting requirements, we remediated our control deficiency identified in prior
filings whereby we did not maintain sufficient personnel with an appropriately
level of technical accounting knowledge, experience, and training in the
application of U.S. GAAP commensurate with the complexity of our financial
accounting and reporting requirements. Senior management will continue to
consult with external experts to assist with the accounting for complex and
non-routine accounting transactions.
28
Management’s
Remediation Plans
Senior
management will monitor the number of personnel employed in the accounting and
financial reporting functions.
ITEM
9B – OTHER INFORMATION
None.
29
PART
III.
ITEM
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
Names:
|
Ages
|
Titles:
|
Board of Directors
|
|||
Peter
Hill (1)
|
62
|
Chief
Executive Officer
|
Director
|
|||
Jonathan
Samuels
|
31
|
Chief
Financial Officer and Corporate Secretary
|
Director
|
|||
F.
Gardner Parker (2)
|
67
|
Chairman
of the Board
|
Chairman
|
|||
Stephen
A. Holditch (3)
|
62
|
Director
|
||||
Randal
Matkaluk (3)
|
|
50
|
|
|
Director
|
(1)Member
of Audit Committee
(2)
Independent Director, Member of Compensation Committee
(3)
Independent Director, Member of Audit Committee, Member of Compensation
Committee
Directors
are elected to serve until the next annual meeting of stockholders and until
their successors are elected and qualified. Currently there are five seats on
our board of directors.
Officers
are elected by the Board of Directors and serve until their successors are
appointed by the Board of Directors. Biographical resumes of each officer and
director are set forth below.
Dr. Peter Hill has been a
director and the Chief Executive Officer of Triangle Petroleum Corporation since
November 2009. Dr. Hill has over 37 years experience in the international oil
and gas industry. He commenced his career in 1972 and spent 22 years in senior
positions at British Petroleum including Chief Geologist, Chief of Staff for BP
Exploration, President of BP Venezuela and Regional Director for Central and
South America. Dr. Hill then worked as Vice President Exploration at Ranger Oil
in England (1994-95), Managing Director Exploration and Production at Deminex in
Germany (1995-97), Technical Director/Chief Operating Officer at Hardy Oil &
Gas (1998-2000), President & CEO at Harvest Natural Resources (2000-2005),
Director/Chairman at Austral Pacific Energy (2006-2008), independent advisor to
Palo Alto ( January 2008 to December 2009) and Non Executive Chairman at
Toreador Resources Corporation (January 2009 to present). Dr. Hill has a BSc
Honors Geology and a PhD.
Jonathan Samuels has been a
director, the Chief Financial Officer and Corporate Secretary of Triangle
Petroleum Corporation since December 2009. Prior to joining Triangle, Mr.
Samuels was an investment professional responsible for research and investment
sourcing in the energy sector at Palo Alto Investors, a $1.3 billion hedge fund
founded in 1989. Mr. Samuels worked for five years at California-based Palo Alto
and worked for a period in Dubai with an investment firm. Mr. Samuels received
his BA from the University of California and his MBA at the Wharton School. He
also has a Certified Financial Analyst designation.
F. Gardner Parker has been a
director and Chairman of the Board of Triangle Petroleum Corporation since
November 2009. From 1970 until 1984, Mr. Parker worked at Ernst & Ernst (now
Ernst & Young LLP), an accounting firm, and was a partner at that firm from
1978 until 1984. Mr. Parker served as Managing Outside Trust Manager with Camden
Property Trust, a real estate investment trust, from 1998-2005 and still serves
as a Trust Manager of Camden Property Trust. He has also served as a director of
Carrizo Oil & Gas since 2000. Mr. Parker also serves on the boards of
Hercules Offshore, Pinnacle Oil & Gas, and Sharpes Medical Compliance. He is
a graduate of the University of Texas and is a CPA in Texas. Mr. Parker is board
certified by the National Association of Corporate Directors. Mr. Parker
previously served as a director of Blue Dolphin Energy Company from
2004-2007.
Stephen A. Holditch has been a
director of Triangle Petroleum Corporation since February 2006. Since January
2004, Mr. Holditch has been the Head of the Department of Petroleum Engineering
at Texas A&M University. Since 1976 through the present, Mr. Holditch has
been a faculty member at Texas A&M University, as an Assistant Professor,
Associate Professor, Professor and Professor Emeritus. Since its founding in
1977 until 1997, when it was acquired by Schlumberger Technology Corporation,
Mr. Holditch was the Founder and President of S.A. Holditch & Associates,
Inc., a petroleum technology consulting firm providing analysis of low
permeability gas reservoirs and designing hydraulic fracture treatments. Mr.
