U.S. Securities and Exchange Commission
Washington, D.C. 20549
Form 10-QSB
(Mark One)
[X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the quarterly period ended December 31, 2001
[_] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
Commission file number: 0-27321
Vista Exploration Corporation
-----------------------------
(Name of small business issuer in its charter)
Colorado 84-1493152
-------- ----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
11952 Farley, Shawnee Mission, KS 66213
---------------------------------------
(Address of principal executive offices, including ZIP Code)
Issuer's telephone number: (913) 814-8313
--------------------------------------------------------------------
(Former name, address and fiscal year, if changed since last report)
Check whether the issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past 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 [ ]
Transitional Small Business Disclosure Format Yes [ ] No [X]
The issuer had 6,090,000 shares of its common stock issued and outstanding
as of February 13, 2002, the latest practicable date before the filing of this
report.
VISTA EXPLORATION CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-QSB
Page
PART I--FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed balance sheet - December 31, 2001 (Unaudited)............ 4
Condensed statement of operations (Unaudited) -
three months ended December 31, 2001 and 2000...................... 5
Condensed statement of operations (Unaudited) -
nine months ended December 31, 2001 and 2000
and April 9, 1998 (inception) through December 31, 2001............ 6
Condensed statements of cash flows (Unaudited) -
nine months ended December 31, 2001 and 2000 and
April 9, 1998 (inception) through December 31, 2001................ 7
Notes to condensed financial statements (Unaudited)................ 8
Item 2. Plan of Operation.................................................. 10
PART II--OTHER INFORMATION.................................................. 18
Item 1. Legal Proceedings.................................................. 18
Item 2. Changes in Securities and Use of Proceeds.......................... 18
Item 3. Defaults Upon Senior Securities.................................... 18
Item 4. Submission of Matters to a Vote of Security Holders................ 18
Item 5. Other Information.................................................. 18
Item 6. Exhibits and Reports on Form 8-K................................... 18
Signatures......................................................... 19
2
PART I - FINANCIAL INFORMATION
Forward-Looking Statements
This report on Form 10-QSB contains forward-looking statements that concern
our business. Such statements are not guarantees of future performance and
actual results or developments could differ materially from those expressed or
implied in such statements as a result of certain factors, including those
factors set forth in Item 2 - Plan of Operation and elsewhere in this report.
All statements, other than statements of historical facts, included in this
report that address activities, events or developments that we expect, believe,
intend or anticipate will or may occur in the future, including the following
matters, are forward looking statements:
o our ability to acquire valuable properties,
o future capital costs of acquisitions and exploration,
o the size of various markets,
o market share,
o project margins,
o business strategies, and
o expansion and growth of our operations.
These statements are based on certain assumptions and analyses made by us in
light of our experience and our perception of the following:
o historical trends,
o current conditions,
o expected future developments, and
o other factors we believe are appropriate under the circumstances.
Such statements are subject to a number of assumptions including the following:
o risks and uncertainties,
o general economic and business conditions,
o the business opportunities that may be presented to and pursued by us,
o changes in laws or regulations and other factors, many of which are
beyond our control, and
o ability to obtain financing on favorable conditions.
The cautionary statements contained or referred to in this report should be
considered in connection with any subsequent written or oral forward-looking
statements that may be issued by us or persons acting on our behalf. We
undertake no obligation to release publicly any revisions to any forward-looking
statements to reflect events or circumstances after the date hereof or to
reflect the occurrence of unanticipated events.
