View:
January
23, 2006
Mr.
H.
Roger Schwall
Assistant
Director
Division
of Corporate Finance
United
States Securities and Exchange Commission
Mail
Stop
7010
Washington,
DC 20549
| RE: |
Natural
Gas Systems, Inc.
|
Registration
Statement on Form SB-2
Filed
June 6, 2005 and amended October 19, 2005
File
No.
333-125564
Dear
Mr.
Schwall:
On
behalf
of Natural Gas Systems, Inc., a Nevada corporation (the “Company”),
we
have enclosed for filing under the Securities Act of 1933 Amendment No. 2 to
the
Registration Statement on Form SB-2, Registration No. 333-125564 (the
“Registration
Statement”),
including the exhibits thereto, that was initially filed with the Securities
and
Exchange Commission (the “Commission”)
on
June 6, 2005, and amended by Amendment No. 1 thereto as filed with the
Commission on October 19, 2005. We have supplementally also enclosed a copy
of
Amendment No. 2 that has been marked to show the changes that have been made
to
Amendment No. 1. Amendment No. 2 to the Registration Statement includes an
amended prospectus (the “Prospectus”).
By
its
letter dated November 18, 2005, the staff of the Commission (the “Staff”)
provided the Company with comments on Amendment No.1. We have set forth below
the responses of the Company to the Staff’s comments. The numbers of the
responses set forth below correspond to the numbered comments in the November
18
letter from the Staff.:
Comment
1: Please provide justification for not naming Mr. James F. George as an
underwriter.
We
have
amended our document to remove James F. George as a selling
stockholder.
Comment
2: Please expand your response to prior comment 5 regarding Item 310 of
Regulation SB and accounting for the “reverse merger”.
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a.
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With
respect to the financial statements we filed relating to the May,
2004
merger of Old NGS with a subsidiary of Reality Interactive, Inc.
(the
former name of our company), we have revised our note on page F-7,
and
deleted references to SAB 2:A.
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As
to the
appropriateness of our accounting for our transaction with Reality Interactive
and the financial statements we filed with the SEC, please be advised that
Reality Interactive represented that it had no operating assets from 1999
through the time of the merger. Additional information regarding the parties,
structure and shares exchanged follows:
-1-
On
May
26, 2004, Reality Acquisition Corp. (“Reality Sub”), a newly formed wholly owned
subsidiary of Reality Interactive, Inc., a Nevada corporation ("Reality
Interactive"), merged with and into Natural Gas Systems, Inc., a Delaware
corporation ("Old NGS"). As a result of this merger (the "Merger"), Old NGS
became a wholly owned subsidiary of Reality Interactive. The Merger occurred
pursuant to an Agreement and Plan of Reorganization dated as of April 12, 2004
(the "Merger Agreement") among Reality Interactive, Reality Sub, Global
Marketing Associates, Inc., Dean H. Becker and Old NGS. On April 27, 2004,
Reality Interactive filed a copy of the Merger Agreement with the Commission
on
a Report on Form 8-K/A.
Reality
Sub merged with and into Old NGS upon the terms and conditions set forth in
the
Merger Agreement and in accordance with the provisions of the Delaware General
Corporation Law. It was the intention of the parties that the transaction
qualify as a tax-free reorganization under Section 368(a)(2)(E) of the Internal
Revenue Code of 1986, as amended. Old NGS was the surviving corporation and
the
separate existence of Reality Sub ceased when the Merger became effective.
Each
share of Old NGS Common Stock issued and outstanding immediately prior to the
Merger was converted into one (1) share of Reality Interactive Common Stock.
All
such shares of Old NGS Common Stock that were outstanding were automatically
canceled and ceased to exist. All 1,000 shares of the Common Stock of Reality
Sub (representing all issued and outstanding shares) were converted into one
(1)
share of Common Stock of Old NGS, which is owned by Reality
Interactive.
