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 June 30, 2002
[_] 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
N.A.
(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 August 9, 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 - June 30, 2002 (Unaudited)................. 4
Condensed statement of operations (Unaudited) -
three months ended June 30, 2001 and 2000 and
April 9, 1998 (inception) through June 30, 2002..................... 5
Condensed statements of cash flows (Unaudited) -
three months ended June 30, 2001 and 2000 and
April 9, 1998 (inception) through June 30, 2002..................... 6
Notes to condensed financial statements (Unaudited)................. 7
Item 2. Plan of Operation................................................... 9
PART II--OTHER INFORMATION................................................... 16
Item 1. Legal Proceedings................................................... 16
Item 2. Changes in Securities and Use of Proceeds........................... 16
Item 3. Defaults Upon Senior Securities..................................... 16
Item 4. Submission of Matters to a Vote of Security Holders................. 16
Item 5. Other Information................................................... 17
Item 6. Exhibits and Reports on Form 8-K.................................... 17
Signatures.......................................................... 17
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 obtain sufficient financing to commence drilling
operations,
o our ability to discover producible gas on our leased properties,
o capital costs of drilling and completing wells,
o capital costs of building other related production or gathering
facilities,
o the availability of contract operators and drillers,
o the continued demand for natural gas, and
o the 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 product research. Such statements are subject to
a number of assumptions including the following:
o risks and uncertainties, including the risk factors in this
prospectus,
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)
June 30, 2002
ASSETS
Current assets:
Cash ........................................................ $ 126
---------
Total current assets 126
Oil and gas properties, at cost ................................... 40,832
---------
$ 40,958
=========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accrued liabilities ......................................... $ 130,246
---------
Total current liabilities 130,246
---------
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, 6,090,000 shares issued and outstanding ...... 220,216
Additional paid-in capital .................................. 3,600
Deficit accumulated during the development stage ............ (313,104)
---------
Total shareholders' equity (89,288)
---------
$ 40,958
=========
See accompanying notes to financial statements
4
VISTA EXPLORATION CORPORATION
(A Development Stage Company)
Statements of Operations (Unaudited)
April 9, 1998
Three Months Ended (Inception)
June 30, Through
-------------------------- June 30,
2002 2001 2002
----------- ----------- -----------
Costs and expenses:
Legal fees .................................... $ 41,555 $ 25,374 $ 161,905
Accounting fees ............................... 7,065 3,000 23,466
Travel ........................................ 2,612 6,087 34,256
General and administrative .................... 1,482 2,565 18,244
Compensation .................................. 7,500 -- 47,500
Project evaluation costs ...................... -- 27,603 28,902
Rent, related party ........................... -- -- 3,600
Organizational costs .......................... -- -- 500
----------- ----------- -----------
Operating loss (60,214) (64,629) (318,373)
Interest income ................................... -- -- 114
----------- ----------- -----------
Loss before income taxes and extraordinary item (60,214) (64,629) (318,259)
Provision for income taxes ........................ -- -- --
----------- ----------- -----------
Loss before extraordinary item (60,214) (64,629) (318,259)
Extraordinary gain on extinguishment of debt,
net of income taxes of $-0- ................... -- -- 5,155
----------- ----------- -----------
Net loss $ (60,214) $ (64,629) $ (313,104)
=========== =========== ===========
Basic and diluted loss per common share:
Before extraordinary item ..................... $ (0.01) $ (0.02)
=========== ===========
Gain on extinguishment of debt ................ $ -- $ --
=========== ===========
Net loss ...................................... $ (0.01) $ (0.02)
=========== ===========
Basic and diluted weighted average
common shares outstanding ..................... 6,090,000 3,848,352
=========== ===========
See accompanying notes to financial statements
5
VISTA EXPLORATION CORPORATION
(A Development Stage Company)
Statements of Cash Flows (Unaudited)
April 9, 1998
Three Months Ended (Inception)
June 30, Through
---------------------- June 30,
2002 2001 2002
--------- --------- ---------
Cash flows from operating activities:
Net loss ...................................... $ (60,214) $ (64,629) $(313,104)
Transactions not requiring cash:
Common stock issued for services ........... -- -- 500
Contributed rent ........................... -- -- 3,600
Changes in operating assets and liabilities:
Receivables and advances ............... 8,265 (8,127) --
Accounts payable and accrued liabilities 47,063 25,898 130,246
--------- --------- ---------
Net cash used in operating activities (4,886) (46,858) (178,758)
--------- --------- ---------
Cash flows from investing activities:
Investment in oil and gas properties .......... -- -- (40,832)
--------- --------- ---------
Net cash used in investing activities ... -- -- (40,832)
--------- --------- ---------
Cash flows from financing activities:
Advances from officer ......................... -- (10,500) --
Sale of common stock ......................... -- 198,000 250,405
Offering costs incurred ....................... -- (20,561) (30,689)
--------- --------- ---------
Net cash provided by financing activities -- 166,939 219,716
--------- --------- ---------
Net change in cash ................................ (4,886) 120,081 126
Cash, beginning of period ......................... 5,012 73 --
--------- --------- ---------
Cash, end of period $ 126 $ 120,154 $ 126
========= ========= =========
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
6
VISTA EXPLORATION CORPORATION
A Development Stage Company
---------------------------
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
June 30, 2002
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, 2002, as filed in its annual report on Form 10K-SB
filed July 1, 2002, 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, 2002 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
period ended June 30, 2002. The comparative figures for the three-month period
ended June 30, 2001 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.