3
Item 1. Financial Statements
VISTA EXPLORATION CORPORATION
(A Development Stage Company)
Balance Sheet (Unaudited)
December 31, 2001
ASSETS
Current assets:
Cash ........................................................ $ 2,450
Expense advance to Officer .................................. 2,972
---------
Total current assets 5,422
Oil and gas properties, at cost ................................... 49,832
---------
$ 55,254
=========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accrued liabilities ......................................... $ 26,983
---------
Total current liabilities 26,983
---------
Shareholders' equity:
Preferred Stock, no par value, 5,000,000 shares
authorized, -0- shares issued and outstanding ............. --
Common stock, no par value, 20,000,000 shares
authorized, 5,890,000 shares issued and outstanding ...... 195,111
Additional paid-in capital .................................. 3,600
Deficit accumulated during the development stage ............ (170,440)
---------
Total shareholders' equity 28,271
---------
$ 55,254
=========
See accompanying notes to financial statements
4
VISTA EXPLORATION CORPORATION
(A Development Stage Company)
Statements of Operations (Unaudited)
Three Months Ended
December 31,
-------------------------
2001 2000
----------- ----------
Costs and expenses:
Legal fees .................................... $ 17,462 $ --
Accounting fees ............................... 1,550 --
Travel ........................................ 4,347 --
General and administrative .................... 3,125 21
Compensation .................................. 10,000 --
Rent, related party ........................... -- 300
----------- -----------
Operating loss (36,484) (321)
Provision for income taxes ........................ -- --
----------- -----------
Net loss $ (36,484) $ (321)
=========== ===========
Basic and diluted loss per common share:
Net loss ...................................... $ (0.01) $ *
=========== ===========
Basic and diluted weighted average
common shares outstanding ..................... 5,716,087 1,230,000
=========== ===========
* Less than $.01 per share
See accompanying notes to financial statements
5
VISTA EXPLORATION CORPORATION
(A Development Stage Company)
Statements of Operations (Unaudited)
April 9, 1998
Nine Months Ended (Inception)
December 31, Through
-------------------------- December 31,
2001 2000 2001
----------- ------------ -----------
Costs and expenses:
Legal fees .................................... $ 65,730 $ 778 $ 69,625
Accounting fees ............................... 5,100 1,500 10,851
Travel ........................................ 19,337 -- 24,676
General and administrative .................... 11,556 63 12,555
Compensation .................................. 25,000 -- 25,000
Project evaluation costs ...................... 28,902 -- 28,902
Rent, related party ........................... -- 900 3,600
Organizational costs .......................... -- -- 500
----------- ----------- -----------
Operating loss (155,625) (3,241) (175,709)
Interest income ................................... -- 8 114
----------- ----------- -----------
Loss before income taxes and extraordinary item (155,625) (3,233) (175,595)
Provision for income taxes ........................ -- -- --
----------- ----------- -----------
Loss before extraordinary item (155,625) (3,233) (175,595)
Extraordinary gain on extinguishment of debt,
net of income taxes of $-0- ................... -- -- 5,155
----------- ----------- -----------
Net loss $ (155,625) $ (3,233) $ (170,440)
=========== =========== ===========
Basic and diluted loss per common share:
Before extraordinary item ..................... $ (0.03) $ *
=========== ===========
Gain on extinguishment of debt ................ $ -- $ *
=========== ===========
Net loss ...................................... $ (0.03) $ *
=========== ===========
Basic and diluted weighted average
common shares outstanding ..................... 5,072,582 1,230,000
=========== ===========
* Less than $.01 per share
See accompanying notes to financial statements
6
VISTA EXPLORATION CORPORATION
(A Development Stage Company)
Statements of Cash Flows (Unaudited)
April 9, 1998
Nine Months Ended (Inception)
December 31, Through
---------------------- December 31,
2001 2000 2001
--------- --------- ---------
Cash flows from operating activities:
Net loss ...................................... $(155,625) $ (3,233) $(170,440)
Transactions not requiring cash:
Common stock issued for services ........... -- -- 500
Contributed rent ........................... -- 900 3,600
Changes in operating assets and liabilities:
Receivables and advances ............... (2,972) (8) (2,972)
Accounts payable and accrued liabilities 18,867 1,633 26,983
--------- --------- ---------
Net cash used in operating activities (139,730) (708) (142,329)
--------- --------- ---------
Cash flows from investing activities:
Investment in oil and gas properties .......... (49,832) -- (49,832)
--------- --------- ---------
Net cash used in investing activities ... (49,832) -- (49,832)
--------- --------- ---------
Cash flows from financing activities:
Advances from officer ......................... (10,500) -- --
Sale of common stock ......................... 223,000 -- 225,300
Offering costs incurred ....................... (20,561) -- (30,689)
--------- --------- ---------
Net cash provided by financing activities 191,939 -- 194,611
--------- --------- ---------
Net change in cash ................................ 2,377 (708) 2,450
Cash, beginning of period ......................... 73 813 --
--------- --------- ---------
Cash, end of period $ 2,450 $ 105 $ 2,450
========= ========= =========
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest ................................... $ -- $ -- $ --
========= ========= =========
Income taxes ............................... $ -- $ -- $ --
========= ========= =========
Non-cash financing activities:
Extraordinary gain on the extinguishment
of debt ................................ $ -- $ -- $ 5,155
========= ========= =========
See accompanying notes to financial statements
7
VISTA EXPLORATION CORPORATION
A Development Stage Company
---------------------------
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
December 31, 2001
Note A: Basis of Presentation
-----------------------------
The financial statements presented herein have been prepared by the Company in
accordance with the accounting policies in its audited financial statements for
the period ended March 31, 2001 as filed in its Form 10K-SB filed July 13, 2001
and should be read in conjunction with the notes thereto. The Company entered
the development stage in accordance with Statement of Financial Accounting
Standard ("SFAS") No. 7 on April 9, 1998 and its purpose was to evaluate,
structure and complete a merger with, or acquisition of, a privately owned
corporation. On or about March 3, 2001, a transfer of ownership of common stock
was completed in order to change from an inactive company to an oil and gas
company.