Immediately
prior to the Merger, Reality Interactive had 7,946,255 outstanding shares of
common stock and no outstanding shares of preferred stock. Pursuant to the
Merger, (i) 7,000,000 of the 7,010,000 shares of Reality Interactive common
stock held by Dean H. Becker, Reality Interactive's President and Chief
Executive Officer, were cancelled, and (ii) 21,750,001 shares of Reality
Interactive common stock were issued to the stockholders of Old NGS in exchange
for 100% of the outstanding shares of common stock of Old NGS. The share
exchange ratio in the Merger was determined through arms'-length negotiations
between Reality Interactive and Old NGS. Prior to the Merger, Mr. Becker owned
approximately 88% of Reality Interactive's outstanding shares.
Each
outstanding option or warrant to purchase shares of Old NGS common stock,
whether or not then exercisable, was converted into an option or a warrant
to
purchase an identical number of shares of Reality Interactive common stock
at a
price equal to the exercise price of the option or warrant in effect immediately
prior to the Merger.
As
a
result of the Merger, (i) 22,696,256 shares of Reality Interactive common stock
were outstanding, 95.8% of which were owned by the former stockholders of Old
NGS, (ii) control of Reality Interactive was assumed by the former stockholders
of Old NGS, (iii) the executive officers of Old NGS became the executive
officers of Reality Interactive, (iv) the Board of Directors of Old NGS became
the Board of Directors of Reality Interactive and (v) Reality Interactive’s name
was changed to Natural Gas Systems, Inc, a Nevada corporation.
-2-
Based
on
these facts and circumstances, especially those described in the immediately
preceding paragraph above, we concluded that the merger transaction represented,
in effect, a recapitalization of Old NGS. Accordingly, we accounted for the
transaction as a “reverse merger”, wherein Old NGS was treated as the accounting
acquiror and filed financial statements with the SEC reflecting the historical
financial condition and operating results of Old NGS. No goodwill arose from
the
transaction and all transaction costs were expensed as incurred.
In
accordance with Rule 310 (c) of Regulation S-B we provided on Form 8-K/A the
following financial information:
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i.
|
Audited
revenue and direct operating expenses for an 18 month period, consisting
of the nine months ended December 31, 2002 and the nine months
ended
September, 2003 (date of the acquisition). Revenue and direct operating
expense statements accorded purchasers of “oil and gas businesses” were
presented in accordance with additional guidance provided by the
Division
of Corporate Finance at Item IIIC - Financial Statements for Acquired
Oil
and Gas Producing Properties, since full financial statements were
not
available or reasonably attainable from the seller.
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|
ii.
|
Audited
financial statements of Old NGS from September 23, 2003 (inception),
through its old fiscal year ended December 31, 2003.
|
|
b.
|
With
respect to our acquisitions of two groups of producing leasehold
interests
in the Tullos Field Area in September 2004 from Atkins Production,
and
February 2005 from Chadco, we followed Regulation S-B 310 c., Financial
Statements of Businesses Acquired or to be Acquired, as follows,
to
ascertain whether financial information for these properties was
required
to be filed on Form 8-K in accordance with Rule 310 of Regulation
S-B:
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|
i.
|
For
the tests at 310-2. i & ii:
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|
1.
|
Our
assets at June 30, 2004 were
$4,011,065.
|
|
2.
|
Our
investments in and the total assets we acquired in the Tullos Field
Area
acquisition from Atkins in September 2004 was $705,790, or 17.6%
of our
total assets at June 30, 2004 (or 16.3% after additional adjustments
to
the purchase price described in #4
below).
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3.
|
Our
investments in and the total assets we acquired in the Tullos Field
Area
acquisition from Chadco in February 2005 was $798,907, or 19.9% of
our
total assets at June 30, 2004 (or 16% after additional adjustments
to the
purchase price described in #4
below).
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4.
|
Pursuant
to the terms of the purchase agreements regarding the property
acquisitions described in #2 and 3 above, we are the beneficiary
of
certain contractual downward adjustments to the purchase prices
resulting
from proceeds to be received from the State of Louisiana concerning
eminent domain proceedings on wellbores located within a state
highway
expansion. The expected adjustments
are:
|
-3-
|
a.
|
A
$52,667.67* downward adjustment to the Atkins acquisition of September
of
2004, or 1.3% of our assets at June 30,
2004.
|
|
b.
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A
$158,000** downward adjustment to the Chadco acquisition of February
2005,
or 3.9% of our assets at June 30,
2004.
