SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
SCHEDULE 13E-3
RULE 13E-3 TRANSACTION STATEMENT
(PURSUANT TO SECTION 13(E) OF THE SECURITIES EXCHANGE ACT OF 1934 AND RULE 13E-3
(SS.240.13E-3) THEREUNDER)
(AMENDMENT NO. 2)
ENEX OIL & GAS INCOME PROGRAM II-1, L.P.
- --------------------------------------------------------------------------------
(NAME OF THE ISSUER)
ENEX RESOURCES CORPORATION
- --------------------------------------------------------------------------------
(NAME OF PERSON(S) FILING PROXY STATEMENT)
$500 "UNITS" OF LIMITED PARTNERSHIP INTERESTS
- --------------------------------------------------------------------------------
(TITLE OF CLASS OF SECURITIES)
- --------------------------------------------------------------------------------
(CUSIP NUMBER OF CLASS OF SECURITIES)
R. E. DENSFORD, VICE PRESIDENT
ENEX RESOURCES CORPORATION
800 ROCKMEAD
THREE KINGWOOD PLACE, SUITE 200
KINGWOOD, TX 77339
(713) 358-8401
- --------------------------------------------------------------------------------
(NAME, ADDRESS AND TELEPHONE NUMBER OF PERSON AUTHORIZED TO RECEIVE NOTICES AND
COMMUNICATIONS ON BEHALF OF PERSON(S) FILING STATEMENT)
THIS STATEMENT IS FILED IN CONNECTION WITH (CHECK THE APPROPRIATE BOX):
A. [x] THE FILING OF SOLICITATION MATERIALS OR AN INFORMATION STATEMENT
SUBJECT TO REGULATION 14A[17 CFR 240.14A-1 TO 240.14B-1].
REGULATION 14C[17 CFR 240.14C-1 TO 240.14C-101] OR RULE 13E-3(C)
[SS.240.13E- 3(C)] UNDER THE SECURITIES EXCHANGE ACT OF 1934.
[AMENDED IN RELEASE NO.34-23789 (P.84,044), EFFECTIVE JANUARY 20,
1987,51 F.R.42048.]
B. O THE FILING OF A REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF
1933.
C. O A TENDER OFFER.
D. O NONE OF THE ABOVE. CHECK THE FOLLOWING BOX IF THE SOLICITING
MATERIALS OR INFORMATION STATEMENT REFERRED TO IN CHECKING
BOX (A) ARE PRELIMINARY COPIES:
CALCULATION OF FILING FEE
TRANSACTION VALUATION:
THE MAXIMUM AGGREGATE VALUE OF THE TRANSACTION AMOUNT OF FILING FEE:
IS $330,150 (PARTNERSHIP INDEBTEDNESS, WHICH EXCEEDS $67.00
ESTIMATED FAIR MARKET VALUE OF PARTNERSHIP ASSETS TO
BE SOLD IN LIQUIDATION PURSUANT TO PLAN OF DISSOLUTION)
[x] CHECK BOX IF ANY PART OF THE FEE IS OFFSET AS PROVIDED BY RULE
0-11(A)(2) AND IDENTIFY THE FILING WITH WHICH THE OFFSETTING FEE WAS
PREVIOUSLY PAID. IDENTIFY THE PREVIOUS FILING BY REGISTRATION STATEMENT
NUMBER, OR THE FORM OR SCHEDULE AND THE DATE OF ITS FILING.
AMOUNT PREVIOUSLY PAID: $67.00
FORM OR REGISTRATION NO.: SCHEDULE 14A
FILING PARTY: ENEX RESOURCES CORPORATION
DATE FILED: OCTOBER 31, 1995
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
SCHEDULE 13E-3
RULE 13E-3 TRANSACTION STATEMENT
(PURSUANT TO SECTION 13(E) OF THE SECURITIES EXCHANGE ACT OF 1934 AND RULE 13E-3
(SS.240.13E-3) THEREUNDER)
(AMENDMENT NO. 2)
ENEX OIL & GAS INCOME PROGRAM II-2, L.P.
- --------------------------------------------------------------------------------
(NAME OF THE ISSUER)
ENEX RESOURCES CORPORATION
- --------------------------------------------------------------------------------
(NAME OF PERSON(S) FILING PROXY STATEMENT)
$500 "UNITS" OF LIMITED PARTNERSHIP INTERESTS
- --------------------------------------------------------------------------------
(TITLE OF CLASS OF SECURITIES)
- --------------------------------------------------------------------------------
(CUSIP NUMBER OF CLASS OF SECURITIES)
R. E. DENSFORD, VICE PRESIDENT
ENEX RESOURCES CORPORATION
800 ROCKMEAD
THREE KINGWOOD PLACE, SUITE 200
KINGWOOD, TX 77339
(713) 358-8401
- --------------------------------------------------------------------------------
(NAME, ADDRESS AND TELEPHONE NUMBER OF PERSON AUTHORIZED TO RECEIVE NOTICES AND
COMMUNICATIONS ON BEHALF OF PERSON(S) FILING STATEMENT)
THIS STATEMENT IS FILED IN CONNECTION WITH (CHECK THE APPROPRIATE BOX):
A. [x] THE FILING OF SOLICITATION MATERIALS OR AN INFORMATION STATEMENT
SUBJECT TO REGULATION 14A[17 CFR 240.14A-1 TO 240.14B-1].
REGULATION 14C[17 CFR 240.14C-1 TO 240.14C-101] OR RULE 13E-3(C)
[SS.240.13E- 3(C)] UNDER THE SECURITIES EXCHANGE ACT OF 1934.