Holditch previously worked for Shell Oil Company and Pan American Petroleum
Corporation. Mr. Holditch is a registered Professional Engineer in Texas, has
received numerous honors, awards and recognitions and has authored or
co-authored over 100 publications on the oil and gas industry. Mr. Holditch
received his B.S., M.S. and Ph.D. in Petroleum Engineering from Texas A&M
University in 1969, 1970 and 1976, respectively.
30
Randal Matkaluk has been a
director of Triangle Petroleum Corporation since August 2007. From November 2008
to February 2010, Mr. Matkaluk was the Chief Financial Officer and Corporate
Secretary of Vigilant Exploration Inc., a private oil and gas exploration
company. From March 2006 to October 2008, Mr. Matkaluk was an independent
businessman. Mr. Matkaluk has been a Director and Officer of Virtutone Networks
Inc. (formerly "Sawhill Capital Ltd.") since October 2005. Between January 2003
and February 2006, Mr. Matkaluk was the co-founder and Chief Financial Officer
of Relentless Energy Corporation, a private oil and gas exploration company.
Between June 2001 and December 2002, Mr. Matkaluk was the Chief Financial
Officer of Antrim Energy Inc., a public international oil and gas exploration
company listed on the Toronto Stock Exchange. Mr. Matkaluk has also worked
for Gopher Oil and Gas Company and Cube Energy Corp. Mr. Matkaluk has been a
Chartered Accountant since 1983. Mr. Matkaluk received his Bachelors Degree in
Commerce in 1980 from the University of Calgary.
The
following is a summary of the committees on which our directors
serve.
Audit
Committee
Report
of the Audit Committee
The Audit
Committee of the Board of Directors of the Company is currently comprised of
three directors, Messrs. Randal Matkaluk, Peter Hill and Stephen Holditch, the
majority of whom (Messrs. Matkaluk and Holditch) satisfy the requirements to
serve as Independent Directors, as those requirements have been defined by
Canadian Securities Regulators, The Securities and Exchange Commission and
NASDAQ. The Board of Directors has determined that Mr. Matkaluk, who is a
Chartered Accountant and having over 25 years of financial experience, qualifies
as an "audit committee financial expert." Mr. Matkaluk is independent of
management based on the independence requirements set forth in the Financial
Industry Regulatory Authority’s definition of "independent
director."
The Audit
Committee has furnished the following report:
The Audit
Committee is appointed by the Company’s Board of Directors to assist the Board
in overseeing (1) the quality and integrity of the financial statements of the
Company; (2) the independent auditor’s qualifications and independence; (3) the
performance of the Company’s independent auditor; and (4) the Company’s
compliance with legal and regulatory requirements. The authority and
responsibilities of the Audit Committee are set forth in a written Audit
Committee Charter adopted by the Board. The Charter grants to The Audit
Committee, sole responsibility for the appointment, compensation and evaluation
of the Company’s independent auditor for the Company, as well as establishing
the terms of such engagements. The Audit Committee has the authority to retain
the services of independent legal, accounting or other advisors as the Audit
Committee deems necessary, with appropriate funding available from the Company,
as determined by the Audit Committee, for such services. The Audit Committee
reviews and reassesses the Charter annually and recommends any changes to the
Board for approval.
The Audit
Committee is responsible for overseeing the Company’s overall financial
reporting process. In fulfilling its oversight responsibilities for the
financial statements for the Company’s fiscal year ended January 31, 2010, the
Audit Committee:
-
|
Reviewed and discussed the annual
audit process and the audited financial statements for the fiscal year
ended January 31, 2010 with management and KPMG LLP, the Company’s
independent auditor;
|
-
|
Discussed with
management, and KPMG LLP the adequacy of the system of internal
controls;
|
-
|
Discussed with KPMG LLP the
matters required to be discussed by Statement on Auditing Standards No.
114 relating to the conduct of the audit;
and
|
-
|
Received a letter from KPMG LLP
regarding its independence as required by Independence Standards Board
Standard No. 1 and discussed with KPMG LLP its
independence.
|
The Audit
Committee also considered the status of pending litigation, taxation matters and
other areas of oversight relating to the financial reporting and audit process
that the Audit Committee determined appropriate. In addition, the Audit
Committee’s meetings included executive sessions with the Company’s independent
auditor and the Company’s accounting and reporting staff, in each case without
the presence of the Company’s management.