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c.
|
To
date, we have received notice from legal counsel that one of the
Chadco
well proceedings has been finalized in the amount of $39,500 to our
interest or .98% of our assets at June 30, 2004, although we have
not
received the proceeds as of the date of this
letter.
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*
(1/3 of
2 wells @ $79,000 each)
**
(½ of
4 wells @ $79,000 each)
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ii.
|
For
the test at 310-2.iii:
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1.
|
Our
loss for the period from September 23, 2003 (inception) to June
30, 2004
was $1,364,587.
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2.
|
Revenue
and direct operating expenses, including a $36,000 allocation for
field
supervision, for the twelve months ended June 30, 2004 for our Tullos
Field Area acquisition from Atkins in September 2004, was $161,000,
or
11.8% of our loss for the period from September 23, 2003 (inception)
through our year ended June 30,
2004.
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3.
|
By
analogy, revenue and direct operating expenses, including field
supervision, for the twelve months ended June 30, 2004 for our
Tullos
Field Area acquisition from Chadco in February 2005 was $186,277,
or 13.7%
of our loss for the period from September 23, 2003 (inception)
through our
year end June 30, 2004.
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iii.
|
Since
none of the tests exceeded 20% individually, or 40% in the aggregate,
no
financial statements of the acquirees were required to be filed with
the
SEC on Form 8-K in accordance with Rule 310 (c) of Regulation
S-B.
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c.
|
With
respect to Securities Exchange Act of 1934reporting requirements,
we have
filed:
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|
i.
|
Financial
statements in compliance with Rule 310(a) for the twelve months
ended June
30, 2005, the six months ended June 30, 2004 and the period from
September
23, 2003 (inception) to December 31, 2004, reflecting the financial
results of Old NGS.
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ii.
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Financial
statements in compliance with Rule 310(b) for the three months ended
March
31, September 30 and December 31, 2004 and for the three months ended
March 31 and September 30, 2005, reflecting the financial results
of Old
NGS.
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-4-
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d.
|
With
respect to Securities Act of 1933 reporting requirements for Amendment
No.2 to the Registration Statement we are filing on Form SB-2, we
are
providing the following financial
statements:
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|
i.
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The
financial statements provided in accordance with Rule 310(a) above,
representing 21 months of audit coverage since inception of the
oil and
gas operations of Old NGS,
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ii.
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The
audited revenue and direct operating expense statements we filed
under
310(c),
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The
Staff
has concluded that the audited statements of revenue and direct operating
expenses do not fulfill the requirements for reporting in a ’33 Act filing under
310 (a), due to a “predecessor entity” issue. Based on this conclusion, we have
reviewed the missing three months of full audit coverage needed for 24 month
audit coverage suggested by the Staff, and believe it is not meaningful to
an
investor’s understanding of our operations, especially given the dilapidated
condition of the field upon our acquisition as evidenced by the audited
statement of revenues and direct operating expenses of the Delhi Field acquired
on September 23, 2003, included in our Form SB-2. In that report, oil and gas
sales for the period from January 1, 2003 to September 30, 2003 were $148,506,
resulting in net revenue after direct operating expenses of $6,652. For the
preceding nine month period ended December 31, 2002, oil and gas sales were
$64,491, resulting in net revenue after direct operating expenses of $9,289.
Further, additional financial data was not available for the three months prior
to April 1, 2002. As we understand it from our seller, the operator during
that
period abandoned the property to foreclosure.
Based
on
these facts and further discussions with the Staff, we believe the Staff has
agreed that presenting 21 months of full audit coverage through June 30, 2005
would provide sufficient information for purposes of the Registration Statement
on Form SB-2.
Comment
3: Please respond to the disclosure on page 8 regarding the additional payments
(described as penalties) payable under the terms of the private placement
agreement for failure to register the shares and obtain/maintain effectiveness
of a registration statement with the SEC.
Included in this discussion are two topics, taken separately as follows:
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a.
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Did
the potential liability for contingent payments create “temporary
equity”?
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We
found
limited literature to guide us in this area:
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i.