[AMENDED IN RELEASE NO.34-23789 (P.84,044), EFFECTIVE JANUARY 20,
1987,51 F.R.42048.]
B. O THE FILING OF A REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF
1933.
C. O A TENDER OFFER.
D. O NONE OF THE ABOVE. CHECK THE FOLLOWING BOX IF THE SOLICITING
MATERIALS OR INFORMATION STATEMENT REFERRED TO IN CHECKING
BOX (A) ARE PRELIMINARY COPIES:
CALCULATION OF FILING FEE
TRANSACTION VALUATION:
THE MAXIMUM AGGREGATE VALUE OF THE TRANSACTION AMOUNT OF FILING FEE:
IS $275,946 (PARTNERSHIP INDEBTEDNESS, WHICH EXCEEDS $56.00
ESTIMATED FAIR MARKET VALUE OF PARTNERSHIP ASSETS TO
BE SOLD IN LIQUIDATION PURSUANT TO PLAN OF DISSOLUTION)
[x] CHECK BOX IF ANY PART OF THE FEE IS OFFSET AS PROVIDED BY RULE
0-11(A)(2) AND IDENTIFY THE FILING WITH WHICH THE OFFSETTING FEE WAS
PREVIOUSLY PAID. IDENTIFY THE PREVIOUS FILING BY REGISTRATION STATEMENT
NUMBER, OR THE FORM OR SCHEDULE AND THE DATE OF ITS FILING.
AMOUNT PREVIOUSLY PAID: $56.00
FORM OR REGISTRATION NO.: SCHEDULE 14A
FILING PARTY: ENEX RESOURCES CORPORATION
DATE FILED: OCTOBER 31, 1995
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
SCHEDULE 13E-3
RULE 13E-3 TRANSACTION STATEMENT
(PURSUANT TO SECTION 13(E) OF THE SECURITIES EXCHANGE ACT OF 1934 AND RULE 13E-3
(SS.240.13E-3) THEREUNDER)
(AMENDMENT NO. 2)
ENEX OIL & GAS INCOME PROGRAM II-3, L.P.
- --------------------------------------------------------------------------------
(NAME OF THE ISSUER)
ENEX RESOURCES CORPORATION
- --------------------------------------------------------------------------------
(NAME OF PERSON(S) FILING PROXY STATEMENT)
$500 "UNITS" OF LIMITED PARTNERSHIP INTERESTS
- --------------------------------------------------------------------------------
(TITLE OF CLASS OF SECURITIES)
- --------------------------------------------------------------------------------
(CUSIP NUMBER OF CLASS OF SECURITIES)
R. E. DENSFORD, VICE PRESIDENT
ENEX RESOURCES CORPORATION
800 ROCKMEAD
THREE KINGWOOD PLACE, SUITE 200
KINGWOOD, TX 77339
(713) 358-8401
- --------------------------------------------------------------------------------
(NAME, ADDRESS AND TELEPHONE NUMBER OF PERSON AUTHORIZED TO RECEIVE NOTICES AND
COMMUNICATIONS ON BEHALF OF PERSON(S) FILING STATEMENT)
THIS STATEMENT IS FILED IN CONNECTION WITH (CHECK THE APPROPRIATE BOX):
A. [x] THE FILING OF SOLICITATION MATERIALS OR AN INFORMATION STATEMENT
SUBJECT TO REGULATION 14A[17 CFR 240.14A-1 TO 240.14B-1].
REGULATION 14C[17 CFR 240.14C-1 TO 240.14C-101] OR RULE 13E-3(C)
[SS.240.13E- 3(C)] UNDER THE SECURITIES EXCHANGE ACT OF 1934.
[AMENDED IN RELEASE NO.34-23789 (P.84,044), EFFECTIVE JANUARY 20,
1987,51 F.R.42048.]
B. O THE FILING OF A REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF
1933.
C. O A TENDER OFFER.
D. O NONE OF THE ABOVE. CHECK THE FOLLOWING BOX IF THE SOLICITING
MATERIALS OR INFORMATION STATEMENT REFERRED TO IN CHECKING
BOX (A) ARE PRELIMINARY COPIES:
CALCULATION OF FILING FEE
TRANSACTION VALUATION:
THE MAXIMUM AGGREGATE VALUE OF THE TRANSACTION AMOUNT OF FILING FEE:
IS $234,382 (PARTNERSHIP INDEBTEDNESS, WHICH EXCEEDS $47.00
ESTIMATED FAIR MARKET VALUE OF PARTNERSHIP ASSETS TO
BE SOLD IN LIQUIDATION PURSUANT TO PLAN OF DISSOLUTION)
CHECK BOX IF ANY PART OF THE FEE IS OFFSET AS PROVIDED BY RULE
0-11(A)(2) AND IDENTIFY THE FILING WITH WHICH THE OFFSETTING FEE WAS
PREVIOUSLY PAID. IDENTIFY THE PREVIOUS FILING BY REGISTRATION STATEMENT
NUMBER, OR THE FORM OR SCHEDULE AND THE DATE OF ITS FILING.
AMOUNT PREVIOUSLY PAID: $47.00
FORM OR REGISTRATION NO.: SCHEDULE 14A
FILING PARTY: ENEX RESOURCES CORPORATION
DATE FILED: OCTOBER 31, 1995
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
SCHEDULE 13E-3
RULE 13E-3 TRANSACTION STATEMENT
(PURSUANT TO SECTION 13(E) OF THE SECURITIES EXCHANGE ACT OF 1934 AND RULE 13E-3
(SS.240.13E-3) THEREUNDER)
(AMENDMENT NO. 2)
ENEX OIL & GAS INCOME PROGRAM II-4, L.P.