31
In
performing all of these functions, the Audit Committee acts only in an oversight
capacity. Also, in its oversight role, the Audit Committee relies on the work
and assurances of the Company’s management, which has the primary responsibility
for financial statements and reports, and of the independent auditor, who, in
their report, express an opinion on the conformity of the Company’s annual
financial statements to accounting principles generally accepted in the United
States of America.
Based on
the Audit Committee’s review of the audited financial statements and discussions
with management and KPMG LLP, the Audit Committee recommended to the Board of
Directors that the audited financial statements be included in the Company’s
annual report on Form 10-K for the fiscal year ended January 31, 2010 for filing
with the SEC.
Audit
Committee
Randal
Matkaluk, Chairman
Stephen
A. Holditch
Peter
Hill
Audit
Committee Pre-Approval Policy
Pursuant
to the terms of the Company’s Audit Committee Charter, the Audit Committee is
responsible for the appointment, compensation and oversight of the work
performed by the Company’s independent auditor. The Audit Committee, or a
designated member of the Audit Committee, must pre-approve all audit (including
audit-related) and non-audit services performed by the independent auditor in
order to ensure that the provisions of such services does not impair the
auditor’s independence. The Audit Committee has delegated interim pre-approval
authority to the Chairman of the Audit Committee. Any interim pre-approval of
permitted non-audit services is required to be reported to the Audit Committee
at its next scheduled meeting. The Audit Committee does not delegate its
responsibilities to pre-approve services performed by the independent auditor to
management.
The term
of any pre-approval is 12 months from the date of pre-approval, unless the Audit
Committee specifically provides for a different period. With respect to each
proposed pre-approved service, the independent auditor must provide detailed
back-up documentation to the Audit Committee regarding the specific service to
be provided pursuant to a given pre-approval of the Audit Committee. Requests or
applications to provide services that require separate approval by the Audit
Committee will be submitted to the Audit Committee by both the independent
auditor and the Company’s Chief Financial Officer, and must include a joint
statement as to whether, in their view, the request or application is consistent
with the SEC’s rules on auditor independence. All of the services described in
Item 14 Principal Accountant Fees and Services were approved by the Audit
Committee.
Compensation
Committee
Our
Compensation Committee currently consists of Messrs. Randal Matkaluk, F. Gardner
Parker and Stephen Holditch, with Mr. Matkaluk elected as Chairman of the
Committee. Our Board of Directors has determined that all of the members are
“independent.” Our Board of Directors has adopted a written charter setting
forth the authority and responsibilities of the Compensation
Committee.
Our
Compensation Committee has responsibility for assisting the Board of Directors
in, among other things, evaluating and making recommendations regarding the
compensation of our executive officers and directors, assuring that the
executive officers are compensated effectively in a manner consistent with our
stated compensation strategy, periodically evaluating the terms and
administration of our incentive plans and benefit programs and monitoring of
compliance with the legal prohibition on loans to our directors and executive
officers.
32
Code
of Ethics
We have
adopted a Code of Ethics that is designed to deter wrongdoing and to promote
honest and ethical conduct, full, fair, accurate, timely and understandable
disclosure in our SEC reports and other public communications. The Code of
Ethics promotes compliance with applicable governmental laws, rules and
regulations.
Section
16(a) Compliance
Section
16(a) of the Securities and Exchange Act of 1934 requires our directors and
executive officers, and persons who own beneficially more than ten percent (10%)
of our Common Stock, to file reports of ownership and changes of ownership with
the Securities and Exchange Commission. Copies of all filed reports are required
to be furnished to us pursuant to Section 16(a). Based solely on the reports we
received and on written representations from reporting persons, we believe that,
during fiscal 2010, our directors, executive officers and 10% stockholders
complied with all Section 16(a) filing requirements, with the exception
noted below:
|
·
|
A
late Form 4 was filed for Mark Gustafson on May 29, 2009 to report the
disposition of 200,000 shares of common stock, effective May 13,
2009.
