SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-QSB
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period ____________________ to ____________________
Commission file number 0-16487
Inland Resources Inc.
(Exact name of small business issuer as specified in its charter)
Washington 91-1307042
(State of incorporation or organization)
(IRS Employer Identification No.)
475 17th Street, Suite 1500, Denver, Colorado 80202
(Address of principal executive offices) (ZIP Code)
Issuer's telephone number, including area code: (303) 292-0900
______________________________________________________________________
Former name, address and fiscal year, if changed, since last report)
Indicate by check mark whether the issuer (1) has filed all reports required
to be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes xx No
Number of shares of common stock, par value $.001 per share, outstanding as of
August 1, 1995: 28,927,999
1
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PART 1. FINANCIAL INFORMATION
<TABLE>
INLAND RESOURCES INC.
CONSOLIDATED BALANCE SHEETS
June 30, 1995 and December 31, 1994
<CAPTION>
June 30, December 31,
1995 1994
ASSETS (Unaudited)
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 515,942 $ 1,691,156
Restricted cash 160,658
Accounts receivable 663,311 902,959
Inventory 852,344 835,691
Department of Energy contract 182,224 650,147
Prepaid expenses 423,886 379,622
Total current assets 2,637,707 4,620,233
Property and equipment, at cost:
Oil and gas properties (successful
efforts method) 14,591,317 11,884,625
Gas and water transportation facilities 647,833 646,507
Accumulated depletion, depreciation and
amortization (937,549) (489,840)
14,301,601 12,041,292
Other property and equipment, net 578,858 376,128
Total assets $ 17,518,166 $17,037,653
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 2,090,845 $ 2,407,179
Current portion of long-term debt 3,028,518 1,965,157
Property reclamation costs, short-term 300,000 300,000
Total current liabilities 5,419,363 4,672,336
Long-term debt 3,405,203 2,157,842
Property reclamation costs, long-term 125,690 283,670
Stockholders' equity:
Preferred Class A stock, par value $.001;
20,000,000 shares authorized, 106,850
shares of Series A issued and outstanding;
liquidation preference of $5,342,500 107 107
Additional paid-in capital - preferred 3,672,861 3,672,861
Common stock, par value $.001; 100,000,000
shares authorized; issued and outstanding
28,927,999 28,928 28,928
Additional paid-in capital - common 13,168,591 13,168,591
Accumulated deficit (8,302,577) (6,946,682)
Total stockholders equity 8,567,910 9,923,805
Total liabilities and stockholders
equity $17,518,166 $17,037,653
The accompanying notes are an integral
part of the financial statements
</TABLE>
2
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PART 1. FINANCIAL INFORMATION (Continued)
<TABLE>
INLAND RESOURCES INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
For the three-month and six-month periods ended
June 30, 1995 and 1994
(Unaudited)
<CAPTION>
Three-months ended Six-months ended
June 30, June 30,
1995 1994 1995 1994
<S> <C> <C> <C> <C>
Sales of oil and gas $ 575,689 $ 218,803 $ 1,128,645 $ 403,039
Operating expenses:
Lease operating expenses 349,331 160,840 736,697 337,605
Production taxes 37,931 29,165 89,035 48,650
Exploration 2,665 14,592
Depletion, depreciation
and amortization 257,044 62,434 510,709 125,653
General and
administrative, net 473,354 158,292 779,785 355,331
Total operating expenses 1,120,325 410,731 2,130,818 867,239
Operating loss (544,636) (191,928) (1,002,173) (464,200)
Interest expense (245,502) (421,408)
Other income, net 43,031 2,750 67,686 4,332
Net loss $ (747,107) $(189,178) $(1,355,895)$(459,868)
Net loss per share $ (.03) $ (.01) $ (.05) $ (.03)
Weighted average common
shares outstanding 28,927,999 15,165,491 28,927,999 14,647,732
Dividends per share NONE NONE NONE NONE
The accompanying notes are an integral
part of the financial statements
</TABLE>
3
<PAGE>
PART 1. FINANCIAL INFORMATION (Continued)
<TABLE>
INLAND RESOURCES INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the six-month periods ended June 30, 1995 and 1994
(Unaudited)
<CAPTION>
<S> <C> <C>
1995 1994
Cash flows from operating activities:
Net loss $ (1,355,895) $ (459,868)
Adjustments to reconcile net loss to net
cash used by operating activities:
Net cash used by discontinued operations (157,980) (142,498)
Depletion, depreciation and amortization 510,709 125,653
Effect of changes in current assets and
liabilities:
Accounts receivable 707,571 (16,154)
Inventory (16,653) (16,047)
Other current assets 43,236 (9,540)
Accounts payable and accrued expenses (316,334) 89,764
Net cash used by operating activities (585,346) (428,690)
Cash flows from investing activities:
Development expenditures and equipment
purchases (2,770,748) (171,225)
Change in restricted cash 160,658
Net cash provided by discontinued operations 220,363
Net cash provided (used) by investing activities(2,610,090) 49,138
Cash flows from financing activities:
Proceeds from issuance of common stock 400,000
Proceeds from long-term debt 2,100,000
Payments of long-term debt (79,778)
Net cash provided by financing activities 2,020,222 400,000
Net increase (decrease) in cash and cash
equivalents (1,175,214) 20,448
Cash and cash equivalents at beginning of
period 1,691,156 302,608
Cash and cash equivalents at end of period $ 515,942 $ 323,056
Noncash financing activity:
Issuance of note payable for consulting
services $ 87,500
Issuance of note payable for land purchase $ 203,000
</TABLE>
The accompanying notes are an integral
part of the financial statements
4
<PAGE>
PART 1. FINANCIAL INFORMATION (Continued)
INLAND RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
______
1. COMPANY ORGANIZATION:
Inland Resources Inc. (the "Company") was incorporated on August 12,
1985 in the State of Washington for the purpose of acquiring, exploring
and developing interests in mining properties. In 1987 the Company
developed a leased property (the "Toiyabe Mine") and began production of
gold and silver. Operations at the Toiyabe Mine have included open-pit
mining, crushing, agglomerations, heap leaching and gold and silver
recovery processes. Currently, the Company's mining operations are limited
to the final detoxification, reclamation and closure of the Toiyabe Mine
in compliance with Nevada and federal laws.