7
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.
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, $33,325 during the year ended
March 31, 2002, and $3,265 during the three months ended June 30, 2002. He
received reimbursements and advances from the Company totaling $42,705 and
received compensation totaling $40,000 through March 31, 2002. During the three
months ended June 30, 2002 compensation to the officer of $7,500 was accrued and
remains unpaid at June 30, 2002.
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.
8
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. We 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 standard geological services, such as drill logging
services, well location recommendations and drill log interpretations, are
available to us from TCC Royalty Corp. at the 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 located above known coal-bearing units
(particularly the Cherokee Group), 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.
Numerous geological studies, such as Public Information Circular 19 -
Natural Gas from Coal in Eastern Kansas published by the Kansas Geological
Survey in 2001, demonstrate that the coal residing in the Cherokee Basin is
typically of Pennsylvanian age and is found, at various depths and thicknesses,
throughout the basin. Because coal found throughout the basin is generally of
the same age and type, theoretically it should contain similar quantities and
quality of gas. Although currently there are no coalbed methane wells producing
in our targeted area, there is a history of such production to the south of our
targeted area, including Labette, Wilson, Neosho and Montgomery Counties,
Kansas. Additionally, there are a small number of coalbed methane gas wells
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). All of these counties are in the Cherokee Basin. Reports from
these producing wells show coal seams and black shale averaging four feet in
thickness and initial water production averaging less than 50 barrels per day,
eventually dropping to below 10 barrels per day.
9
The rules and regulations of the Kansas Corporation Commission require that
drill logs must be generated for each well drilled and must be submitted to the
Commission, whereupon they become part of the public record. Additionally, many
operators also complete geophysical logs which also become public record and
clearly define the type of rock and its depth or location in the bore hole of
each well. We have examined over 100 such logs from oil exploration in and
surrounding our targeted area. These logs generally confirm the uniformity of
the coalbeds in the region and suggest coal seams within our targeted area
similar to those found to the south of our targeted area. This conclusion was
confirmed by William Stoeckinger, a certified petroleum geologist who has
published numerous articles regarding coalbed methane activities in Kansas. We
have also discussed many of these logs with an experienced well operator and
driller who we anticipate hiring to act as both the operator and driller of our
wells. Although we believe that the coalbeds within our targeted area will prove
to be similar to those found to the south of our targeted area, we cannot assure
you that they are or that even if they are, that we will find commercially
producible amounts of methane gas or any other hydrocarbons.
Phase 1 - Our Leasing Activities
In July 2001 we rented an office in Burlington, Kansas for $350.00 per
month and began leasing land in the south half of Coffey County, Kansas, and the
southeast portion of Lyon County, Kansas, in order to drill for coalbed methane
gas. Lyon County is adjacent to, and west of, Coffey County and both counties
are within the Cherokee Basin.
As of March 31, 2002, we had acquired 115 separate leases covering
approximately 15,388 acres, of which approximately 13,902 acres are in Coffey
County and approximately 1,486 acres are in Lyon County. We paid approximately
$50,000 to obtain our leases. In the event that we are successful in phase two
of our plan and we find commercially producible 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.
Each of our southeast Kansas mineral leases grants us the exclusive right
to explore for and produce oil, gas, coalbed methane, and other hydrocarbons and
minerals from wells located on the leased property. Each lease also grants us
rights-of-way and easements for laying pipelines and servicing other wells in
the vicinity of the leased property. Under the terms of each lease, the lessor
will receive a royalty equal to 12.5% of all oil, gas or other minerals produced
from the leased property or the proceeds of the sale thereof, and we will be
entitled to 87.5% of such production or proceeds. The lessor's royalty will be
free of costs and expenses and we will be responsible for all expenses incurred
in our operations including drilling, testing, completing and equipping.
Each lease has an initial or primary term of 5 years which is automatically
extended during such period thereafter 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. After the primary term, in the event oil and gas is not
being produced or shall have ceased on the leased property, the lease will not
terminate if we commence additional drilling or reworking operations within 120
days. If a lease is not extended beyond its primary term by production or
operations, we have the option to extend the primary term for an additional 3
years by paying the lessor $10 per net mineral acre.
10
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 (a well capable of producing oil or gas but, for
whatever reason, is not 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
We can not assure you that we will be able to obtain additional capital to
retain our leased mineral properties.
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.
11
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. We estimate that each title opinion or
title insurance will cost $1,000 and will take approximately two days to obtain.
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. We did not exercise the
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
$775,000 to achieve our initial goal of drilling, testing and completing ten
coalbed methane gas producing wells.