|
ITEM
11. EXECUTIVE COMPENSATION.
The
following tables set forth certain information regarding our CEO and each of our
most highly-compensated executive officers whose total annual salary and bonus
for the fiscal years ending January 31, 2010 and 2009 exceeded
$100,000:
Name & Principal
Position
|
Year
|
Salary ($)
|
Bonus
($)
|
Stock
Awards($)
|
Option
Awards
($)
|
All Other
Compen-
sation ($)
|
Total ($)
|
|||||||||||||||||||
Peter
Hill (a),
|
||||||||||||||||||||||||||
CEO,
Principal
|
||||||||||||||||||||||||||
Executive
Officer
|
2010
|
41,667 | - | - | 5,660 | - | 47,327 | |||||||||||||||||||
Jonathan
Samuels (b)
|
||||||||||||||||||||||||||
CFO,
Principal
|
||||||||||||||||||||||||||
Financial
Officer
|
2010
|
25,000 | - | - | 3,841 | - | 28,841 | |||||||||||||||||||
Mark
Gustafson (c),
|
||||||||||||||||||||||||||
CEO,
Principal
|
2010
|
186,820 | - | - | 138,600 | 233,525 | 558,945 | |||||||||||||||||||
Executive
Officer
|
2009
|
201,000 | 29,000 | - | 47,481 | 835 | 278,316 | |||||||||||||||||||
Howard
Anderson (d),
|
2010
|
80,180 | 131,552 | 382,984 | ||||||||||||||||||||||
President
and COO
|
2009
|
156,000 | - | - | 93,798 | 2,326 | 252,124 | |||||||||||||||||||
Shaun
Toker (e)
|
||||||||||||||||||||||||||
CFO,
Principal
|
2010
|
122,601 | 23,353 | - | 88,522 | 93,410 | 327,886 | |||||||||||||||||||
Financial
Officer
|
2009
|
122,000 | 39,000 | - | 57,545 | 5,533 | 224,078 | |||||||||||||||||||
Ron
Hietala (f), Former President of
|
||||||||||||||||||||||||||
Elmworth
Energy
|
||||||||||||||||||||||||||
Corporation
|
2009
|
48,000 | 16,000 | - | - | 197 | 64,197 |
33
|
a)
|
Effective
November 30, 2009, we agreed to pay a salary of $250,000 per year to Mr.
Hill.
|
|
b)
|
Effective
December 16, 2009, we agreed to pay a salary of $200,000 per year to Mr.
Samuels.
|
|
c)
|
On
November 1, 2006, we agreed to pay a salary of Cdn $24,000 per month to
Mr. Gustafson. Effective March 17, 2008, we agreed to pay a salary of Cdn
$20,000 per month to Mr. Gustafson. Mr. Gustafson resigned effective
November 30, 2009 and we agreed to pay a severance of Cdn $250,000 and
fully vested his 500,000 stock options granted January 28, 2009 and
extended the expiration date of such options from 10 days after
resignation to one year.
|
|
d)
|
Effective
February 1, 2008, we agreed to pay a salary of Cdn $15,000 per month to
Mr. Anderson. On July 1, 2008, we agreed to pay a salary of Cdn $16,667
per month to Mr. Anderson. Mr. Anderson resigned effective January 5, 2010
and we agreed to pay a severance of Cdn
$133,333.
|
|
e)
|
Effective
September 1, 2007, we agreed to pay an annual salary of Cdn $120,000 to
Mr. Toker until December 31, 2007. Effective January 1, 2008, we agreed to
pay an annual salary of Cdn $150,000 to Mr. Toker. Mr. Toker resigned from
his officer positions effective December 23, 2009 and we agreed to pay a
severance of Cdn $100,000.
|
|
f)
|
On
June 23, 2005, we entered into a management consulting agreement with RWH
Management Services Ltd. (RWH Management Serves Ltd. is owned by Mr.
Hietala). Under the terms of the agreement, we agreed to pay US$20,000 per
month for an initial term of two years. The agreement was extended to
December 31, 2007. Effective March 17, 2008, we agreed to pay a salary of
Cdn $16,667 per month to Mr. Hietala. Mr. Hietala resigned effective June
30, 2008.
|
Employment
Agreements with Executive Officers
Both Dr.
Hill and Mr. Samuels have entered into employment agreements with the company
effective January 29, 2010. The agreements provide for a one year term with an
automatic renewal for an additional year unless either party provides written
notice of non-renewal. For more detail, please see the complete agreements filed
as exhibits to this form 10-K.
Peter
Hill
The
agreement provides for an annual salary of $250,000. In addition, Dr. Hill is
entitled to receive an annual bonus based upon various criteria targets.
Additionally, he is entitled to participate in any and all benefit plans, from
time to time, in effect for executives, along with vacation, sick and holiday
pay in accordance with the Company’s policies established and in effect from
time to time. In the event that Dr. Hill’s employment is terminated by the
Company without cause (as defined in the agreement) or by the employee for good
reason, Dr. Hill is entitled to the continuation of payment of annual salary,
target bonus and benefits for a 18 month period and the immediate vesting of all
Common Shares previously awarded. In the event that Dr.