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EITF
05-4 "The Effect of a Liquidated Damages Clause on a Freestanding
Financial Instrument Subject to EITF Issue No. 00-19, ‘Accounting for
Derivative Financial Instruments Indexed to, and Potentially Settled
in, a
Company's Own Stock’" appears to address our specific issue, although as
we understand it, the EITF has tabled this effort until the FASB
provides
additional guidance on the derivative nature of a registration
rights
agreement. We, therefore, find this guidance
inadequate.
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ii.
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EITF
00-19 provides guidance on “Accounting for freestanding contracts that are
indexed to, and potentially settled in, a company's own stock”. To the
extent that our registration rights agreement could be determined
to be a
freestanding derivative, we examined paragraph 16 and determined
that the
8% maximum amount due the purchaser (“Rubicon”) for failure to register
and maintain effectiveness of a registration statement did not
exceed the
difference between the fair value of registered and un-registered
shares.
We came to this conclusion based on knowledge that many PIPE transactions,
with registration rights attached, are commonly priced at a 10-15%
discount to currently registered shares. Since the 8% penalty provision
of
our agreement did not exceed this 10-15% market discount, it is
not
considered a “penalty”. As such, the provisions of EITF 00-19 are not
applicable to this
transaction.
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-5-
Our
review of the applicable literature and historical practice of SEC registrants
does not, in our view, support classification of the proceeds of the common
stock as temporary equity until the shares in question have been registered.
In
analyzing the terms of our agreement, the maximum amount for which we could
be
liable under the terms of our Registration Rights Agreement is $240,000, an
excerpt of which follows:
as
partial relief for the damages to any holder by reason of any such delay in
or
reduction of its ability to sell the underlying Shares of Common Stock (which
remedy shall not be exclusive of any other remedies available at law or in
equity), but subject to the limitation set forth in the last sentence of this
Section 2(f)………………,which
states:
Notwithstanding
the other provisions of this Section 2(f), in
no event shall the Company be liable for damages in excess of
8%
of
the aggregate purchase price paid by the holders of Registrable Securities.
{underline
added}
We
believe that the language above is both more specific and conclusive in
specifying maximum penalties for damages compared to more typical registration
rights agreements that are silent on remedies within the contract, at law or
at
equity.
Subsequent
to the filing of Amendment No. 1 to the Registration Statement on Form SB-2
filed with the Commission, please be advised that we entered into an amended
registration rights agreement with Rubicon dated January 13, 2006, in which
we
agreed to issue 160,000 shares of our common stock to eliminate any amounts
that
may have been or may become due with respect to the 8% penalty provision of
that
agreement. A Form 8-K was filed with the Commission on January 20, 2006
describing this transaction, and including as exhibits the Stock Purchase
Agreement and the Amended and Restated Registration Rights
Agreement.
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b.
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Referring
to our disclosure on page 8 regarding the penalties under the terms
of our
registration rights agreement, we agree with you that a SFAS 5 accrual
would not have been appropriate at June 30, 2005, since it was not
probable at that time that a loss would be incurred.
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-6-
Please
note, however, that at June 30, 2005, we accrued expected registration costs
to
be incurred in connection with the common stock sold to Rubicon, which amount
included $60,000 in penalties we expected to incur in connection with the
underlying registrations rights agreement entered into with Rubicon. These
costs
were charged against the proceeds of the offering, as we viewed them as a refund
of proceeds based on the probability of a contingency event not occurring.
We
understand the Staff does not concur with our treatment of the penalties as
a
reduction of the proceeds of the offering. Furthermore, we understand the Staff
has questioned whether the accrual of the penalties at June 30, 2005 met the
probability requirements of FASB 5 for accrual at that date. It became probable
in accordance with the guidelines of FASB 5 that a penalty would be incurred
during the quarter ended September 30, 2005. The event giving rise to our
conclusion that the penalty became probable was our inability to file the
Registration Statement on Form SB-2 in sufficient time to avoid such penalty.
Given these factors, the accrual in the amount of $60,000 at June 30, 2005
was
not appropriate and $30,000 of expense should have been accrued and charged
to
expense during the quarter ended September 30, 2005. Given that these amounts
are not in our judgment material to our financial statements at either September
30, 2005 or June 30, 2005, we propose that we prospectively make these
corrections in our December 31, 2005 quarter.