In March 1993, the Company acquired an undivided 50% interest in 36,860
net acres of oil and gas leases in the Uinta Basin located in Duchesne
County Utah, and an undivided 50% interest in various tangible oil and gas
assets (collectively called the "Duchesne County Field"). Accordingly, the
Company's business emphasis changed from precious metals mining to oil and
gas development and production.
On September 21, 1994, the Company acquired all the outstanding common and
preferred stock of Lomax Exploration Company. Effective July 1, 1995, the
name of Lomax Exploration Company was changed to Inland Production Company
("IPC"). IPC is also engaged primarily in oil and gas development and
production activities in the Uinta Basin area of Northeastern Utah
(collectively called the "Monument Butte Field"). The acquisition was
accounted for as a purchase, therefore, the net assets and results of
operations of IPC are included in the Company's consolidated financial
statements from the acquisition date forward. IPC operates as a wholly-
owned subsidiary of the Company.
2. BASIS OF PRESENTATION:
The preceding financial information has been prepared by the Company
pursuant to the rules and regulations of the Securities and Exchange
Commission ("SEC") and, in the opinion of the Company, includes all normal
and recurring adjustments necessary for a fair statement of the results of
each period shown. Certain information and footnote disclosures normally
included in the financial statements prepared in accordance with generally
accepted accounting principles have been condensed or omitted pursuant to
SEC rules and regulations. Management believes the disclosures made are
adequate to ensure that the financial information is not misleading, and
suggests that these financial statements be read in conjunction with the
Company's Annual Report on Form 10-KSB for the year ended December 31,
1994.
3. RECLASSIFICATIONS:
Certain amounts for 1994 have been reclassified to conform with the 1995
financial statement presentation. The reclassifications had no impact on
net loss or the accumulated deficit.
4. LONG-TERM DEBT:
The Company is in violation of the minimum net cash flow covenant within
the Inland Loan Agreement (defined in Item 2). Waivers regarding compliance
with this covenant have been granted covering the period through September
30, 1995. In addition, borrowings under the Inland Loan Agreement are due
and payable on December 31, 1995. Currently, the Company does not have
available funds to cure the covenant violation and does not expect to
generate sufficient cash flow from the Duchesne County Field to repay the
indebtedness before December 31, 1995. As a result, the Company is exploring
other alternatives to repay the indebtedness which include (i) selling the
property (ii) selling additional equity of the Company (iii) refinancing the
loan with Joint Energy Development Investments Limited Partnership ("JEDI"),
or (iv) refinancing the loan with a separate lender. If the Company remains
in violation of the minimum net cash flow covenant or should the Company be
5
<PAGE>
unable to repay the borrowings when due, it is possible that JEDI could
foreclose on the Duchesne County Field. The Inland Loan Agreement is
nonrecourse, therefore, foreclosure would not impact the Monument Butte
Field or other assets of the Company. Also, Inland does not operate the
Duchesne County Field and the property does not currently generate any
unrestricted operating cash for the Company. As of June 30, 1995,
outstanding indebtedness under the Inland Loan Agreement was $2,500,000.
See an expanded discussion of the Inland Loan Agreement within the
Liquidity and Capital Resources section of Management's Discussion and
Analysis or Plan of Operation.
On August 10, 1995, the Company entered into a Letter of Intent with
Petroglyph Gas Partners, L.P. ("PGP") to sell the Company's 50% undivided
interest in the Duchesne County Field. Under the terms of the agreement,
PGP will pay the Company $3,000,000 in cash and assume the $2,500,000 of
outstanding indebtedness under the Inland Loan Agreement. The closing date
is anticipated to be September 1, 1995 with a July 1, 1995 effective date.
The sale remains subject to the negotiation and execution of a purchase and
sale agreement, approval of the transaction by the Company's Board of
Directors and various other regulatory and governmental approvals. Also,
JEDI must consent to PGP's assumption of the Company's outstanding debt
under the Inland Loan Agreement.