In the opinion of management, all adjustments (consisting only of normal
recurring adjustments) which are necessary to provide a fair presentation of
operating results for the interim period presented have been made. The results
of operations for the periods presented are not necessarily indicative of the
results to be expected for the year.
Interim financial data presented herein are unaudited. The unaudited interim
financial information presented herein has been prepared by the Company in
accordance with the policies in its audited financial statements for the period
ended March 31, 2001 and should be read in conjunction with the notes thereto.
On April 18, 2001, the Company changed its year-end from April 30 to March 31.
The accompanying statements of operations and cash flows reflect the three-month
and nine-month periods ended December 31, 2001. The comparative figures for the
three-month and nine-month periods ended December 31, 2000 have been included in
the accompanying statements of operations and cash flows for comparison on an
unaudited basis.
Note B: Summary of Significant Accounting Policies
--------------------------------------------------
Oil and Gas Properties: The Company follows the full cost method of accounting
for oil and gas properties. Accordingly, all costs associated with acquisition,
exploration, and development of oil and gas reserves, including directly related
overhead costs, are capitalized. No internal overhead costs have been
capitalized to date.
All capitalized costs of oil and gas properties, including the estimated future
costs to develop proved reserves, are amortized on the unit-of-production method
using estimates of proved reserves. Investments in unproved properties and major
development projects are not amortized until proved reserves associated with the
projects can be determined or until impairment occurs. If the results of an
assessment indicate that the properties are impaired, the amount of the
impairment is added to the capitalized costs to be amortized.
The capitalized costs are subject to a "ceiling test," which limits capitalized
costs to the aggregate of the "estimated present value," discounted at a
10-percent interest rate, of future net revenues from proved reserves (based on
current economic and operating conditions), plus the lower of cost or fair
market value of unproved properties.
8
Sales of proved and unproved properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves of oil and gas, in which case the gain or loss is recognized in income.
Abandonments of properties are accounted for as adjustments of capitalized costs
with no loss recognized.
Note C: Related Party Transactions
----------------------------------
On April 11, 1998, the Company issued an affiliate 1,000,000 shares of common
stock in exchange for services related to management and organization costs of
$500. The affiliate provided administrative and marketing services as needed.
The affiliate, from time to time, advanced to the Company additional funds that
the Company needed for operating capital and for costs in connection with
searching for or completing an acquisition or merger.
On behalf of the Company, the affiliate sold 230,000 shares of the Company's
common stock in a private placement for $2,300. The private placement, which
closed in July 1998, also included the offering of common shares in nineteen
other corporations. The costs related to the offering and certain legal fees and
general and administrative fees were allocated to each of the twenty companies
participating in the offering. The Company's pro rata one twentieth share of the
costs and expenses were deducted from the gross proceeds from the sale of the
Company's common shares. The gross proceeds of $2,300 were transferred to the
Company net of offering costs of $127 and certain general and administrative
costs incurred by the affiliate of $89.
On February 28, 2001, an officer advanced the Company $10,500 for working
capital. The advance carried no interest rate and was payable on demand. The
Company repaid the advance in April 2001.
The officer also paid travel and administrative expenses totaling $6,115 on
behalf of the Company prior to March 31, 2001 and $24,118 during the nine months
ended December 31, 2001. He received reimbursements and advances from the
Company totaling $43,102 during the nine months ended December 31, 2001. The net
advance of $2,972 is included in the accompanying financial statements as
expense advance to officer at December 31, 2001.
Note D: Income Taxes
--------------------
The Company records its income taxes in accordance with Statement of Financial
Accounting Standard No. 109, "Accounting for Income Taxes". The Company incurred
net operating losses during the periods shown on the condensed financial
statements resulting in a deferred tax asset, which was fully allowed for,
therefore the net benefit and expense result in $0 income taxes.
9
Item 2. Plan of Operation.
We intend to acquire and develop coal bed methane gas producing properties
in the United States, with our initial efforts focused on southeast Kansas. We
may do this by leasing oil and gas interests and drilling the leased property to
prove reserves or by acquiring working interests in production or reserves. In
August 2001 we changed our name from "Bail Corporation" to "Vista Exploration
Corporation" to reflect our new plan of operation.
Our current plan of operation has three separate phases. Phase one
consisted of identifying the most promising areas to drill for methane gas and
acquiring mineral rights for as many properties within the identified area as
practicable. Phase two will involve drilling and testing wells on the leased
acres to prove reserves, completing promising test wells, extracting the oil,
gas and other hydrocarbons that we find, and delivering them to market. In phase
three we plan to expand our drilling operations to maximize our production.