Comment
4: Provide all disclosures required by Rule 4-10(c)(7) of Regulation
S-X:
We
have
included the additional disclosures required by Rule 4-10(c)(7) of Regulation
S-X in Amendment No.2.
Comment
5: Please update financial statements as required by Item 310(g) of Regulation
S-B.
Financial
statements and consents required by Item 310(g) of Regulation S-B have been
updated in our filing.
The
following responses were prepared by the Company and reviewed and approved
by W.
D. Von Gonten & Co., the independent reservoir engineer that reported on the
proved reserves of the Company as of January 1, 2004, July 1, 2004 and July
1,
2005.
Comment
7. You
stated that the properties purchased in the Tullos Area were transferred without
normally available well plats, geological maps and well histories, consequently
your development plans were delayed. Please explain, including any technical
data, how you estimated prove reserves for Tullos Area Fields without this
information, particularly the proved nonproducing
reserves.
The
proved reserves assigned to the Tullos Field Area properties by W. D. Von Gonten
& Co. were determined through analysis of historical production rates and
stabilized production declines by lease, available from public records, and
historical lease operating costs that we provided to W. D. Von Gonten & Co.
based on our actual costs to operate the properties historically. They also
obtained, independently, well logs, maps and well histories from Louisiana
state
records to assist in estimating future reserves. The historical decline rate
was
projected forward until economic limit to estimate future production. Less
than
6% of proved developed reserves were assigned to the Tullos offset non-producing
wells, based upon the performance of the immediate offset wells. W. D. Von
Gonten & Co. used allocated lease production, based on historical test data,
to generate individual well production histories to establish production trends
for nonproducing wells to which were assigned proved developed nonproducing
reserves.
-7-
Current
and future development activities by the Company, to develop incremental
unproved
production and reserves (not filed or publicly disclosed) in addition to the
proved
reserves
assigned by W. D. Von Gonten & Co., require additional information that we
had to independently generate post closing. For example, optimization of salt
water collection and disposal, installation of additional salt water disposal
capacity, selection of (other than proved) non-producing wells for
re-completions or restoration of production, and identification of candidate
wells for installation of high volume submersible pumps require exact physical
location of wells, flow lines, roads and tank batteries. This information was
neither necessary nor required for our independent engineer to assign the proved
developed reserves in our July 1, 2005 report.
Comment
8: Please amend the SB-2 to disclose historical product prices before and after
any hedging effects and historical production costs.
Page
17
has been amended to include such information.
Comment
9: Please disclose the number of producing wells at each period
end.
The
numbers of producing wells as of June 30 and September 30, 2005 are
approximately:
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June
30
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September
30
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||||||
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Delhi
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9
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10
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Tullos
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133
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143
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Amendment
No. 2 has been updated to reflect this information.
Comment
10: Please disclose detailed explanation of conditions that led to negative
revisions in fiscal 2004, including but not limited to
208-1.
The
proved reserves as of January 1, 2004 were based on information available
immediately post closing of the purchase of the Delhi Field. Such information
included limited documentation as to mechanical work and log section for the
Delhi Ut. 208-1 well, which indicated that the well had been tested in the
“Z”
Sand Formation shortly after being drilled in 1946 at a rate of approximately
160 bopd with a high gas-oil ratio. Due to the high gas oil ratio, the “Z” Sand
reservoir was bypassed at that time.
We
later
obtained from the seller the full well file in which we found that a previous
operator had conducted some minimal efforts to re-complete the Delhi Ut. 208-1
in the “Z” Sand and found sufficient reservoir damage, or depletion, to prevent
commercial flow. That operator abandoned further efforts to restore production.
Therefore, we and W.D. Von Gonten & Co. believed that the probability of
obtaining the expected reserves, regardless of amount of work expended, fell
below the level required for proved reserves. This revision was the primary
negative revision reflected in the report by W. D. Von Gonten & Co.. The
registration statement has been amended to eliminate reference to any potential
other-than-proved reserves. Other revisions in the July 1, 2004 report by W.
D.