- --------------------------------------------------------------------------------
(NAME OF THE ISSUER)
ENEX RESOURCES CORPORATION
- --------------------------------------------------------------------------------
(NAME OF PERSON(S) FILING PROXY STATEMENT)
$500 "UNITS" OF LIMITED PARTNERSHIP INTERESTS
- --------------------------------------------------------------------------------
(TITLE OF CLASS OF SECURITIES)
- --------------------------------------------------------------------------------
(CUSIP NUMBER OF CLASS OF SECURITIES)
R. E. DENSFORD, VICE PRESIDENT
ENEX RESOURCES CORPORATION
800 ROCKMEAD
THREE KINGWOOD PLACE, SUITE 200
KINGWOOD, TX 77339
(713) 358-8401
- --------------------------------------------------------------------------------
(NAME, ADDRESS AND TELEPHONE NUMBER OF PERSON AUTHORIZED TO RECEIVE NOTICES AND
COMMUNICATIONS ON BEHALF OF PERSON(S) FILING STATEMENT)
THIS STATEMENT IS FILED IN CONNECTION WITH (CHECK THE APPROPRIATE BOX):
A. [x] THE FILING OF SOLICITATION MATERIALS OR AN INFORMATION STATEMENT
SUBJECT TO REGULATION 14A[17 CFR 240.14A-1 TO 240.14B-1].
REGULATION 14C[17 CFR 240.14C-1 TO 240.14C-101] OR RULE 13E-3(C)
[SS.240.13E- 3(C)] UNDER THE SECURITIES EXCHANGE ACT OF 1934.
[AMENDED IN RELEASE NO.34-23789 (P.84,044), EFFECTIVE JANUARY 20,
1987,51 F.R.42048.]
B. O THE FILING OF A REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF
1933.
C. O A TENDER OFFER.
D. O NONE OF THE ABOVE. CHECK THE FOLLOWING BOX IF THE SOLICITING
MATERIALS OR INFORMATION STATEMENT REFERRED TO IN CHECKING
BOX (A) ARE PRELIMINARY COPIES:
CALCULATION OF FILING FEE
TRANSACTION VALUATION:
THE MAXIMUM AGGREGATE VALUE OF THE TRANSACTION AMOUNT OF FILING FEE:
IS $259,856 (PARTNERSHIP INDEBTEDNESS, WHICH EXCEEDS $52.00
ESTIMATED FAIR MARKET VALUE OF PARTNERSHIP ASSETS TO
BE SOLD IN LIQUIDATION PURSUANT TO PLAN OF DISSOLUTION)
CHECK BOX IF ANY PART OF THE FEE IS OFFSET AS PROVIDED BY RULE
0-11(A)(2) AND IDENTIFY THE FILING WITH WHICH THE OFFSETTING FEE WAS
PREVIOUSLY PAID. IDENTIFY THE PREVIOUS FILING BY REGISTRATION STATEMENT
NUMBER, OR THE FORM OR SCHEDULE AND THE DATE OF ITS FILING.
AMOUNT PREVIOUSLY PAID: $52.00
FORM OR REGISTRATION NO.: SCHEDULE 14A
FILING PARTY: ENEX RESOURCES CORPORATION
DATE FILED: OCTOBER 31, 1995
<PAGE>
Item 17. Material to be Filed as Exhibits
(a) Not applicable
(b) Revised fair market valuation reports prepared by Gruy are filed
herewith as Exhibit 1.
(c) Not applicable.
(d) Not applicable.
(e) Not applicable.
(f) Not applicable.
Enex Resources Corporation -1- November 16, 1995
November 16, 1995
Enex Resources Corporation
Three Kingwood Place, Suite 200
Kingwood, Texas 77339
Enex Oil & Gas Income Program II
Series 1, LP
95-002-106
Gentlemen:
At your request, we have estimated the fair market value as of July 1, 1995 for
certain interests owned by the limited partners in Enex Oil & Gas Income Program
II, Series 1, LP (Enex). The estimated fair market value is summarized by
acquisition for this partnership as follows:
Estimated
Acquisition Fair Market Value
E. Seven Sisters $ 203,825
Comite A $ 53,500
NW Esperance Point 'B&C' $ 2,364
Steamboat $ 0
TOTAL $ 259,689
The fair market value was estimated using the income approach as opposed to the
market data approach because it is difficult to identify sales of oil and gas
properties that are comparable in net reserves, product prices, location,
operating expenses, and operator expertise. For the proved producing properties,
the discounted future net revenue is reduced to a fair market value by
multiplying by a suitable fraction that accounts for the risk associated with an
investment. For proved developed non-producing and proved undeveloped reserves,
the present value of the required capital is added to the discounted future net
revenue, a suitable risk factor is applied, and the present value of the capital
is subtracted from that value. This approach assumes that the capital is
invested with certainty and the resulting cash flow stream is burdened with the
uncertainty. In all cases, the payout time and the internal rate-of-return for
each fair market value estimate is computed and compared with that which a
rational investor would expect.
<PAGE>
<PAGE>
Enex Resources Corporation -2- December 6, 1995
The estimated discounted future net revenue is that revenue which will be
realized from the sale of the estimated net reserves after deduction of
royalties, ad valorem and production taxes, direct operating costs and capital
expenditures, when applicable and then discounted at 10 percent using mid-year
discounting. Surface and well equipment salvage values and well plugging and
field abandonment costs have been considered in the revenue projections, when
applicable. Future net revenue as stated in this report is before the deduction
of federal income tax.