5. PREFERRED STOCK:
The Series A Preferred Stock contains a right that increases the
Liquidation Value and Redemption Price from $50.00 to $54.00 per share on
August 29, 1995. As a result, effective August 29, 1995 the Liquidation
Value of the Series A Preferred Stock will increase to $5,769,900 and each
share of Series A Preferred Stock will be convertible into 90 shares of the
Company's Common Stock.
6. DEFERRED COMPENSATION AGREEMENT:
The Company and John D. Lomax mutually agreed to terminate Mr. Lomax s
employment services to the Company effective July, 1 1995. Mr. Lomax will
continue in his position as Chairman of the Company's Board of Directors.
Under the terms of his employment agreement, Mr. Lomax is entitled to one
years salary and benefits upon termination. The calculated severance
amount of $142,000 is accrued as a component of general and administrative
expense during the three month period ended June 30, 1995. The severance
amount will be paid-out during the next two years in equal bi-monthly
installments.
7. RELATED PARTY TRANSACTION:
Effective July 1, 1995, the Company entered into a Farmout Agreement (the
"Farmout") with a significant stockholder ("Farmee"). The Farmout covers the
period through the end of 1995 and allocates up to $6,600,000 for the
drilling and completion of wells in the Monument Butte Field. Under terms
of the Farmout, the interest in each drillsite assigned to the Farmee
reverts to the Company after Payout. Payout is defined on a lease basis as
the point in time when Farmee has recovered through production proceeds, net
of production taxes, 100% of the cost to drill, complete and operate the
well or wells on the affected lease plus a 22% rate of return. The Farmee is
also required to pay the Company a supervisory fee of $25,000 per well,
proportionately reduced to the Farmee's interest and net of COPAS
drilling overhead charges, to reimburse the Company for land, geological,
engineering and accounting services. The agreement may be terminated at any
time by either party. The accompanying financial statements as of June 30,
1995 do not include any activity under the Farmout.
6
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PART 1. FINANCIAL INFORMATION (Continued)
INLAND RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION
______
ITEM 2. Management's Discussion and Analysis or Plan of Operation:
GENERAL:
Upon the acquisition of the Duchesne County Field, Inland's mining operations
were limited to final detoxification, reclamation and closure of the Toiyabe
Mine, and Inland's business emphasis was shifted to its current business of
oil and gas development and production. Effective February 1, 1994, Evertson
Oil Company sold their 50% undivided interest in the Duchesne County Field and
assigned their option for 2,008,894 shares of the Company's Common Stock to
Petroglyph Gas Partners, L.P. ("PGP"). As a result, Inland and PGP each own a
50% undivided interest in the Duchesne County Field with PGP serving as
operator.
Effective September 21, 1994, the Company acquired all the outstanding common
and preferred stock of Lomax Exploration Company (the name was subsequently
changed to Inland Production Company IPC ). IPC is also engaged primarily in
oil and gas development and production activities in the Uinta Basin area of
Northeastern, Utah (the "Monument Butte Field"). At the acquisition date, IPC
owned varying working interests in 62 wells of which the majority were
operated and located adjacent to the Company's properties. IPC's property
interest included 8,508 net acres of oil and gas leases in Utah and 8,847 net
acres of mostly undeveloped leasehold in Wyoming. The IPC acquisition was
accounted for as a purchase, therefore, the net assets and results of
operations of IPC are included in the Company's consolidated financial
statements from the acquisition date forward. IPC operates as a wholly-owned
subsidiary of the Company.
Inland's strategy for achieving profitability is to increase oil and gas
reserves and production through acquisition of existing oil and gas production
in developed fields, and further developing such existing production through
development drilling, reworking existing wells and engaging in secondary
recovery enhancement operations. Increased production levels are expected to
increase operational efficiencies at the field level which in turn should have
a positive impact on the Company's equivalent per barrel lifting costs. In
addition, general and administrative costs are expected to decrease in
relation to production since these costs are generally fixed in nature and
thereby do not increase proportionate to production. The Company also has
protected the price it receives for a portion of its oil production by
entering into hedging arrangements. The ultimate success of the Company's plan
to achieve profitability is dependent on conducting extensive development and
secondary recovery operations on existing properties, locating new properties
with acceptable terms and continuing to secure sufficient capital to acquire
and develop target properties.
The Company does not generally intend to pursue exploratory drilling in
undeveloped oil and gas properties due to the industry's relatively high
historical failure rate relating to exploratory drilling and the resulting
higher associated finding costs. However, from time to time the Company may
for various reasons determine to drill exploratory wells in certain areas
considered strategic by the Company.
7
<PAGE>
PART 1. FINANCIAL INFORMATION (Continued)
INLAND RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION
______
RESULTS OF OPERATIONS:
Three Months Ended June 30, 1995 and 1994:
Continuing Operations Continuing Operations :
The Company acquired IPC effective September 21, 1994. Accordingly, the
results of operations for the second quarter of 1995 includes three months of
consolidated activity, while the results of operations for the second quarter
of 1994 does not include any IPC activity.