Phase 1 - Our Area of Interest
In June 2001 we retained consultants TCC Royalty Corp. and Austin
Exploration, L.L.C. to identify areas in southeast Kansas suitable for coal bed
methane exploration and development, to provide us with customary geological and
land maps, and to assist us with leasing mineral rights. TCC Royalty Corp.'s
geological services have been provided by Steven Tedesco, a geologist who is
also the President of Atoka Geochemical Services Corporation in Englewood,
Colorado. Austin Exploration, L.L.C.'s leasing services have been provided by
John Wilson, who is also the President of Western Land Services in Ludington,
Michigan. We have paid our consultants an initial fee of $25,000 and we are
obligated to pay them a 3% royalty fee on all oil and gas produced from property
leased or purchased by us, or oil and gas purchased by us from properties,
within the prospective area identified by the consultants. Additional geological
services are available to us at an hourly rate of $500 per day.
The targeted area identified by our management and our consultants is the
southwestern quarter of Coffey County, Kansas. This area was targeted for
several reasons, including its being situated above a known coal formation
called the Cherokee Basin, its proximity to active leasing efforts of other oil
and gas companies in southeastern Kansas in general and southern Coffey County
in particular, known oil and gas drilling and production in the region, the
availability of mineral rights for lease, and other geological information
provided by TCC Royalty Corp.
The Western Interior Coal Region includes three basins in the central
United States that contain gas bearing coal deposits of similar age and rank.
They are the Arkoma, Forest City and Cherokee Basins. Together these three
basins stretch from western Arkansas and central Oklahoma northward through
eastern Kansas and western Missouri into central Iowa. Our targeted area is
within the Cherokee Basin which is defined geographically as the area bounded to
the north by the Bourbon Arch, to the east and southeast by the Ozark Dome, and
to the west by the Nemaha uplift, encompassing northern Oklahoma, southeastern
Kansas, and southwestern Missouri.
The Cherokee Basin formation contains Pennsylvanian age coal beds which are
believed to be contiguous throughout the entire basin. Coal found throughout the
basin is generally of the same age and type and therefore theoretically should
contain similar quantities and quality of gas. Historically, the majority of
coal bed methane gas production in Kansas has been south of our targeted area,
including production in Labette, Wilson, Neosho and Cherokee Counties, Kansas,
where coal seams and black shale averaging four feet in thickness have been
reported and initial water production generally has been less than 50 barrels
per day, eventually dropping to below 10 barrels per day. Although currently
there are no coal bed methane wells producing in our targeted area, drilling
logs from oil exploration in and surrounding our targeted area typically confirm
the uniformity of the coal beds, indicating coal seams similar to those found to
the south of our targeted area. Additionally, a small number of coal bed methane
gas wells are producing in Woodson County, Kansas (approximately 10 miles south
of our targeted area) and Anderson County, Kansas (approximately 20 miles east
of our targeted area).
10
Phase 1 - Our Leasing Activities
In July 2001 we opened an office in Burlington, Kansas for $350.00 per
month and started leasing land in the south half of Coffey County, Kansas and
the southeast portion of Lyon County, Kansas, to drill for coal bed methane gas.
Lyon County is adjacent to, and west of, Coffey County and both counties are
within the Cherokee Basin.
As of February 1, 2002, we had executed 115 separate leases totaling
approximately 15,388 acres, of which approximately 13,902 acres are in Coffey
County and approximately 1,486 acres are in Lyon County. We have paid
approximately $50,000 to date to obtain our leases. In the event that we are
successful in phase two of our plan and we find commercially producable gas or
oil, we intend to lease additional available land to the extent that we believe
such land will further our exploration and development activities. Because we
believe that we can continue to successfully lease land without having our
office in Burlington, Kansas, we closed that office in November 2001.
All of the mineral leases that we have executed in southeast Kansas grant
us the exclusive right to explore for and develop oil, gas and other
hydrocarbons and minerals that may be produced from wells drilled on the leased
property. Each lease also grants us rights of way and easements for laying
pipelines and servicing or drilling other wells in the vicinity of the leased
property.
Each lease has an initial term of 5 years that is automatically extended
for such period of time as we continue to produce oil or gas from the leased
property or acres pooled with the leased property or we continue our drilling
operations on the leased property or acres pooled therewith. We will be deemed
to have discontinued our operations on a leased property, and thus our lease of
that property will no longer be extended, if we discontinue drilling or
producing oil and gas on such property for 120 days or more. If a lease is not
automatically extended, we may extend the term of a lease for an additional 3
years by paying the lessor $10 per net mineral acre.