The following parameters are incorporated in the economic projections of the
report. Market prices received by Enex from third party purchasers in June, 1995
are held constant in 1995 at $17.25 per barrel of oil for Louisiana and $17.00
per barrel for all other states, then escalated per Table 1 to a maximum price
of $30.69 per barrel. June 1995 gas prices varied by area and BTU content and
remained flat through 1995, then escalated per Table 1 to a maximum price of
$3.80 per MMBTU. Operating and capital costs are escalated at an annual rate of
3 percent until the primary product reaches its maximum price. The actual prices
that will be received and the associated costs may be more or less than those
projected.
Extent and character of ownership, oil and gas prices, production data, capital
expenditure estimates were provided by Enex and verified as follows: extent of
ownership by reference to third party division orders, assignments, bills of
sale and conveyance and stipulation of interest in our files, oil and gas prices
by reference to information accompanying checks received as Enex's share of the
proceeds of production from the oil and gas interests that are the subject of
this report and posted price bulletins issued by purchasers of Enex's
production. Price escalation rates were derived from published industry
guidelines and are a composite of a published survey of rates used by energy
lending institutions and operators of oil and gas properties. Production data
were obtained from independent commercial data sources and direct operating
costs were obtained by references to joint interest billings issued by the third
party operators of Enex's oil and gas interests. Capital expenditures were
extracted from AFE's (authorization for expenditure). No independent well tests,
property inspections or audits of operating expenses were conducted by our staff
in conjunction with this study but were reviewed for reasonableness. We did not
verify or determine the extent, character, obligations, status or liabilities,
if any, arising from any current or possible future environmental liabilities
that might be applicable.
In order to estimate the fair market value shown in this report, we have relied
in part on geological, engineering and economic data furnished by Enex, such as
well logs and core analyses provided to Enex by the third party operators of
Enex's oil and gas interests, and other data available from state records and
commercial log libraries. Income may be subject to regulation and contract
provisions and may fluctuate according to market demand or other factors beyond
the control of the operator.
<PAGE>
Enex Resources Corporation -3- December 6, 1995
We are unrelated to Enex and we have no interest in the properties included in
this report. In particular:
1. We do not own a financial interest in Enex or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other
relationship with Enex that would affect our independence.
4. We have verified and corroborated through sources unaffiliated
with Enex all information provided by Enex and used by us in
estimating the fair market value shown above.
5. No instructions were given and no limitations were imposed by
Enex on the scope or methodology to be used by us in preparing
such estimates; we did not accept or incorporate any assumptions
from Enex, but merely called upon Enex to the extent customary
in the oil and gas industry to gather and provide certain
background information which we determined to be relevant and
appropriate, we determined what information to use, and how and
to what extent such information should be relied upon, in
estimating the fair market values shown above.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.
Any distribution or publication of this report or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
Marilyn Wilson, P.E.
Executive Vice President
<PAGE>
Enex Resources Corporation -4- December 6, 1995
James H. Hartsock, P.E.
Executive Vice President
Sylvia Castilleja
Reservoir Engineer
MW:JHH:SC:llb
Attachments
B:\PAGES2&3.INS
<PAGE>
Enex Resources Corporation -5- December 6, 1995
TABLE 1
OIL AND GAS ESCALATIONS
Oil Escalations Gas Escalations
% %
1996 5.2 7.2
1997 5.0 7.3
1998 4.3 4.2
1999 3.2 3.0
Thereafter 3.3 3.0
<PAGE>
November 16, 1995
Enex Resources Corporation
Three Kingwood Place, Suite 200
Kingwood, Texas 77339
Enex Oil & Gas Income Program II
Series 2, LP
95-002-106
Gentlemen:
At your request, we have estimated the fair market value as of July 1, 1995 for
certain interests owned by the limited partners in Enex Oil & Gas Income Program
II, Series 2, LP (Enex). The estimated fair market value is summarized by
acquisition for this partnership as follows:
Estimated
Acquisition Fair Market Value
E. Seven Sisters $ 212,350
Comite A $ 13,910
Steamboat $ 0
TOTAL $ 226,260
The fair market value was estimated using the income approach as opposed to the
market data approach because it is difficult to identify sales of oil and gas
properties that are comparable in net reserves, product prices, location,
operating expenses, and operator expertise. For the proved producing properties,
the discounted future net revenue is reduced to a fair market value by
multiplying by a suitable fraction that accounts for the risk associated with an
investment. For proved developed non-producing and proved undeveloped reserves,
the present value of the required capital is added to the discounted future net
revenue, a suitable risk factor is applied, and the present value of the capital
is subtracted from that value. This approach assumes that the capital is
invested with certainty and the resulting cash flow stream is burdened with the
uncertainty. In all cases, the payout time and the internal rate-of-return for
each fair market value estimate is computed and compared with that which a
rational investor would expect.
<PAGE>
<PAGE>
Enex Resources Corporation -2- December 6, 1995
The estimated discounted future net revenue is that revenue which will be
realized from the sale of the estimated net reserves after deduction of
royalties, ad valorem and production taxes, direct operating costs and capital
expenditures, when applicable and then discounted at 10 percent using mid-year
discounting. Surface and well equipment salvage values and well plugging and
field abandonment costs have been considered in the revenue projections, when
applicable. Future net revenue as stated in this report is before the deduction
of federal income tax.
The following parameters are incorporated in the economic projections of the
report. Market prices received by Enex from third party purchasers in June, 1995
are held constant in 1995 at $17.25 per barrel of oil for Louisiana and $17.00
per barrel for all other states, then escalated per Table 1 to a maximum price
of $30.69 per barrel. June 1995 gas prices varied by area and BTU content and
remained flat through 1995, then escalated per Table 1 to a maximum price of
$3.80 per MMBTU. Operating and capital costs are escalated at an annual rate of
3 percent until the primary product reaches its maximum price. The actual prices
that will be received and the associated costs may be more or less than those
projected.