Sales during the second quarter of 1995 exceeded the previous year second
quarter by $357,000 due to the IPC sales and development drilling in the
Duchesne County Field. Monthly consolidated sales volumes increased to an
average of 10,100 Bbls of oil and 12,100 Mcf of natural gas in the second
quarter of 1995 from 2,600 Bbls and 15,400 Mcf in 1994. In addition, the
average price received for oil production increased from approximately $16.50
Bbl during 1994 to approximately $17.65 Bbl during 1995. Natural gas prices
fell from an average price of $1.95 Mcf in 1994 to approximately $1.20 Mcf
during 1995.
Lease operating expenses increased $188,000 between periods primarily due to
the IPC operations in 1995. The Company continues to focus on lowering its
lifting costs and as a result lease operating expense per barrel of oil
equivalent ("BOE") decreased from $12.27 for the year ended December 31, 1994
to $10.90 for the three month period ended March 31, 1995 to $9.65 for the
three month period ended June 30, 1995. The Company's policy to expense the
costs of water injection operations during the start-up phase of secondary
recovery water flood operations has contributed to this high level of lifting
costs. These expenses include the costs of purchasing water and operating
water source wells, water injection wells and water injection stations. As a
result of this policy, the Antelope Creek Field (a start-up water flood
operation in 1994 within the Duchesne County Field) had operating costs in
excess of $14.00 per BOE during 1994 and continued high operating costs during
the first six months of 1995, while the operating costs for the first water
flood unit within the Monument Butte Field (a mature water flood operation)
(the "Monument Butte Unit") were less than $5.00 per BOE. The decrease in
lifting costs per BOE in mature water floods is attributable to increased
production rather than decreased operating costs. The Company considers the
Monument Butte Unit to be the only mature water flood in which the Company has
an interest at June 30, 1995.
The increase in production taxes and depletion, depreciation and amortization
between periods is consistent with the increased sales volumes in 1995.
Exploration expense in 1995 represents the Company's share of costs to retain
unproved acreage and residual costs related to uneconomic exploration wells
drilled in 1994.
General and administrative expenses increased approximately $315,000 between
periods. After removing the one-time charge for the John D. Lomax severance
accrual of $142,000, the increase was $173,000 between periods. The majority
of the general and administrative increase is related to salaries, payroll
taxes and employee benefits as the Company's employee base grew from six
employees at June 30, 1994 to twenty-three employees at June 30, 1995. The
increase in employees was required since the Company became an operator of
properties through the merger with IPC and to administer the 1995 drilling
program. The remaining increase is associated with the cost of operating with
8
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a larger employee base such as additional travel, supplies and utilities
expense.
Interest expense represents the financing cost of borrowings in 1995 under the
Inland Loan Agreement, IPC Loan Agreement and other debt assumed during the
merger with IPC. No debt existed during the second quarter of 1994.
Other income in 1995 primarily represents interest earned on the investment of
surplus cash balances and certain oil trading income.
Discontinued Operations:Discontinued Operations
The Company considers all mining activities to be discontinued operations.
Since March 1994, the Company's only mining activity has been the Toiyabe
Mine. Reclamation activities at the Toiyabe Mine during 1994 concentrated on
the detoxification of leach pad #1 which, based on recent closure sampling
results, appears to be within the toxicity guidelines as established in the
approved reclamation plans. The focus of reclamation activities in 1995 has
been the detoxification of leach pad #2 using procedures similar to those
performed on leach pad #1 in the previous year.
During the second quarters of 1995 and 1994, the Company incurred reclamation
costs of $100,000 and $114,000, respectively. Since operating procedures were
similar in each year on different pads, the cost differential is attributable
to variable expenses such as supplies, repairs, etc. In each period,
reclamation costs were charged against the reclamation reserve and, therefore,
did not impact the Consolidated Statement of Operations. Based on factors
presently known or anticipated, the Company believes that the reclamation
reserve of $426,000 at June 30, 1995 will be sufficient to fully reclaim the
Toiyabe Mine in compliance with established environmental standards.
Six Months Ended June 30, 1995 and 1994:
Continuing OperationsContinuing Operations :
The Company acquired IPC effective September 21, 1994. Accordingly, the
results of operations for the first six months of 1995 includes consolidated
Inland and IPC activity, while the results of operations for the first six
months of 1994 does not include any IPC activity.
Sales the first six months of 1995 exceeded the same period in the previous
year by $725,000 due to the IPC sales and development drilling in the Duchesne
County Field. Monthly consolidated sales volumes increased to an average of
9,800 Bbls of oil and 12,700 Mcf of natural gas from 2,500 Bbls and 14,800 Mcf
in 1994. In addition, the average price received for oil production increased
from approximately $14.90 Bbl during 1994 to approximately $17.40 Bbl during
1995. Natural gas prices fell from an average price of $1.95 Mcf in 1994 to
approximately $1.35 Mcf during 1995.