We paid each lessor an initial payment of $10 upon the execution of our
lease. Regardless of whether or not we are producing oil and gas from a leased
property or acres pooled therewith, on the one-year anniversary of each lease we
will be required to pay the lessor $10 per net mineral acre leased. If we fail
to make such payment, the lease will terminate 30 days thereafter. We have
agreed to pay each lessor a royalty equal to 12.5% of any oil, gas or other
minerals that may be produced from wells drilled on the leased property. In the
event of a shut-in well capable of producing oil or gas, we have agreed to pay
the lessor a royalty equal to $1 per year per net mineral acre.
Pursuant to the lease payment terms described above, we will be obligated
to make the following one-year anniversary payments beginning in August 2002:
Month No. of Leases No. of Net Mineral Acres Payment
----- ------------- ------------------------ -------
August 69 9,491.35 94,913.50
September 42 5,397.10 53,971.00
October 4 500.00 5,000.00
- ------ --------
TOTAL: 115 15,388.45 $153,884.50
11
Under our leases we have the right to pool or unitize the leased property
with other land owned or leased by us in the immediate vicinity for the
production of oil or gas. With respect to shallow gas and associated
hydrocarbons produced in conjunction therewith, we have the right to pool or
unitize the leased properties into a development pool of a maximum of 3,000
acres if we have drilled at least 2 wells within the pooled unit no later than 1
year after the expiration of the primary term of the lease.
We have agreed to indemnify each lessor against any and all liabilities
arising out of our operations on the leased property, including environmental
liabilities. We also have agreed to pay each lessor the amount of $500 per acre
as liquidated damages for any leased property that is damaged as a result of our
operations on such leased property. Additionally, we have agreed to pay each
lessor for any damages caused by us to any crops growing on the leased property.
Following the completion of our operations on a leased property, we are
obligated to restore the well site to its original condition and land contour,
to the extent possible.
All of the oil and gas property that we have leased to date is considered
"undeveloped acreage" which the Securities and Exchange Commission defines as
"lease acreage on which wells have not been drilled or completed to a point that
would permit the production of commercial quantities of oil and gas regardless
of whether such acreage contains proved reserves." We own a working interest in
15,388.45 gross undeveloped acres (100% of each leased acre) and 13,143.30 net
undeveloped acres (84.5% of 10,717.99 leased acres and 87.5% of 4,670.46 leased
acres) in southern Kansas. A "working interest" is the operating interest that
gives us, as the operator, the right to drill, produce and conduct operating
activities on the property and a share of production. A "net acre" (or net well)
is deemed to exist when the sum of the fractional working interest owned in
gross acres or gross wells equals one. The number of net acres or net wells is
then expressed as a whole number and fractions thereof. A "gross acre" (or gross
well) is the total acres or wells, as the case may be, in which a working
interest is owned.
Before committing substantial resources, including obtaining necessary
permits and preparing for drilling on any particular leased property, we plan to
complete our due diligence on our leased property, including obtaining a title
opinion or title insurance to confirm our rights to any oil, gas and other
minerals produced pursuant to our lease. It is difficult to determine what our
final interest in any oil, gas or other mineral that we produce will be until we
have negotiated all agreements with the third parties that we will hire to
perform our drilling activities and operate our wells.
In addition to our leasing activities in Kansas, in June 2001 we acquired a
one-year option for a lease on 4,560 acres in Island Township, Blaine County,
Montana from Geominerals Corp. for $1,400. Geominerals Corp. is controlled by
George Andrews, our former president and director. If we exercise the option, we
will pay $2.50 per acre for a total purchase price of $10,000 (after credit of
the amount paid for the option). Currently we do not intent to exercise this
option.
Phase 2 - Our Anticipated Drilling Activities
Phase two of our current plan of operation will involve identifying the
most promising and cost-effective drill sites on our leased acres, drilling and
testing wells to prove reserves, completing promising test wells, extracting the
oil, gas and other hydrocarbons that we find, and delivering them to market.
Although we believe that we have leased enough land to move forward with phase
two of our plan, we will have to obtain additional financing before we can
implement this next phase. We anticipate that we will need approximately
$750,000 to achieve our initial goal of drilling, testing and completing ten
coal bed methane gas producing wells.
12
We have just begun phase two of our plan of operation. To date we have not
commenced any drilling or other exploration activities on the properties that we
have leased and thus we do not have any estimates of oil and gas reserves on
such properties. Consequently we have not reported our reserve estimates to any
state or federal authority.