Extent and character of ownership, oil and gas prices, production data, capital
expenditure estimates were provided by Enex and verified as follows: extent of
ownership by reference to third party division orders, assignments, bills of
sale and conveyance and stipulation of interest in our files, oil and gas prices
by reference to information accompanying checks received as Enex's share of the
proceeds of production from the oil and gas interests that are the subject of
this report and posted price bulletins issued by purchasers of Enex's
production. Price escalation rates were derived from published industry
guidelines and are a composite of a published survey of rates used by energy
lending institutions and operators of oil and gas properties. Production data
were obtained from independent commercial data sources and direct operating
costs were obtained by references to joint interest billings issued by the third
party operators of Enex's oil and gas interests. Capital expenditures were
extracted from AFE's (authorization for expenditure). No independent well tests,
property inspections or audits of operating expenses were conducted by our staff
in conjunction with this study but were reviewed for reasonableness. We did not
verify or determine the extent, character, obligations, status or liabilities,
if any, arising from any current or possible future environmental liabilities
that might be applicable.
In order to estimate the fair market value shown in this report, we have relied
in part on geological, engineering and economic data furnished by Enex, such as
well logs and core analyses provided to Enex by the third party operators of
Enex's oil and gas interests, and other data available from state records and
commercial log libraries. Income may be subject to regulation and contract
provisions and may fluctuate according to market demand or other factors beyond
the control of the operator.
<PAGE>
Enex Resources Corporation -3- December 6, 1995
We are unrelated to Enex and we have no interest in the properties included in
this report. In particular:
1. We do not own a financial interest in Enex or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other
relationship with Enex that would affect our independence.
4. We have verified and corroborated through sources unaffiliated
with Enex all information provided by Enex and used by us in
estimating the fair market value shown above.
5. No instructions were given and no limitations were imposed by
Enex on the scope or methodology to be used by us in preparing
such estimates; we did not accept or incorporate any assumptions
from Enex, but merely called upon Enex to the extent customary
in the oil and gas industry to gather and provide certain
background information which we determined to be relevant and
appropriate, we determined what information to use, and how and
to what extent such information should be relied upon, in
estimating the fair market values shown above.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.
Any distribution or publication of this report or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
Marilyn Wilson, P.E.
Executive Vice President
<PAGE>
Enex Resources Corporation -4- December 6, 1995
James H. Hartsock, P.E.
Executive Vice President
Sylvia Castilleja
Reservoir Engineer
MW:JHH:SC:llb
Attachments
B:\PAGES2&3.INS
<PAGE>
Enex Resources Corporation -5- December 6, 1995
TABLE 1
OIL AND GAS ESCALATIONS
Oil Escalations Gas Escalations
% %
1996 5.2 7.2
1997 5.0 7.3
1998 4.3 4.2
1999 3.2 3.0
Thereafter 3.3 3.0
<PAGE>
November 16, 1995
Enex Resources Corporation
Three Kingwood Place, Suite 200
Kingwood, Texas 77339
Enex Oil & Gas Income Program II
Series 3, LP
95-002-106
Gentlemen:
At your request, we have estimated the fair market value as of July 1, 1995 for
certain interests owned by the limited partners in Enex Oil & Gas Income Program
II, Series 3, LP (Enex). The estimated fair market value is summarized by
acquisition for this partnership as follows:
Estimated
Acquisition Fair Market Value
E. Seven Sisters $ 133,610
Comite A $ 12,840
Steamboat $ 0
Newport $ 24,600
Blair $ 8,200
Hanson $ 28,140
TOTAL $ 207,390
The fair market value was estimated using the income approach as opposed to the
market data approach because it is difficult to identify sales of oil and gas
properties that are comparable in net reserves, product prices, location,
operating expenses, and operator expertise. For the proved producing properties,
the discounted future net revenue is reduced to a fair market value by
multiplying by a suitable fraction that accounts for the risk associated with an
investment. For proved developed non-producing and proved undeveloped reserves,
the present value of the required capital is added to the discounted future net
revenue, a suitable risk factor is applied, and the present value of the capital
is subtracted from that value. This approach assumes that the capital is
invested with certainty and the resulting cash flow stream is burdened with the
uncertainty. In all cases, the payout time and the internal rate-of-return for
each fair market value estimate is computed and compared with that which a
rational investor would expect.
<PAGE>
<PAGE>
Enex Resources Corporation -2- December 6, 1995
The estimated discounted future net revenue is that revenue which will be
realized from the sale of the estimated net reserves after deduction of
royalties, ad valorem and production taxes, direct operating costs and capital
expenditures, when applicable and then discounted at 10 percent using mid-year
discounting. Surface and well equipment salvage values and well plugging and
field abandonment costs have been considered in the revenue projections, when
applicable. Future net revenue as stated in this report is before the deduction
of federal income tax.
The following parameters are incorporated in the economic projections of the
report. Market prices received by Enex from third party purchasers in June, 1995
are held constant in 1995 at $17.25 per barrel of oil for Louisiana and $17.00
per barrel for all other states, then escalated per Table 1 to a maximum price
of $30.69 per barrel. June 1995 gas prices varied by area and BTU content and
remained flat through 1995, then escalated per Table 1 to a maximum price of
$3.80 per MMBTU. Operating and capital costs are escalated at an annual rate of
3 percent until the primary product reaches its maximum price. The actual prices
that will be received and the associated costs may be more or less than those
projected.