Von Gonten & Co. were:
-8-
Bases
for
revisions:
Fuel
Use Installation
of gas treating facility fueled by lease gas
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178-1
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Well
was shut-in due to high water production rates and subsequently
re-completed into gas producing reservoir post
7/1/04
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178-2
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Well
suffered from mechanical problems at time of July 2004 report, limiting
performance
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183-3
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Performance.
Well subsequently re-completed to add additional producing
reservoir
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184-1
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Performance.
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197-1
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Well
developed sand production problem that limits
rate.
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| 208-1 |
Additional
research into historical records indicated increased risk as to reservoir
damage and prior depletion.
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87-2
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Field
study based on production test, later confirmed by re-completion
as a
producing well.
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123-18
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Field
study
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184-2
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Re-completed
as a gas well prior to 7/1/04
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197-2
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Additional
review of well data
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204-2
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Re-completed
as a gas well prior to 7/1/04
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W.
D. Von
Gonten & Co. specifically notes that the Delhi Field was severely neglected
by the recent previous operators and the field production decline was a result
of both mechanical and reservoir causes, and subsequent operations of the
Company provides useful information for more precise evaluation of remaining
reserves. The initial independent reserve report, absent a full and detailed
field-wide study, only touched upon the full reserves potential of the field,
and assigned approximately 300,000 bbls of oil equivalent to a field with
cumulative production of approximately 240 million bbls of oil equivalent.
Therefore, any change in the current reserves is minuscule compared to the
total
reservoir. Further, the individual wells evaluated were very mature and the
remaining reserves assigned were a small fraction of the ultimate reserves
of
the wells (please see below explanatory table by W. D. Von Gonten &
Co.).
-9-
-10-
Comment
11: Please
provide technical narrative to support addition of eight proved undeveloped
locations, including pertinent production information of relevant offset
wells.
We
engaged Robert A. Olson, a consulting geologist based in Arkansas with prior
experience in the Delhi Field, to conduct a field study of portions of the
Delhi
Field. His work identified numerous potential drilling locations, eight of
which
we showed to W. D. Von Gonten & Co. for evaluation and consideration. Each
location was based on structural interpretation of immediate offset wells
on
strike, down dip and up dip. In general, the offset wells down dip were
productive in the targeted reservoirs, and the on strike and up dip wells
either
were tested in the reservoir, without material production, or demonstrated
conclusive correlations by electric logs. Note that we have successfully
drilled
and completed the first three locations.
The
consent of Mr. Olson has been included as an exhibit to Amendment No.
2.
Delhi
Ut. 92-2 Drilled
in October 2005 and completed as a gas well in the Lane Sand at a rate of
approximately 700 mcfd. Location was drilled as an attic well immediately
up dip
from the Delhi Ut. 87-2 well that produced 1209 MBO and 963 MMCF prior to
being
shut in for high water production, and up dip of and offset from the Delhi
Ut.
86-1 well that produced 146 MBO and 484 MMCF prior to watering out. The location
is down dip from the Delhi Ut. 92-1 that logged five feet of pay sand with
logged resistivity indicative of production, but was not produced following
the
test in 1946 due to projected (undesirable) gas production.
Delhi
Ut. 70-4 Drilled
in November 2005 and completed in the Murphy Sand as an oil well. Location
was
drilled as an attic well immediately up dip of the Delhi Ut. 70-1 (cumulative
production of 863 MBO and 485 MMCF) and the Delhi Ut. 58-2 (cumulative
production of 1110 MBO and 586 MMCF). Up dip control is provided by the Delhi
Ut. 70-3.
Delhi
Ut. 87-3 Drilled
in November 2005 as a replacement well for the down dip Delhi Ut. 87-2 well
(see
above) that is currently completed in the Upper Barrier Sand (mechanical
problems limit current production to 50 bopd). Location was also intended
to
develop the Lower Barrier Sand that is also present in the Ut. 87-2 (see
above)
and successfully flow tested circa 1946. Induction log of the 87-3 defined
the
oil/water contact in the Lane Sand developed in the up dip 92-2 well (see
above)
and defined a quality reservoir in the Lower Barrier, further confirmed by
sonic
log. This well has been completed in the Lower Barrier Sand.