Hill’s employment is terminated by the Company after a Change of Control (as
defined in the agreement), he is entitled lump sum cash payment of two times
annual salary and two times the target bonus, and the immediate vesting of all
Common Shares previously awarded.
Jonathan
Samuels
The
agreement provides for an annual salary of $200,000. In addition, Mr. Samuel is
entitled to receive an annual bonus based upon various criteria targets.
Additionally, he is entitled to participate in any and all benefit plans, from
time to time, in effect for executives, along with vacation, sick and holiday
pay in accordance with the Company’s policies established and in effect from
time to time. In the event that Mr. Samuel’s employment is terminated by the
Company without cause (as defined in the agreement) or by the employee for good
reason, Mr. Samuels is entitled to the continuation of payment of annual salary,
target bonus and benefits for a 12 month period and the immediate vesting of all
Common Shares previously awarded. In the event that Mr.
Samuels employment is terminated by the Company after a Change of Control (as
defined in the agreement), he is entitled lump sum cash payment of two times
annual salary and two times the target bonus, and the immediate vesting of all
Common Shares previously awarded.
34
GRANTS
OF PLAN-BASED AWARDS
The
following table sets forth information regarding the number of stock options
granted to named executive officers during fiscal 2010.
Name
|
Grant Date
|
All Other
Option Awards:
Number of
Securities
Underlying
Options (#)
|
Exercise
or Base
Price of
Option
Awards
($/Sh)
|
Grant
Date Fair
Value of
Stock and
Option
Awards ($)
|
||||||||||
Peter
Hill
|
November
30, 2010
|
1,400,000 | $ | 0.125 | 126,000 | |||||||||
Jonathan
Samuels
|
November
30, 2010
|
950,000 | $ | 0.125 | 85,500 |
Outstanding Equity Awards at Fiscal
Year-End Table.
The
following table sets forth information for the named executive officers
regarding the number of shares subject to both exercisable and unexercisable
stock options, as well as the exercise prices and expiration dates thereof, as
of January 31, 2010.
Option Awards
|
|||||||||||||
Name
|
Number
of
Securities
Underlying
Unexercised
Options
(#)
Exercisable
|
Number
of
Securities
Underlying
Unexercised
Options
(#)
Unexercisable
|
Option
Exercise
Price
($)
|
Option
Expiration
Date
(mm/dd/yy)
|
|||||||||
Peter Hill
|
- | 1,400,000 | $ | 0.125 |
11/30/15
|
||||||||
Jonathan
Samuels
|
- | 950,000 | $ | 0.125 |
11/30/15
|
Director
Compensation
Our
directors are elected by the vote of a majority in interest of the holders of
our voting stock and hold office until the expiration of the term for which he
was elected and until a successor has been elected and qualified.
A
majority of the authorized number of directors constitutes a quorum of the Board
of Directors for the transaction of business. The directors must be present at
the meeting to constitute a quorum. However, any action required or permitted to
be taken by the Board of Directors may be taken without a meeting if all members
of the Board of Directors individually or collectively consent in writing to the
action.
Directors
received compensation for their services for the fiscal year ended January 31,
2010 as set forth below:
Name
|
Fees
Earned
or Paid
in Cash
($)
|
Stock
Awards
($)
|
Option
Awards
($)
|
Non-Equity
Incentive Plan
Compensation
($)
|
Change in
Pension Value
and Nonqualified
Deferred
Compensation
Earnings
|
All Other
Compensation
($)
|
Total
($)
|
|||||||||||||||||||||
Stephen
A. Holditch
|
$ | 40,000 | $ | 0 | $ | 37,698 | $ | 0 | $ | 0 | $ | 0 | $ | 77,698 | ||||||||||||||
David
L. Bradshaw
|
$ | 33,333 | $ | 0 | $ | 103,900 | $ | 0 | $ | 0 | $ | 0 | $ | 137,233 | ||||||||||||||
Randal
Matkaluk
|
$ | 40,000 | $ | 0 | $ | 119,406 | $ | 0 | $ | 0 | $ | 0 | $ | 159,406 | ||||||||||||||
F.
Gardner Parker
|
$ | 12,500 | $ | 0 | $ | 1,819 | $ | 0 | $ | 0 | $ | 0 | $ | 14,319 |
35
ITEM
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS.