Lease operating expenses increased $399,000 between periods primarily due to
the IPC operations in 1995. As explained more thoroughly in the previous
analysis for the three month period ended June 30, 1995, the Company continues
to focus on lowering its lifting costs. Lease operating expense per BOE
decreased from $12.27 for the year ended December 31, 1994 to $10.25 for the
six month period ended June 30, 1995. The Company's policy of expensing the
costs of water injection operations during the start-up phase of secondary
recovery water flood operations has contributed to this high level of lifting
costs per BOE. Other than the Monument Butte Unit, all water flood operations
are considered to be in the start-up phase.
The increase in production taxes and depletion, depreciation and amortization
between periods is consistent with the increased sales volumes in 1995.
9
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Exploration expense in 1995 represents the Company's share of costs to retain
unproved acreage and residual costs related to uneconomic exploration wells
drilled in 1994.
General and administrative expenses increased approximately $424,000 between
periods. After removing the one-time charge for the John D. Lomax severance
accrual of $142,000, the increase was $282,000 between periods. The majority
of the general and administrative increase is related to salaries, payroll
taxes and employee benefits as the Company's employee base grew from six
employees at June 30, 1994 to twenty-three employees at June 30, 1995. The
increase in employees was required since the Company became an operator of
properties through the merger with IPC and to administer the 1995 drilling
program. The remaining increase is associated with the cost of operating with
a larger employee base such as additional travel, supplies and utilities
expense.
Interest expense represents the financing cost of borrowings in 1995 under the
Inland Loan Agreement, IPC Loan Agreement and other debt assumed during the
merger with IPC. No debt existed during the first six months of 1994.
Other income in 1995 primarily represents interest earned on the investment of
surplus cash balances and certain oil trading income.
Discontinued Operations:Discontinued Operations
The Company considers all mining activities to be discontinued operations.
During the first quarter of 1994, the Company sold an undeveloped mining
property for approximately $222,500. Since March 1994, the Company's only
mining activity has been the Toiyabe Mine. Reclamation activities at the
Toiyabe Mine during 1994 concentrated on the detoxification of leach pad #1
which, based on recent closure sampling results, appears to be within the
toxicity guidelines as established in the approved reclamation plans. The
focus of reclamation activities in 1995 has been the detoxification of leach
pad #2 using procedures similar to those performed on leach pad #1 in the
previous year.
During the initial six months of 1995 and 1994, the Company incurred
reclamation costs of $158,000 and $174,000, respectively. Reclamation charges
in 1994 were offset by incidental mineral recoveries of $38,000 for a net
reclamation cost of $136,000. Since operating procedures were similar in each
year on different pads, the cost differential is attributable to variable
expenses such as supplies, repairs, etc. In each period, reclamation costs
were charged against the reclamation reserve and, therefore, did not impact
the Consolidated Statement of Operations. Based on factors presently known or
anticipated, the Company believes that the reclamation reserve of $426,000 at
June 30, 1995 will be sufficient to fully reclaim the Toiyabe Mine in
compliance with established environmental standards.
10
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PART 1. FINANCIAL INFORMATION (Continued)
INLAND RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION
______
LIQUIDITY AND CAPITAL RESOURCES:
During the first six months of 1995, the Company's unrestricted cash and cash
equivalents decreased $1,175,000 to $516,000. The primary uses of unrestricted
cash during this period were (1) reclamation activities at the Toiyabe Mine
site of $158,000, (2) principal payments on long-term debt of $80,000, (3)
payment of general and administrative expenses of $638,000 (net of overhead
reimbursements), (4) reduction of outstanding accounts payable and accrued
expenses of $458,000, (5) payment of $196,000 to the IPC restricted account to
cover minimum net cash flow deficiencies under the IPC Loan Agreement (defined
below), and (6) net changes in other current assets and liabilities and other
items of $181,000. The primary sources of unrestricted cash were (1) receipts
under the contract with the Department of Energy of $468,000, and (2) interest
and other miscellaneous income of $68,000.
The Company also borrowed a total of $2,100,000 under the Inland and IPC Loan
Agreements during 1995 and further developed the Duchesne County Field and the
Monument Butte Field. Since these borrowings, along with the net cash flows
from the properties, are restricted to pay project costs and interest they do
not affect unrestricted cash flows. At June 30, 1995, the Company had incurred
project costs slightly in excess of borrowings and, therefore, no restricted
cash is shown in the accompanying consolidated financial statements.
During the first six months of 1995, the Company incurred capital expenditures
of $2,771,000. These expenditures include the drilling cost of five
development wells, two exploratory wells and one water injection well in the
Monument Butte Field. The Company also incurred its proportionate share of
costs on eight wells in the Duchesne County Field and performed various other
activities. Throughout the remainder of 1995, the Company anticipates using
borrowings available under the Inland Loan Agreement and IPC Loan Agreement to
further develop oil and gas operations in the Duchesne County Field and
Monument Butte Field through additional infill well drilling, further
development of existing water flood areas and the initiation of new water
flood areas.