Furthermore, we have not yet identified any specific drill sites. Drill
sites will be selected based on a variety of factors, including information
gathered from historic records and drill logs (depth and thickness of coal seams
and the results of electric gamma ray readings), proximity to existing
distribution pipelines, ease of access for drilling equipment, the presence of
oil and natural gas in the immediate vicinity, and consultations with our
operator and driller. Because a majority of this research information was
obtained during phase one of our plan, we believe that the cost of identifying
drill sites will be insubstantial. With the exception of the evaluation of the
geological structures that we encounter during the drilling process, the cost of
which has been factored into our estimated drilling costs, we do not anticipate
needing any further product research.
If phase two of our plan of operation is fully implemented, we will drill,
test and complete ten coal bed methane gas producing wells. Our drilling efforts
also will determine whether there are other forms of commercially producable
hydrocarbons present, such as oil or other types of natural gas. Each well will
be drilled and tested individually. If commercially producable amounts of gas
are present, the well will be completed and a distribution pipeline installed.
Completed wells that are producing and connected to distribution pipelines will
begin generating revenues as soon as they begin pumping although these revenues
may be realized on a quarterly basis.
We anticipate that each well in our targeted area will cost approximately
$25,000 to drill and test, an additional $15,000 to complete, plus an additional
$350 per month per well to pay for electricity, pulling and repairs, pumping and
other miscellaneous charges. We intend to hire third parties to operate our
wells and perform our drilling activities.
Once we have identified a proposed drilling site, we will engage the
services of an operator licensed to operate oil and gas wells in the State of
Kansas. The operator will be responsible for permitting the well, which will
include obtaining permission from the Kansas Oil and Gas Commission relative to
spacing requirements and any other state and federal environmental clearances
required at the time that the permitting process commences. Additionally, the
operator will formulate and deliver to all interest owners an operating
agreement establishing each participants' rights and obligations in that
particular well based on the location of the well and the ownership. In addition
to the permitting process, the operator will be responsible for hiring the
driller, geologist and land men to make final decisions relative to the zones to
be targeted, confirming that we have good title to each leased parcel covered by
the spacing permit and to actually drill the well to the target zone. Should the
well be successful, the operator would thereafter be responsible for completing
the well and connecting it to the most appropriate transmission facility for the
hydrocarbons produced. It is likely that we will pay the operator by issuing it
a net revenue interest, which we expect would be equal to the 12.5% interest
that we have granted to the mineral owners from whom we have leased our
property.
The operator will be the caretaker of the well once production has
commenced. As such, the operator will be responsible for paying bills related to
the well, billing working interest owners for their proportionate expenses in
drilling and completing the well, and selling the production from the well. We
anticipate that once the production has been sold, the purchaser thereof will
carry out its own research with respect to ownership of that production and will
send out a division order to confirm the nature and amount of each interest
owned by each interest owner. Once a division order has been established and
confirmed by the interest owners, the production purchaser will issue the checks
to each interest owner in accordance with its appropriate interest. From that
point forward, the operator also will be responsible for maintaining the well
and the wellhead site during the entire term of the production or until such
time as the operator has been replaced.
13
Although we presently do not intend to seek status as a licensed operator,
if in the future we believe that seeking licensed operator status is appropriate
and we have adequate staff available to us, we may decide to operate our own
wells.
We have had preliminary discussions with Becker Drilling of Bucyrus,
Kansas, to act as both the operator and driller of our wells. Becker Drilling
was established in 1977 and is owned and operated by Mike Becker, who has
drilled and completed over 1,000 oil and gas wells in Kansas, Oklahoma, Texas,
New Mexico, Illinois, Wyoming, and Missouri, including over 20 coal bed methane
wells.
The driller will be responsible for performing, or contracting with third
parties and supervising their efforts, all aspects of the drilling operation
except for geological services. We currently anticipate getting additional
geological services from TCC Royalty Corp.
The success of phase two of our plan of operation is dependent upon our
ability to obtain additional capital to drill our wells and also upon our
successfully finding commercially producable amounts of coal bed methane gas or
other hydrocarbons in the wells that we drill. We cannot assure you that we will
obtain the necessary capital or that we will find commercially producable
amounts of gas if our drilling operations commence.
14
Phase 2 - Getting Our Products To Market
If any of our wells proves to hold commercially producable gas, we will
need to install a distribution infrastructure to transport our gas from the
wellhead to a major distribution pipeline. We have identified several major
distribution pipelines currently installed in our general vicinity, including
lines owned by Phillips Petroleum, Williams Energy, CMS Panhandle Eastern, and
Kansas Gas. We have initiated contact with these companies to ascertain the
specific locations of their pipelines, their requirements to purchase gas from
us (including volume of gas and quality of gas), and costs to connect to their
pipelines. Traditionally, the major distributors of gas in the United States
have purchased production from anyone who can get sufficient quantities of
quality gas to their distribution pipeline. Because some of these companies have
purchased coal bed methane from producing wells in the southern part of Kansas,
we believe that if the gas produced from wells drilled in our targeted area
meets their criteria in both quantity and quality, they will purchase our gas
from us at market prices. To date, we have not entered into any purchase
agreements nor have we received assurances from anyone that they will enter into
such agreements with us in the future.