Extent and character of ownership, oil and gas prices, production data, capital
expenditure estimates were provided by Enex and verified as follows: extent of
ownership by reference to third party division orders, assignments, bills of
sale and conveyance and stipulation of interest in our files, oil and gas prices
by reference to information accompanying checks received as Enex's share of the
proceeds of production from the oil and gas interests that are the subject of
this report and posted price bulletins issued by purchasers of Enex's
production. Price escalation rates were derived from published industry
guidelines and are a composite of a published survey of rates used by energy
lending institutions and operators of oil and gas properties. Production data
were obtained from independent commercial data sources and direct operating
costs were obtained by references to joint interest billings issued by the third
party operators of Enex's oil and gas interests. Capital expenditures were
extracted from AFE's (authorization for expenditure). No independent well tests,
property inspections or audits of operating expenses were conducted by our staff
in conjunction with this study but were reviewed for reasonableness. We did not
verify or determine the extent, character, obligations, status or liabilities,
if any, arising from any current or possible future environmental liabilities
that might be applicable.
In order to estimate the fair market value shown in this report, we have relied
in part on geological, engineering and economic data furnished by Enex, such as
well logs and core analyses provided to Enex by the third party operators of
Enex's oil and gas interests, and other data available from state records and
commercial log libraries. Income may be subject to regulation and contract
provisions and may fluctuate according to market demand or other factors beyond
the control of the operator.
<PAGE>
Enex Resources Corporation -3- December 6, 1995
We are unrelated to Enex and we have no interest in the properties included in
this report. In particular:
1. We do not own a financial interest in Enex or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other
relationship with Enex that would affect our independence.
4. We have verified and corroborated through sources unaffiliated
with Enex all information provided by Enex and used by us in
estimating the fair market value shown above.
5. No instructions were given and no limitations were imposed by
Enex on the scope or methodology to be used by us in preparing
such estimates; we did not accept or incorporate any assumptions
from Enex, but merely called upon Enex to the extent customary
in the oil and gas industry to gather and provide certain
background information which we determined to be relevant and
appropriate, we determined what information to use, and how and
to what extent such information should be relied upon, in
estimating the fair market values shown above.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.
Any distribution or publication of this report or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
Marilyn Wilson, P.E.
Executive Vice President
<PAGE>
Enex Resources Corporation -4- December 6, 1995
James H. Hartsock, P.E.
Executive Vice President
Sylvia Castilleja
Reservoir Engineer
MW:JHH:SC:llb
Attachments
B:\PAGES2&3.INS
<PAGE>
Enex Resources Corporation -5- December 6, 1995
TABLE 1
OIL AND GAS ESCALATIONS
Oil Escalations Gas Escalations
% %
1996 5.2 7.2
1997 5.0 7.3
1998 4.3 4.2
1999 3.2 3.0
Thereafter 3.3 3.0
<PAGE>
November 16, 1995
Enex Resources Corporation
Three Kingwood Place, Suite 200
Kingwood, Texas 77339
Enex Oil & Gas Income Program II
Series 4, LP
95-002-106
Gentlemen:
At your request, we have estimated the fair market value as of July 1, 1995 for
certain interests owned by the limited partners in Enex Oil & Gas Income Program
II, Series 4, LP (Enex). The estimated fair market value is summarized by
acquisition for this partnership as follows:
Estimated
Acquisition Fair Market Value
E. Seven Sisters $ 110,360
Comite A $ 9,630
Steamboat $ 0
Newport $ 24,600
Blair $ 10,250
Hanson $ 26,264
TOTAL $ 181,104
The fair market value was estimated using the income approach as opposed to the
market data approach because it is difficult to identify sales of oil and gas
properties that are comparable in net reserves, product prices, location,
operating expenses, and operator expertise. For the proved producing properties,
the discounted future net revenue is reduced to a fair market value by
multiplying by a suitable fraction that accounts for the risk associated with an
investment. For proved developed non-producing and proved undeveloped reserves,
the present value of the required capital is added to the discounted future net
revenue, a suitable risk factor is applied, and the present value of the capital
is subtracted from that value. This approach assumes that the capital is
invested with certainty and the resulting cash flow stream is burdened with the
uncertainty. In all cases, the payout time and the internal rate-of-return for
each fair market value estimate is computed and compared with that which a
rational investor would expect.
<PAGE>
<PAGE>
Enex Resources Corporation -2- December 6, 1995
The estimated discounted future net revenue is that revenue which will be
realized from the sale of the estimated net reserves after deduction of
royalties, ad valorem and production taxes, direct operating costs and capital
expenditures, when applicable and then discounted at 10 percent using mid-year
discounting. Surface and well equipment salvage values and well plugging and
field abandonment costs have been considered in the revenue projections, when
applicable. Future net revenue as stated in this report is before the deduction
of federal income tax.
The following parameters are incorporated in the economic projections of the
report. Market prices received by Enex from third party purchasers in June, 1995
are held constant in 1995 at $17.25 per barrel of oil for Louisiana and $17.00
per barrel for all other states, then escalated per Table 1 to a maximum price
of $30.69 per barrel. June 1995 gas prices varied by area and BTU content and
remained flat through 1995, then escalated per Table 1 to a maximum price of
$3.80 per MMBTU. Operating and capital costs are escalated at an annual rate of
3 percent until the primary product reaches its maximum price. The actual prices
that will be received and the associated costs may be more or less than those
projected.