Effective July 1, 1995, the Company entered into a Farmout Agreement covering
the period through the end of 1995 that allocates up to $6,600,000 for the
drilling and completion of wells in the Monument Butte Field. Under terms of
the Farmout, the interest in each drillsite assigned to the Farmee reverts to
the Company after Payout. Payout is defined on a lease basis as the point in
time when Farmee has recovered through production proceeds, net of production
taxes, 100% of the cost to drill, complete and operate the well or wells on
the affected lease plus a 22% rate of return. The Farmee is also required to
pay the Company a supervisory fee of $25,000 per well, proportionately reduced
to the Farmee's interest and net of COPAS drilling overhead charges, to
reimburse the Company for land, geological, engineering and accounting
services. The agreement may be terminated at any time by either party.
On August 24, 1994, the Company entered into a Loan Agreement with JEDI, an
affiliate of Enron Corp., to provide nonrecourse financing for the development
of the Duchesne County Field (the "Inland Loan Agreement"). On September 21,
1994, the Company entered into a separate Loan Agreement with JEDI to provide
financing for the development of the Monument Butte Field (the "IPC Loan
Agreement"). The production loan portion of each facility includes the initial
$1.5 million of borrowings and bears interest at prime plus 1.5%. The
development loan portion of the Inland Loan Agreement includes the next $6.0
million of advances beyond the initial $1.5 million production loan for a
11
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maximum combined commitment of $7.5 million, and the development loan portion
of the IPC Loan Agreement includes the next $3.5 million of advances beyond
the initial $1.5 million production loan for a maximum combined commitment of
$5.0 million. The development loan portion of each facility bears interest at
prime plus 4% plus an equity yield enhancement in the form of a 7.25%
overriding royalty interest in the Inland Loan Agreement and an 8.5%
overriding royalty interest in the IPC Loan Agreement, in each instance
proportionately reduced by the Company's interest in the oil and gas
properties and commencing January 28, 1996 and continuing until the internal
rate of return to JEDI equals 19% on the development loan portion of the
applicable facility. Each advance under each facility is also subject to a 1%
loan commitment fee. Interest only is payable monthly under each facility
until December 31, 1995. On December 31, 1995, the entire principal balance
of the Inland Loan Agreement is due, and the principal balance on the IPC Loan
Agreement will be scheduled over 60 monthly installments of principal and
interest. The Company is required to meet certain minimum ratios, generate or
contribute agreed upon levels of monthly net cash flow and maintain a
commodity price hedging agreement under each facility. The Inland Loan
Agreement is collateralized by the Company's interest in the Duchesne County
Field. The IPC Loan Agreement is collateralized by the Company's interest in
the Monument Butte Field. At June 30, 1995, the Company had borrowed
$2,500,000 under the Inland Loan Agreement and $3,500,000 under the IPC Loan
Agreement. As further discussed below, the Company was in violation of the
minimum net cash flow covenant within the Inland Loan Agreement at June 30,
1995, but had received a waiver regarding compliance with this covenant
covering the period through September 30, 1995.
Substantially all oil and gas properties of the Company are mortgaged under
the Loan Agreements with JEDI. Under those agreements, the loan proceeds and
net cash flows (generally defined as production revenue less production taxes
and lease operating costs) from mortgaged properties are required to be
maintained in segregated accounts and are not available for general corporate
purposes. Funds in the segregated accounts may be used for project costs and
to make principal and interest payments as they become due. As a result, the
Company is required to cover the net reclamation costs of the Toiyabe Mine,
net general and administrative expenses, capital expenditures on non-mortgaged
properties and contributions to cover minimum net cash flow deficiencies under
the Loan Agreements out of its current unrestricted operating cash holdings,
the Company's share of proceeds received under the Department of Energy cost
sharing project and supervisory fees earned under the Farmout Agreement.
Assuming only the above unrestricted cash sources and uses, the Company
anticipates that it will experience operating cash shortfalls before June 30,
1996. The Company anticipates curing any operating cash shortfalls by selling
nonstrategic property interests, selling additional equity of the Company, or
entering into a joint venture arrangement with an industry partner that
provides the Company with additional unrestricted operating cash. Furthermore,
the amount borrowed under the Inland Loan Agreement is due and payable on
December 31, 1995, as further discussed below.
The Company is in violation of the minimum net cash flow covenant within the
Inland Loan Agreement. Waivers regarding compliance with this covenant have
been granted covering the period through September 30, 1995. In addition,
borrowings under the Inland Loan Agreement are due and payable on December 31,
1995. Currently, the Company does not have available funds to cure the
covenant violation and does not expect to generate sufficient cash flow from
the Duchesne County Field to repay the indebtedness before December 31, 1995.
As a result, the Company is exploring other alternatives to repay the
indebtedness which include (i) selling the property (ii) selling additional
equity of the Company (iii) refinancing the loan with JEDI, or (iv)
refinancing the loan with a separate lender. If the Company remains in
violation of the minimum net cash flow covenant or should the Company be
unable to repay the borrowings when due, it is possible that JEDI could
foreclose on the Duchesne County Field. The Inland Loan Agreement is
nonrecourse, therefore, foreclosure would not impact the Monument Butte Field
12
<PAGE>
or other assets of the Company. Also, Inland does not operate the Duchesne
County Field and the property does not currently generate any unrestricted
operating cash for the Company. As of June 30, 1995, outstanding indebtedness
under the Inland Loan Agreement was $2,500,000.