We cannot accurately predict the costs of transporting our gas products to
existing pipelines until we locate our first successful well. The cost of
installing a distribution infrastructure will vary depending upon the distance
the gas must travel from our wellhead to the tap, and whether the gas first must
be treated to meet the purchasing company's quality standards. However, based on
the close proximity of several major distribution pipelines to our leased
properties, plus our intent to drill as close to these pipelines as practicable,
we anticipate that the total cost of installing a distribution infrastructure
for ten producing wells will be approximately $150,000 or $10,000 each plus a
one-time expense of $50,000 to tap into the main distribution pipeline, which
will payable for the first distribution line.
The prices obtained for oil and gas are dependent on numerous factors
beyond our control, including domestic and foreign production rates of oil and
gas, market demand and the effect of governmental regulations and incentives. We
do not have any delivery commitments with respect to any oil or gas produced
from any properties that we acquire. However, due to the U.S. government's
recent push toward increased domestic production of energy sources, and the high
demand for natural gas, we do not anticipate any difficulties in selling any oil
and gas that we produce, once it has been delivered to a distribution facility.
Phase 3 - Expanding Our Operations
The expansion phase of our plan of operation can commence only after the
successful completion of phase two, which means that we will have operating
wells that are producing gas and generating revenues for us. Our expansion
efforts will be constrained by state and local laws as well as by the number of
mineral acres that we have leased. For example, because State of Kansas
regulations require that coal bed methane wells be spaced no closer than eighty
acres, we could expand to a maximum of 187 wells based on the property that we
have leased to date. We intend to lease additional available land to the extent
that we believe such land will further our exploration and development
activities.
Liquidity and Capital Resources
Our auditors included an explanatory paragraph in their opinion on our
financial statements for the year ended March 31, 2001, to state that our losses
since inception and our net capital deficit at March 31, 2001 raise substantial
doubt about our ability to continue as a going concern. Our ability to continue
as a going concern is dependent upon raising additional capital and achieving
profitable operations. We cannot assure you that our plan of operation will be
successful in addressing this issue.
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During the three months ended December 31, 2001, we spent approximately
$44,000 pursuing oil and gas leases in southeast Kansas, including $19,000 in
legal and accounting fees, which expenses were substantially funded by $25,000
received as proceeds from the sale of our common stock in December 2001. At
December 31, 2001, we had cash of $2,450, a decrease of $9,204 from September
30, 2001, and current liabilities of $26,983.
During the nine months ended December 31, 2001, we spent approximately
$205,000 pursuing potential oil and gas leases in southeast Kansas, including
$25,000 in compensation paid to our president, and $71,000 in legal and
accounting fees. These fees were incurred in connection with negotiating
potential acquisitions, preparing investment documents in connection with our
capital raising efforts, and preparing and filing a registration statement for
the resale of shares owned by some of our current shareholders. These expenses
were substantially funded by $223,000 received as proceeds from the sale of our
common stock in April, June and December 2001. At December 31, 2001, we had cash
of $2,450, an increase of $2,377 from March 31, 2001, and current liabilities of
$26,983. In January 2002, we received approximately $25,000 from the sale of our
common stock to two overseas investors.
Our Capital Requirements
We will need to raise additional funds to finance our planned operations
during the next 12 months, including implementing phase two of our plan of
operation and making our mineral lease payments as they come due. We anticipate
that we will need a minimum of $100,000 to begin drilling operations ($50,000
for drilling expenses and $50,000 for operating expenses) and a total of
$750,000 to complete phase two of our plan, which entails drilling and
completing ten coalbed methane gas wells. We intend to raise these funds through
one or more equity or debt offerings, either private or public, commencing in
the first quarter of 2002.
We currently do not have any binding commitments for, or readily available
sources of, additional financing. We cannot assure you that additional financing
will be available to us when needed or, if available, that it can be obtained on
commercially reasonably terms. If we do not obtain additional financing we will
not be able to implement our planned drilling and exploration activities and may
not be able to maintain our mineral leases. Furthermore, we could be forced to
cease our operations and liquidate our assets.
Assuming that we are able to obtain a minimum of $100,000 in additional
financing, we will begin drilling our first well. We will drill and test the
well for gas and, if producable amounts of gas are found, complete the well.