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. We will
select drill sites 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 pipelines, ease
of access for drilling equipment, the presence of oil and natural gas in the
immediate vicinity, and consultations with our geologist, 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 coalbed methane gas producing wells. Our drilling efforts
also will determine whether there are other forms of commercially producible
hydrocarbons present, such as oil or other types of natural gas. Each well will
be drilled and tested individually. If commercially producible amounts of gas
are present, the well will be completed and facilities installed to connect to
gathering or pipeline facilities. 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.
12
Our anticipated costs of drilling operations are based on estimates
obtained from third-party service providers whom we believe will be available to
us to provide the services that we will need. However, the actual costs of such
operations may be more or less than the estimates contained herein. If actual
costs of operations exceed our estimates to any significant degree, we may
require additional funding to achieve our phase two objectives.
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 Corporation 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.
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 coalbed methane
wells. We intend to continue our discussions with Becker Drilling after we
secure the additional financing needed to implement phase two of our plan of
operation.
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 that we will continue to
utilize outside consultants for geological services on an as-needed basis.
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 producible amounts of coalbed 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 producible
amounts of gas if our drilling operations commence.
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Phase 2 - Getting Our Products To Market
If any of our wells proves to hold commercially producible gas, we may need
to install necessary infrastructure to permit delivery of our gas from the
wellhead to a major pipeline. We have identified the locations of all major
gathering and other facilities currently installed in the general vicinity of
our targeted area and have initiated contacts with the owners of these
facilities to ascertain their specific requirements with respect to transporting
our gas to pipelines for transmission, including volume and quality of gas and
connection costs. Pursuant to the open access regulations issued by the Federal
Energy Regulatory Commission (beginning with Order No. 436 issued in 1985 and
most recently with Order No. 636 issued in 1992), the owner of an interstate
pipeline is required to transport any gas that a producer delivers so long as
the gas delivered meets the pipeline's reasonable, non-discriminatory
requirements regarding such things as quality and quantity of gas.
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 an infrastructure to deliver our gas to a pipeline or gatherer 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 such a infrastructure for ten producing wells will be approximately
$150,000, which includes a one-time expense of $50,000 to tap into the main
distribution pipeline, which expense will be payable for the first distribution
line.
Traditionally, the major marketers of gas in the United States have
purchased production from anyone who can deliver sufficient quantities of
quality gas. Because some of these companies have purchased coalbed 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 posted index market
prices. However, 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 with respect to any oil or gas produced from
any properties that we acquire.
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.
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, 2002, to state that our losses
since inception and our net capital deficit at March 31, 2002 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 June 30, 2002, we spent approximately $60,000
pursuing financing and maintaining the company's status, including $49,000 in
legal and accounting fees and $7,500 in officer compensation, substantially all
of which remains unpaid. At June 30, 2002, we had cash of $126, a decrease of
$4,886 from March 31, 2002, and current liabilities of $130,246.
Due to our lack of funds, we have not yet developed a formal budget for the
current fiscal year. If we are unable to meet a required payment for our mineral
leases or well completion, we could suffer a substantial loss of a business
opportunity.
Our Capital Requirements
We will need to raise additional funds to finance our planned operations
during the next 12 months, including making our mineral lease payments as they
come due and implementing phase two of our plan of operation. 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. If we fail to
make these payments, we likely will lose our rights to some or all of the
property currently under lease, which could make further development impossible.
In addition, we anticipate that we will need a minimum of $200,000 to begin
drilling operations ($50,000 for drilling expenses and $150,000 for operating
expenses and outstanding accounts payable) and a total of $775,000 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 second fiscal 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 maintain our mineral leases or to implement our planned drilling
and exploration activities. Under these circumstances, we could be forced to
cease our operations and liquidate our assets.
Assuming that we are able to obtain a minimum of $354,000 in additional
financing ($154,000 to retain our mineral leases and $200,000 to commence
drilling operations), we will begin drilling our first well. We will drill and
test the well for gas and, if producible amounts of gas are found, complete the
well. However, unless we receive an additional $60,000 in financing above the
$200,000 minimum, we will not be able to install a gathering system and a
pipeline 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 producible 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 producible 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 $929,000 in additional financing
($154,000 to retain our mineral leases and $775,000 for drilling operations), we
will be able to drill, test and complete up to ten producing coalbed methane
wells and install the necessary infrastructure to transport our gas from the
wellhead to a gatherer or pipeline. If each well proved to hold producible
amounts of gas, we believe that we could generate revenues relatively quickly.
Completed wells that are producing and connected to 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
unproducible, we will complete as many producible wells as possible with the
funds available to us.
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In the event that we are able to obtain more than $354,000 but less than
$929,000 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 facilities to connect to gathering or pipeline facilities, 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.
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. Our president has agreed to
devote as much time to our activities as is required to implement our plan of
operation. 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.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
None.
Item 2. Changes in Securities and Use of Proceeds.
None.
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
first quarter of the year ended June 30, 2002. We are in the process of
soliciting proxies for the annual shareholders meeting to be held on August 16,
2002.
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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.
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: August 9, 2002 By: /s/ Charles A. Ross, Sr.
--------------------------------------
Charles A. Ross, Sr.,
President and Chief Accounting Officer
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