On August 10, 1995, the Company entered into a Letter of Intent with
Petroglyph Gas Partners, L.P. ("PGP") to sell the Company's 50% undivided
interest in the Duchesne County Field. Under the terms of the agreement, PGP
will pay the Company $3,000,000 in cash and assume the $2,500,000 of
outstanding indebtedness under the Inland Loan Agreement. The closing date is
anticipated to be September 1, 1995 with a July 1, 1995 effective date. The
sale remains subject to the negotiation and execution of a purchase and sale
agreement, approval of the transaction by the Company's Board of Directors and
various other regulatory and governmental approvals. Also, JEDI must consent
to PGP's assumption of the Company's outstanding debt under the Inland Loan
Agreement. Assuming the Company closed on the transaction under the terms
outlined above, the Company would no longer have any covenant or other
violations in existence under any debt agreements. Also, the Company would
have sufficient unrestricted operating cash to cover the net reclamation costs
of the Toiyabe Mine, net general and administrative expenses and capital
expenditures on non-mortgaged properties through June 30, 1996.
The Loan Agreements with JEDI also require the Company to maintain price
protection agreements to help insure the repayment of indebtedness. In
satisfaction of this requirement in the Inland Loan Agreement, on August 24,
1994 the Company entered into a commodity contract with JEDI, through its
affiliate Enron Risk Management Services Corp. Under terms of the contract,
the Company hedged crude oil production over a four year period beginning
January 1, 1996 in monthly amounts escalating from 8,500 Bbls in January 1996
to 13,250 Bbls in December 1999. The hedge was structured as a cost free
collar whereby if the average monthly price (based on NYMEX Light Sweet Crude
Oil Futures Contracts) (the "Average Price") is between $17.00 and $20.75 per
barrel, no payment is due under the contract. If the Average Price is less
than $17.00, the Company is paid the difference between $17.00 and the Average
Price, multiplied by barrels of crude oil hedged that month. Similarly, should
the Average Price exceed $20.75 per barrel, the Company is required to pay the
difference between $20.75 and the Average Price, multiplied by barrels of
crude oil hedged that month. A similar contract was entered into with JEDI
regarding the IPC Loan Agreement on November 22, 1994. This contract hedges
crude oil production over a five year period beginning January 1, 1996 in
monthly amounts escalating from 8,500 Bbl in January 1996 to 14,000 Bbl in
December 2000. This hedge was also structured as a cost free collar with a
floor price of $18.00 and a ceiling price of $20.55. Since the hedged
quantities are based on expected future development in the Duchesne County
Fields and the Monument Butte Field and because hedging activities do not
affect the actual sales price for the Company's crude oil, there exists
substantial risk to the Company's financial position and results of operations
should the Average Price rise significantly above the ceiling prices of $20.75
and $20.55 in the respective contracts and development activities do not
produce the expected results or progress on a slower than expected timetable.
The Company is aware of and continually evaluates this financial risk and has
the ability to enter into commodity contracts to mitigate potential financial
loss should the risk factors as explained above begin to materialize.
The Company has also entered into similarly structured commodity contracts on
August 4, 1994 and January 18, 1995 which cover the period ending December 31,
1995. These contracts hedge an aggregate 8,000 Bbls of oil each month with a
cost-free range from $17.00 to $20.00 per Bbl. Because recent consolidated
net production has averaged in excess of 10,000 Bbls per month and because the
actual average sales price of oil in the field has approximated the Average
Price in the contract, these contracts do not currently subject the Company to
significant financial exposure. The Company recognized a hedging loss of
$7,700 during the first six months of 1995 under these contracts.
13
<PAGE>
The Company continues to aggressively seek other opportunities to acquire
existing oil and gas production in developed fields. The Company will attempt
to finance such acquisitions through (i) seller financing, whenever possible;
(ii) joint operating agreements with industry partners where the Company may
sell part of its position to provide acquisition and development funds; (iii)
sales of equity or debt of the Company; or (iv) traditional bank lines of
credit, although the Company currently has no existing bank lines of credit or
arrangements with any bank to loan funds.
The Company is subject to numerous federal and state laws and regulations
relating to environmental matters. Increasing focus on environmental issues
nationally has lead the Company to continue to evaluate its responsibilities
to the environment. The Company believes it is in compliance in all material
respects with applicable federal, state and local environmental regulations.
There are no environmental proceedings pending against the Company. At June
30, 1995, the Company had recognized a liability of $426,000 to cover the
future costs of reclaiming the Toiyabe Mine.
14
<PAGE>
PART II. OTHER INFORMATION
INLAND RESOURCES INC.
Items 1, 2 and 3 are omitted from this report as inapplicable.