Extent and character of ownership, oil and gas prices, production data, capital
expenditure estimates were provided by Enex and verified as follows: extent of
ownership by reference to third party division orders, assignments, bills of
sale and conveyance and stipulation of interest in our files, oil and gas prices
by reference to information accompanying checks received as Enex's share of the
proceeds of production from the oil and gas interests that are the subject of
this report and posted price bulletins issued by purchasers of Enex's
production. Price escalation rates were derived from published industry
guidelines and are a composite of a published survey of rates used by energy
lending institutions and operators of oil and gas properties. Production data
were obtained from independent commercial data sources and direct operating
costs were obtained by references to joint interest billings issued by the third
party operators of Enex's oil and gas interests. Capital expenditures were
extracted from AFE's (authorization for expenditure). No independent well tests,
property inspections or audits of operating expenses were conducted by our staff
in conjunction with this study but were reviewed for reasonableness. We did not
verify or determine the extent, character, obligations, status or liabilities,
if any, arising from any current or possible future environmental liabilities
that might be applicable.
In order to estimate the fair market value shown in this report, we have relied
in part on geological, engineering and economic data furnished by Enex, such as
well logs and core analyses provided to Enex by the third party operators of
Enex's oil and gas interests, and other data available from state records and
commercial log libraries. Income may be subject to regulation and contract
provisions and may fluctuate according to market demand or other factors beyond
the control of the operator.
<PAGE>
Enex Resources Corporation -3- December 6, 1995
We are unrelated to Enex and we have no interest in the properties included in
this report. In particular:
1. We do not own a financial interest in Enex or its oil and gas
properties.
2. Our fee is not contingent on the outcome of our work or report.
3. We have not performed other services for or have any other
relationship with Enex that would affect our independence.
4. We have verified and corroborated through sources unaffiliated
with Enex all information provided by Enex and used by us in
estimating the fair market value shown above.
5. No instructions were given and no limitations were imposed by
Enex on the scope or methodology to be used by us in preparing
such estimates; we did not accept or incorporate any assumptions
from Enex, but merely called upon Enex to the extent customary
in the oil and gas industry to gather and provide certain
background information which we determined to be relevant and
appropriate, we determined what information to use, and how and
to what extent such information should be relied upon, in
estimating the fair market values shown above.
If investments or business decisions are to be made in reliance on these
estimates by anyone other than our client, such person with the approval of our
client is invited to visit our offices at his expense so that he can evaluate
the assumptions made and the completeness and extent of the data available on
which our estimates are based.
Any distribution or publication of this report or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
Marilyn Wilson, P.E.
Executive Vice President
<PAGE>
Enex Resources Corporation -4- December 6, 1995
James H. Hartsock, P.E.
Executive Vice President
Sylvia Castilleja
Reservoir Engineer
MW:JHH:SC:llb
Attachments
B:\PAGES2&3.INS
<PAGE>
Enex Resources Corporation -5- December 6, 1995
TABLE 1
OIL AND GAS ESCALATIONS
Oil Escalations Gas Escalations
% %
1996 5.2 7.2
1997 5.0 7.3
1998 4.3 4.2
1999 3.2 3.0
Thereafter 3.3 3.0
<PAGE>
ATTACHMENT 1
<PAGE>
ATTACHMENT 1
DEFINITIONS FOR OIL AND GAS RESERVES 1
RESERVES
Reserves are estimated volumes of crude oil, condensate, natural gas, natural
gas liquids, and associated substances anticipated to be commercially
recoverable from known accumulations from a given date forward, under existing
economic conditions, by established operating practices, and under current
government regulations. Reserve estimates are based on interpretation of
geologic and/or engineering data available at the time of the estimate.
Reserve estimates generally will be revised as reservoirs are produced, as
additional geologic and/or engineering data become available, or as economic
conditions change.
Reserves do not include volumes of crude oil, condensate, natural gas, or
natural gas liquids being held in inventory. If required for financial
reporting or other special purposes, reserves may be reduced for on-site usage
and/or processing losses.
The ownership status of reserves may change due to the expiration of a pro-
duction license or contract; when relevant to reserve assignment such changes
should be identified for each reserve classification.
Reserves may be attributed to either natural reservoir energy, or improved
recovery methods. Improved recovery includes all methods for supplementing
natural reservoir energy to increase ultimate recovery from a reservoir. Such
methods include (1) pressure maintenance, (2) cycling, (3) waterflooding, (4)
thermal methods, (5) chemical flooding, and (6) the use of miscible and immis-
cible displacement fluids.
All reserves estimated involve some degree of uncertainty, depending chiefly on
the amount and reliability of geologic and engineering data available at the
time of the estimate and the interpretation fo these data. The relative degree
of uncertainty may be conveyed by placing reserves in one of two classifica-
tions, either proved or unproved. Unproved reserves are less certain to be re-
covered than proved reserves and may be subclassified as probable or possible to
denote progressively increasing uncertainty.
PROVED RESERVES
Proved reserves can be estimated with reasonable certainty to be recoverable
under current economic conditions. Current economic conditions include prices
and costs prevailing at the time of the estimate. Proved reserves may be devel-
oped or undeveloped.
- --------------------
1 Approved by the Board of Directors, Society of Petroleum Engineers, Inc. and
the Board of Directors of the Society of Petroleum Evaluation Engineers in 1987.
<PAGE>
In general, reserves are considered proved if commercial producibility of the
reservoir is supported by actual production or formation tests. The term proved
refers to the estimated volume of reserves and not just to the productivity of
the well or reservoir. In certain instances, proved reserves may be assigned on
the basis of electrical and other type logs and/or core analysis that indicate
subject reservoir is hydocarbon bearing and is analogous to reservoirs in the
same area that are producing, or have deomonstrated the ability to produce on a
formation test.
The area of a reservoir considered proved includes (1) the area delineated by
drilling and defined by fluid contacts, if any, and (2) the undrilled areas that
can be reasonably judged as commercially productive on the basis of available
geological and engineering data. In the absence of data on fluid contracts, the
lowest known structural occurrence of hydocarbons controls the proved limit
unless otherwise indicated by definitive engineering of performance data.