The
following table sets forth certain information regarding beneficial ownership of
our common stock as of April 7, 2010.
|
·
|
by
each person who is known by us to beneficially own more than 5% of our
common stock;
|
|
·
|
by
each of our officers and directors;
and
|
|
·
|
by
all of our officers and directors as a
group.
|
NAME AND ADDRESS
OF OWNER (1)
|
TITLE OF
CLASS
|
NUMBER OF
SHARES OWNED (2)
|
PERCENTAGE OF
CLASS (3)
|
|||||||
Peter
Hill
|
Common
Stock
|
0 | 0 | % | ||||||
Jonathan
Samuels
|
Common
Stock
|
0 | 0 | % | ||||||
F.
Gardner Parker
|
Common
Stock
|
0 | 0 | % | ||||||
Stephen
A. Holditch
|
Common
Stock
|
95,600 | (4) | * | ||||||
Randal
Matkaluk
|
Common
Stock
|
150,000 | (5) | * | ||||||
All
Officers and Directors
|
Common
Stock
|
245,600 | (6) | * | ||||||
As
a Group (5 persons)
|
||||||||||
Palo
Alto Investors, LLC
|
Common
Stock
|
14,751,350 | (7) | 15.06 | % | |||||
470
University Avenue
|
||||||||||
Palo
Alto, California 94301
|
||||||||||
Sprott
Asset Management
|
Common
Stock
|
14,216,900 | (8) | 14.03 | % | |||||
200
Bay Street, Suite 2700
|
||||||||||
Box
27 Toronto, Ontario M5J 2J1
|
||||||||||
Cambrian
Capital, L.P.
|
Common
Stock
|
19,393,939 | (9) | 19.81 | % | |||||
45
Coolidge Point
|
||||||||||
Manchester,
Massachusetts 01944
|
* Less
than 1%.
(1)
Address is c/o Triangle Petroleum Corporation, Suite 750, 521-3rd Avenue SW,
Calgary, Alberta T2P 3T3 Canada unless otherwise indicated.
(2)
Beneficial Ownership is determined in accordance with the rules of the
Securities and Exchange Commission and generally includes voting or investment
power with respect to securities. Shares of common stock subject to options or
warrants currently exercisable or convertible, or exercisable or convertible
within 60 days of April 7, 2010 are deemed outstanding for computing the
percentage of the person holding such option or warrant but are not deemed
outstanding for computing the percentage of any other person.
(3) Based
upon 97,919,982 shares issued and outstanding on April 7, 2010.
(4)
Includes 7,000 shares of common stock underlying warrants that are currently
exercisable and 50,000 shares of common stock underlying options that are
currently exercisable or exercisable within 60 days.
36
(5)
Includes 50,000 shares of common stock underlying options that are currently
exercisable or exercisable within 60 days.
(6) Includes
7,000 shares of common stock underlying warrants that are currently exercisable
and 100,000 shares of common stock underlying options that are currently
exercisable or exercisable within 60 days.
(7) As
reported pursuant to a Schedule 13D/A filed with the Securities and Exchange
Commission on December 1, 2009. Palo Alto Investors, LLC is
a registered investment adviser and general partner of Micro Cap Partners, L.P.,
Palo Alto Global Energy Master Fund, L.P., Palo Alto Global Energy Fund, L.P.,
Palo Alto Small Cap Master Fund, L.P. and Palo Alto Small Cap Fund, L.P., who in
the aggregate, own 14,751,350 shares of Triangle common stock. Palo Alto
Investors is the manager of Palo Alto Investors, LLC. William L. Edwards is the
controlling shareholder and President of Palo Alto Investors. Each of Mr.
Edwards, PAI and Palo Alto Investors disclaims beneficial ownership of the
common stock except to the extent of that person's pecuniary interest therein
and each disclaims that it is, the beneficial owner, as defined in Rule 13d-3
under the Securities Exchange Act of 1934, of any of the common
stock.
(8) As
reported pursuant to a Schedule 13G/A filed with the Securities and Exchange
Commission on January 26, 2010. Includes 3,420,900 shares of common stock
issuable upon exercise of warrants. Kirstin McTaggart, the Chief Compliance
Officer of Sprott Asset Management has voting and dispositive power over the
shares held by Sprott Asset Management. Ms. McTaggart disclaims beneficial
ownership of the common stock.