Delhi
Ut. 225-2 (Not
a
PUD) Drilled (spud December 1, 2005) to develop the Barrier Sand. Location
is
380’ offset, and 20’ high, to the Delhi Ut. 225-1 that produced 450 MBO and 390
MMCF. Offset control is provided by the Delhi Ut. 232-2 (offset west by 900’ and
35’ up dip from the drilling location) and the Delhi Ut. 224-1 (offset east by
1100’ and 28’ up dip from the location). Both offset wells establish the
reservoir boundaries as the Barrier Sand appears to be present in both, though
in poor quality and subsequently not produced by the original operator in
1946
(224-1 flow tested oil at low rate, and 232-2 cored oil and flowed gas at
then
noncommercial rate).
Delhi
Ut. 139-2
Scheduled to be drilled in December 2005 to develop the Upper Barrier Sand.
Location is approximately 500’ south and ~15’ down dip of the Delhi Ut. 139-1
well that evidenced a 4-5’ portion of the Upper Barrier Sand truncated against
the Monroe Gas Rock, which is the sealing cap rock for reservoir development
in
the field. The location is ~50’ up dip of the Delhi Ut. 123-24 that cumulatively
produced 1200+ MBO and 700 MMCF. Lateral control is demonstrated by logged
pay
sand pinchouts in the Delhi Ut. 123-21 (cumulative production of 72 MBO)
that is
1250’ to the east of the drilling location and the Delhi Ut. 147-2 (cumulative
production of 5 MBO) that is 900’ to the west of the drilling
location.
Delhi
Ut. 28-3 Scheduled
to be drilled in December 2005 to develop the Lower Lane Sand member of the
Holt
Bryant group of reservoirs. The location is a 250’ offset (10’ up dip) to the
Delhi Ut. 28-1 that logged 15+ feet of high resistivity pay, deemed gas based
on
drill stem test and abandoned circa 1946. Location is 20’ up dip of the Delhi
Ut. 28-2 that logged 18’ of reservoir pay and produced 88 MMCF before mechanical
problems shut in well. Location is further up dip of the Delhi Ut. 34-1,
26-1
and 24-1 wells that cumulatively produced approximately 4000 MBO plus associated
gas.
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Delhi
Ut. 24-4 Scheduled
to be drilled in calendar 2006 to develop the Upper Lane Sand member of the
Holt
Bryant group. Location is ~45’ updip of the Delhi Ut. 26-1 and 24-1 (see above)
and Delhi Ut. 24-2 (cumulative production greater than 1000 MBO). Based on
the
down dip wells watering out at their highest point, the location should be
~25’
up dip of the estimated oil/water contact. Up dip control is established
by the
Delhi Ut. 23-1 that is ~600’ north and 25’ up dip of the drilling
location.
Delhi
Ut. 158-4 Scheduled
to be drilled in calendar 2006 to develop the Lower Barrier as a replacement
well for the Delhi Ut. 158-3, which was shut-in by a previous operator due
to
mechanical problems while producing in the Holt Sand (below the Lower Barrier).
Location is ~35’ up dip to the 158-1, which initially produced 260+ bopd.
Comment
12: Please provide the reserves report prepared by your outside
engineer.
Attached
is the reserve report summary prepared by W. D. Von Gonten & Co. as of July
1, 2005, with reserve estimates and annual cash flows by reserve category.
Although detailed well-by-well reserve estimates and cash flows have not
been
included (we would hope that the summary information provided would be
sufficient for the Staff to complete its review; we also view certain of
this
information as confidential and would prefer not to have it made potentially
publicly available), such detailed information will be provided to the Staff
upon further request.
General
In
addition to effecting the changes discussed above, the Company has made various
other changes and has endeavored to update the information in the Registration
Statement.
Please
direct questions regarding the amended Registration Statement (other than
questions regarding accounting and engineering matters) to the Company’s outside
counsel, Lawrence Schnapp, at 310-789-1255. Questions regarding accounting
and
engineering matters should be addressed to the undersigned, at
713-935-0122.
Sincerely,
Sterling
H. McDonald
Chief
Financial Officer
Enclosures
cc:
Robert S. Herlin
Lawrence
P. Schnapp, Esq.
Steven
D.
Lee, Esq
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