However, unless we receive an additional $60,000 in financing above the $100,000
minimum, we will not be able to install a gathering system and a well tap, and
therefore would not be able to generate any revenues from the well. Nonetheless,
a proven gas reserve would increase the value of our leased mineral rights
considerably and may increase our ability to receive additional financing to
proceed with our phase two drilling activities. In the event that our first test
well does not prove to hold producable reserves, we would have enough capital to
drill and test a second well, but we would need approximately $15,000 in
additional financing to complete it. If the second well did not prove to hold
producable reserves, we would be forced to cease our drilling operations until
such time as further financing became available, if ever. If no further
financing became available, we would be forced to cap a producing well or plug a
non-producing well, and cease our operations.
Assuming that we are able to obtain $750,000 in additional financing, we
will be able to drill, test and complete up to ten producing coal bed methane
wells and install the necessary distribution infrastructure to transport our gas
from the wellhead to a major distribution pipeline. If each well proved to hold
producable amounts of gas, we believe that we could generate revenues relatively
quickly. Completed wells that are producing and connected to distribution
pipelines will begin generating revenues as soon as they begin pumping although
these revenues may be realized on a quarterly basis. In the event that one or
more drill sites proves unproducable, we will complete as many producable wells
as possible with the funds available to us.
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In the event that we are able to obtain more than $100,000 but less than
$750,000 in additional financing, we will drill, test, complete and distribute
gas from as many well sites as possible with the amount of capital available to
us.
We estimate that it will take approximately two weeks to drill, test and
complete each well, and an additional two weeks to four weeks per well to
install the distribution pipelines, depending on the distance from the well to
the pipeline. With full funding, we expect phase two to take approximately ten
months from start to finish. However, the timeline for completion of phase two
of our plan of operation is completely dependent upon our ability to secure
additional financing. We cannot implement any of our drilling and exploration
plans until we obtain additional financing.
In addition to the capital necessary to commence our drilling activities,
we will need additional financing to make our mineral lease payments as they
come due. From August 2002 to October 2002, we will need approximately $154,000
to make our one-year anniversary payments on our leased properties in southeast
Kansas. Although we have budgeted $75,000 of the $750,000 that we need to
implement phase two to pay some of these lease payments, our plan assumes that
we have begun production prior to this point and thus are producing and selling
sufficient gas to meet our lease payments. Failure to complete enough wells to
generate sufficient income to pay the $154,000 lease payments would require us
to obtain additional financing to retain our mineral leasehold rights. If we
fail to make these payments, we could lose our rights to some or all of the
property currently under lease, which could make further development impossible.
Under these circumstances, we could be forced to cease our operations and
liquidate our assets.
Furthermore, if we decide to exercise our option to lease 4,560 acres in
Blaine County, Montana, we will need an additional $8,600 in June 2002.
If we do not obtain additional financing through an equity or debt
offering, we may attempt to sell our leasehold interests in some or all of the
properties that we have leased in southeast Kansas together with any proprietary
information that we have developed concerning such properties, such as title
searches, title policies, engineering reports and records, core information,
drilling reports, and production records, if any. However, we cannot assure you
that we will be able to find interested buyers or that the funds received from
any such sale would be adequate to fund our activities.
Employees
We currently have no full time employees except our president who is
devoting his full-time to our activities. In July 2001 we retained two
independent leasing consultants to help us lease land for our oil and gas
operations. We terminated our agreements with the independent leasing
consultants in October 2001 and December 2001.
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PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
None.
Item 2. Changes in Securities and Use of Proceeds.
During December 2001 and January 2002, we sold 450,000 shares of our common
stock at an average price of $0.12 per share, with net proceeds of approximately
$50,000, to three accredited investors without registering the shares under the
Securities Act of 1933. No underwriter, sales or placement agent was involved in
the sale to the U.S. shareholder. A finders fee of approximately $1,500 was paid
to a non-U.S. finder with respect to the two non-U.S. investors. These sales
were made pursuant to Section 4(2) and Rule 506 of Regulation D adopted under
the Securities Act of 1933. The U.S. purchaser is controlled by one of our
current shareholders and thus was known to us and our management through
pre-existing business relationships. The two non-U.S. investors were known to us
as long standing business associates of other shareholders. All of the
purchasers were provided access to the material information which they requested
and all information necessary to verify such information, and were afforded
access to our management in connection with their purchases. The purchasers of
the unregistered securities acquired such securities for investment and not with
a view toward distribution, acknowledging such intent to us.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no items submitted to a vote of security holders during the
third quarter of the year ended December 31, 2001.
Item 5. Other Information.
None.
Item 6. Exhibits and Reports on Form 8-K.
(a) The following exhibits are furnished as part of this report:
None.
(b) Reports on Form 8-K.
None.
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SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
VISTA EXPLORATION CORPORATION
Date: February 14, 2002 By: /s/ Charles A. Ross
-----------------------
Charles A. Ross, Sr.,
President and Chief Accounting Officer
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