(9) As
reported pursuant to a Schedule 13G filed with the Securities and Exchange
Commission on March 22, 2010. Cambrian Capital, L.P. serves as the investment
manager to CamCap Energy Offshore Master Fund, L.P., which owns 12,121,212
shares of our common stock, and CamCap Resources Offshore Master Fund, L.P.,
which owns 7,272,727 shares of our common stock. CamCap Resources
Partners, LLC serves as general partner of CamCap Resources Offshore Master
Fund, L.P. CamCap Energy Partners, LLC serves as general partner of
CamCap Energy Offshore Master Fund, L.P. Cambrian Capital, LLC is the
general partner of Cambrian Capital, L.P. Ernst von Metzsch and
Roland von Metzsch are the managers of each of Cambrian Capital, LLC, CamCap
Resources Partners, LLC and CamCap Energy Partners, LLC, and in such capacities
may be deemed to have voting and investment control over the shares for such
entities. Each of the Reporting Persons disclaims beneficial
ownership of all shares except to the extent of its pecuniary interest
therein.
ITEM
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, DIRECTOR
INDEPENDENCE.
There
have been no transactions, or proposed transactions, which have materially
affected or will materially affect us in which any director, executive officer
or beneficial holder of more than 5% of the outstanding common stock, or any of
their respective relatives, spouses, associates or affiliates, has had or will
have any direct or material indirect interest. We have no policy regarding
entering into transactions with affiliated parties.
ITEM
14. PRINCIPAL ACCOUNTING FEES AND SERVICES (AMOUNTS IN CANADIAN
DOLLARS).
Audit
Fees
The
aggregate fees billed by our current auditor during the years ended January 31,
2010 and 2009 for professional services rendered for the audit of our annual
financial statements and for the reviews of the financial statements included in
our Quarterly Reports on Form 10-Q during the fiscal years, were $92,656 and
$130,000, respectively.
The
aggregate fees billed by our previous auditor during the years ended January 31,
2009 for professional services rendered for the audit of our annual financial
statements and for the reviews of the financial statements included in our
Quarterly Reports on Form 10-Q during the fiscal year was
$43,900.
37
Audit-Related
Fees
Our
current independent registered public accounting firm billed us $nil and $97,000
during the fiscal years ended January 31, 2010 and 2009, respectively, for audit
related services. These services relate to required securities filings such as
prospectus, Form S-1 and Form S-8.
Our
previous independent registered public accounting firm billed us $13,500 during
the fiscal year ended January 31, 2009 for audit related services.
Tax
Fees
Our
current independent registered public accounting firm billed us $13,654 and
$17,760 during the fiscal years ended January 31, 2010 and 2009 for tax related
work.
All
Other Fees
Our
current and previous independent registered public accounting firm did not bill
us during fiscal years ended January 31, 2010 or 2009 for other
services.
The Board
of Directors and Audit Committee have considered whether the provision of
non-audit services is compatible with maintaining the principal accountant's
independence.
38
PART
IV.
ITEM
15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
Exhibit No.
|
Description
|
|
3.1
|
Articles
of Incorporation, filed as an exhibit to the registration statement on
Form SB-2 filed with the Securities and Exchange Commission on February
27, 2004 and incorporated herein by reference.
|
|
3.2
|
Articles
of Amendment to the Articles of Incorporation, changing the name to
Triangle Petroleum Corporation, filed with the Nevada Secretary of State
on May 10, 2005.
|
|
3.3
|
Amended
and Restated Bylaws of the Company, filed as an exhibit to the Current
Report on Form 8-K, filed with the Commission on November 19, 2008 and
incorporated herein by reference.
|
|
10.01
|
2005
Incentive Stock Plan, filed as an exhibit to the Registration Statement on
Form S-8, filed with the Commission on October 14, 2005 and incorporated
herein by reference.
|
|
10.02
|
2007
Incentive Stock Plan, filed as an exhibit to the Quarterly Report on Form
10-Q filed with the Securities and Exchange Commission on September 14,
2007 and incorporated herein by reference.
|
|
10.03
|
Stock
Option Plan, filed as an exhibit to the definitive proxy statement on
Schedule 14A, filed with the Securities and Exchange Commission on May 22,
2009 and incorporated herein by reference.
|
|
10.04
|
Production
Lease, dated as of April 15, 2009, by and between the Company and Her
Majesty the Queen in the Right of the Province of Nova Scotia, filed as an
exhibit to the Quarterly Report on Form 10-Q filed with the Securities and
Exchange Commission on April 20, 2009 and incorporated herein by
reference.
|
|
10.05
|
Overriding
Royalty Agreement, dated as of June 10, 2009, by and between Elmworth
Energy Corporation and Contact Exploration Inc., filed as an exhibit to
the Current Report on Form 8-K filed with the Securities and Exchange
Commission on September 2, 2009 and incorporated herein by
reference.
|
|
10.06
|
Memorandum
of Understanding, dated as of November 30, 2009, by and among Triangle
Petroleum Corporation, Palo Alto Global Energy Master Fund, L.P. and Mark
Gustafson, filed as an exhibit to the Current Report on Form 8-K filed
with the Securities and Exchange Commission on December 3, 2009 and
incorporated herein by reference.