Proved reserves must have facilities to process and transport those reserves to
market that are operational at the time of the estimate, or there is a commit-
ment or reasonable expectations to install such facilities in the future.
In general, proved undeveloped reserves are assigned to undrilled locations that
satisfy the following conditions: (1) the locations are direct offsets to wells
that have indicated commercial production in the objective formation, (2) it is
reasonably certain that the locations are within the known proved productive
limits of the objective formation, (3) the locations conform to existing well
spacing regulations, if any, and (4)it is reasonably certain that the locations
will be developed. Reserves for other undrilled locations are classified as
proved undeveloped only in those cases where interpretations of data from wells
indicate that the objective formation is laterally continuous and contains com-
mercially recoverable hydrocarbons at locations beyond direct offsets.
Reserves that can be produced through the application of established improved
recovery methods are included in the proved classifications when (1) successful
testing by a pilot project or favorable production or pressure response of an
insalled program in that reservoir, or one in the immediate area with similar
rock and fluid properties, provides support for the engineering analysis on
which the project or program is based and (2) it is reasonably certain the pro-
ject will proceed.
Reserves to be recovered by improved recovery methods that have yet to be esta-
blished through repeated commercially successful applications are included in
the proved classification only (1) after a favorable production response from
subject reservoir from either (a) a representative pilot or (b) an installed
program, where the response provides support for the engineering analysis on
which the project is based, and (2) it is reasonably certain the project will
proceed.
UNPROVED RESERVES
Unproved reserves are based on geologic and/or engineering data similar to that
used in estimates of proved reserves; but technological, contractual, economic,
or regulatory uncertainties preclude such reserves being classified as proved.
They may be estimated assuming future economic
Page 2
<PAGE>
conditions different from those prevailing at the time of the estimate.
Estimates of unproved reserves may be made for internal planning or special
evaluations, but are not routinely compiled.
Unproved reserves are not to be added to proved reserves because of different
levels of uncertainty.
Unproved reserves may be divided into two subclassifications: probable and pos-
sible.
Probable Reserves - Probable reserves are less certain than proved reserves and
can be estimated with a degree of certainty sufficient to indicate they are more
likely to be recovered than not.
In general, probable reserves may include (1) reserves anticipated to be proved
by normal stepout drilling where subsurface control is inadequate to classify
these reserves as proved, (2) reserves in formations that appear to be
productive base on log characteristics but that lack core data or definitive
tests and which are not analogous to producing or proved reservoirs in the area,
(3) incremental reservoirs attributable to infill drilling that otherwise could
be classified as prove but closer to statutory spacing had not been approved at
the time of the estimate, (4) reserves attributable to an improved recovery
method which has been established by repeated commercially successful
applications when a project or pilot is planned but not in operation and rock,
fluid, and reservoir characteristics appear favorable for commercial
application, (5) reserves in an area of a formation that has been proved
productive in other areas of the field but subject area appears to be separated
from the proved area by faulting and the geologic interpretation indicates
subject area is structurally higher than the proved area, (6) reserves
attributable to a successful workover, treatment, retreatment, change of
equipment, or other mechanical procedure, where such procedure has not been
proved successful in wells exhibiting similar behavior in analogous reservoirs,
and (7) incremental reserves in a proved producing reservoir where an alternate
interpretation of performance or volumetric data indicates significantly more
reserves than can be classified as proved.
Possible Reserves - Possible reserves are less certain than probable reserves
and can be estimated with a low degree of certainty, insufficient to indicate
whether they are more likely to be recovered than not.
In general, possible reserves may include (1) reserves suggested by structural
and/or stratigraphic extrapolation beyond area classified as probable, based on
geologic and/or geophysical interpretation, (2) reserves in formations that
appear to be hydrocarbon bearing based on logs or cores but that may not be
productive at commercial rates, (3) incremental reserves attributable to infill
drilling that are subject to technical uncertainty, (4) reserves attributable to
an improved recovery method when a project or pilot is planned but not in opera-
tion and rock, fluid, and reservoir characteristics are such that a reasonable
doubt exists that the project will be commercial, and (5) reserves in an area of
a formation that has been proved productive in other areas of the field but
subject area appears to be separated from the proved area by faulting and
geologic interpretation indicates subject area is structurally lower than the
proved area.
Page 3
<PAGE>
RESERVE STATUS CATEGORIES
Reserve status categories define the development and producing status of wells
and/or reservoirs.
Developed - Developed reserves are expected to be recovered from existing wells
(including reserves behind pipe). Improved recovery reserves are considered
developed only after the necessary equipment has been installed, or when the
costs to do so are relatively minor. Developed reserves may be subcategorized as
producing or nonproducing.
Producing - Producing reserves are expected to be recovered from
completion intervals open at the time of the estimate
and producing. Improved recovery reserves are consid-
ered to be producing only after an improved recovery
project is in operation.
Nonproducing - Non producing reserves include shut-in and behind-pipe
reserves. Shut-in reserves are expected to be recover-
ed from completion intervals open at the time of the
estimate, but which had not started producing, or
where shut-in for market conditions or pipeline conec-
tion, or were not capable of production for mechanical
reasons, and the time when sales will start is uncer-
tain.
Behind-pipe reserves are expected to be recovered from zones behind casing in
existing wells, which will require additional completion work or a future
recompletion prior to the start of production.
Undeveloped - Undeveloped reserves are expected to be recovered: (1) from new
wells on undrilled acreage, (2) from deepening existing wells to a different
reservoir, or (3) where a relatively large expenditure is required to (a)
recomplete an existing well or (b) install production or transportation
facilities or improved recovery projects.
Page 4
<PAGE>