|
|
10.07
|
Separation
Agreement, dated as of November 30, 2009, by and between Triangle
Petroleum Corporation and Mark Gustafson, filed as an exhibit to the
Current Report on Form 8-K filed with the Securities and Exchange
Commission on December 3, 2009 and incorporated herein by
reference.
|
|
10.08
|
Termination
of Employment of Shaun Toker, dated December 23, 2009, filed as an exhibit
to the Current Report on Form 8-K filed with the Securities and Exchange
Commission on January 5, 2009 and incorporated herein by
reference.
|
|
10.09
|
Termination
of Employment of J. Howard Anderson, dated December 30, 2009, filed as an
exhibit to the Current Report on Form 8-K filed with the Securities and
Exchange Commission on January 5, 2009 and incorporated herein by
reference.
|
|
10.10
|
Form
of Warrant, dated as of June 3, 2008, filed as an exhibit to the Current
Report on Form 8-K, filed with the Commission on June 4, 2008 and
incorporated herein by reference.
|
|
10.11
|
Form
of Employment Agreement, effective as of January 29th,
2010, by and between Triangle USA Petroleum Corporation and Peter
Hill.
|
39
10.12
|
Form
of Employment Agreement, effective as of January 29th,
2010, by and between Triangle USA Petroleum Corporation and Jonathan
Samuels.
|
|
14.01
|
Code
of Ethics for Senior Financial Officers, filed as an exhibit to the
Quarterly Report on Form 10-Q filed with the Securities and Exchange
Commission on June 3, 2009 and incorporated herein by
reference.
|
|
14.02
|
Audit
Committee Charter
|
|
21.01
|
List
of subsidiaries, filed as an exhibit to the Registration Statement on Form
SB-2, filed with the Commission on January 18, 2006 and incorporated
herein by reference.
|
|
23.01
|
Consent
of Ryder Scott, Independent Petroleum Engineers.
|
|
24.01
|
Power
of Attorney (incorporated by reference to the signature page of this
Annual Report on Form 10-K).
|
|
31.01
|
Certification
of Chief Executive Officer pursuant to Exchange Act Rules 13a-14(a) and
15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
2002
|
|
31.02
|
Certification
of Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and
15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
2002
|
|
32.01
|
|
Certifications
of Chief Executive Officer and Chief Financial Officer pursuant to
18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
|
40
SIGNATURES
In
accordance with the requirements of the Exchange Act, the registrant caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
TRIANGLE
PETROLEUM CORPORATION
Date: April 9, 2010
|
By:
|
/s/ PETER HILL
|
Peter
Hill
|
||
Chief
Executive Officer (Principal Executive Officer)
|
||
Date: April
9, 2010
|
By:
|
/s/ JONATHAN SAMUELS
|
Jonathan
Samuels
|
||
Chief
Financial Officer (Principal Financial Officer and
Principal
Accounting Officer)
|
KNOW ALL
MEN BY THESE PRESENTS, that each person whose signature appears below
constitutes and appoints Peter Hill and Jonathan Samuels, jointly and severally,
his or her attorney-in-fact, with the power of substitution, for him or her in
any and all capacities, to sign any amendments to this Annual Report on Form
10-K and to file the same, with exhibits thereto and other documents in
connection therewith, with the Securities and Exchange Commission, hereby
ratifying and confirming all that each of said attorneys-in-fact, or his or her
substitute or substitutes, may do or cause to be done by virtue
hereof.
Pursuant
to the requirements of the Securities Exchange Act of 1934, this Annual Report
on Form 10-K has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Name
|
Position
|
Date
|
||
/s/ PETER HILL
|
Chief
Executive Officer (Principal Executive Officer)
|
April
9, 2010
|
||
Peter
Hill
|
and
Director
|
|||
/s/ JONATHAN SAMUELS
|
Chief
Financial Officer (Principal Financial Officer and
|
April
9, 2010
|
||
Jonathan
Samuels
|
Principal
Accounting Officer)
|
|||
/s/ F. GARDNER PARKER
|
Director
|
April
9, 2010
|
||
F.
Gardner Parker
|
||||
/s/ STEPHEN A. HOLDITCH
|
Director
|
April
9, 2010
|
||
Stephen
A. Holditch
|
||||
/s/ RANDAL MATKALUK
|
Director
|
April
9, 2010
|
||
Randal
Matkaluk
|
|
|
41