Item 4. Submission of Matters to a Vote of Security Holders
On May 26, 1995, the Company held its Annual Meeting of
Stockholders. During the meeting the shareholders voted only on
the election of Directors. Pursuant to that vote, the following
individuals were elected to the Company's Board of Directors; John
D. Lomax (Chairman), Kyle R. Miller, Bill I. Pennington, Arthur J.
Pasmas, T Brooke Farnsworth, John J. Crabb and James F. Etter.
Item 5. Other Information.
On August 10, 1995, the Company entered into a Letter of Intent
with Petroglyph Gas Partners, L.P. ("PGP") to sell the Company s
50% undivided interest in the Duchesne County Field. Under the
terms of the agreement, PGP will pay the Company $3,000,000 in
cash and assume the $2,500,000 of outstanding indebtedness under
the Inland Loan Agreement. The closing date is anticipated to be
September 1, 1995 with a July 1, 1995 effective date. The sale
remains subject to the negotiation and execution of a purchase and
sale agreement, approval of the transaction by the Company's Board
of Directors and various other regulatory and governmental
approvals. Also, JEDI must consent to PGP's assumption of the
Company's outstanding debt under the Inland Loan Agreement.
Item 6. Exhibits and Reports on Form 8-K.
(a) The following documents are filed as part of this Quarterly Report
on Form 10-QSB:
Exhibit
Number Description of Exhibits
3.1 Articles of Incorporation, as amended through May 5, 1993
(filed as Exhibit 3.1 to the Company's Registration Statement on
Form S-18, Registration No. 33-11870-F, and incorporated herein by
reference).
3.1.1 Articles of Amendment to Articles of Incorporation dated
May 6, 1993 (filed as Exhibit 3.1.1 to the Company's Annual Report
on Form 10-KSB for the fiscal year ended December 31, 1993, and
incorporated herein by reference).
3.1.2 Articles of Amendment to Articles of Incorporation dated
August 16, 1994 designating a series of stock (filed as Exhibit
3.1.2 to the Company's Annual Report on Form 10-KSB for the fiscal
year ended December 31, 1994, and incorporated herein by reference).
3.1.3 Articles of Amendment to Articles of Incorporation filed
with Secretary of State of Washington on August 30, 1994 (filed as
Exhibit 3.1.3 to the Company's Annual Report on Form 10-KSB for
the fiscal year ended December 31, 1994, and incorporated herein
by reference).
3.1.4 Articles of Correction to Articles of Amendment dated
August 31, 1994 (filed as Exhibit 3.1.4 to the Company's Annual
Report on Form 10-KSB for the fiscal year ended December 31, 1994,
and incorporated herein by reference).
15
<PAGE>
3.2 Bylaws of the Company (filed as Exhibit 3.2 to the Company's
Registration Statement of Form S-18, Registration No. 33-11870-F,
and incorporated herein by reference).
3.2.1 Amendment to Article IV, Section 1 of the Bylaws of the
Company adopted February 23, 1993 (filed as Exhibit 3.2.1 to the
Company's Annual Report on Form 10-K for the fiscal year ended
December 31, 1992, and incorporated herein by reference).
3.2.2 Amendment to the Bylaws of the Company adopted April 8,
1994 (filed as Exhibit 3.2.2 to the Company's Registration
Statement of Form S-4, Registration No. 33-80392, and incorporated
herein by reference).
3.2.3 Amendment to the Bylaws of the Company adopted April 27,
1994 (filed as Exhibit 3.2.3 to the Company's Registration Statement
of Form S-4, Registration No. 33-80392, and incorporated herein by
reference).
10.1 Swap Agreement dated November 22, 1994 between Inland Resources
Inc. and Joint Energy Investments Limited Partnership.*
10.2 Swap Agreement dated January 18, 1995 between Inland Resources
Inc. and Enron Capital and Trade Resources Corp.*
10.3 Farmout Agreement dated July 1, 1995 between Inland Resources
Inc. and Inland Production Company and Randall D. Smith (without
exhibits).*
10.4 Deferred Compensation Agreement dated July 1, 1995 between
Inland Resources Inc. and John D. Lomax.*
27.1 Financial Data Schedule required by Item 601 of Regulation
S-B.*
_____________________________
* Filed herewith.
(b) No Current Report on Form 8-K was filed during the quarter
ended June 30, 1995.
16
<PAGE>
INLAND RESOURCES INC.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
INLAND RESOURCES INC.
(Registrant)
Date: August 11, 1995 By: Kyle R. Miller
Kyle R. Miller
Chief Executive Officer
Date: August 11, 1995 By: Michael J. Stevens
Michael J. Stevens
Controller (Principal
Accounting Officer)
17
<PAGE>
INDEX TO EXHIBITS
Exhibit Sequentially
Number Description of Exhibits Numbered Page
3.1 Articles of Incorporation, as amended through
May 5, 1993 (filed as Exhibit 3.1 to the
Company's Registration Statement on Form S-18,
Registration No. 33-11870-F, and incorporated
herein by reference).
3.1.1 Articles of Amendment to Articles of
Incorporation dated May 6, 1993 (filed as
Exhibit 3.1.1 to the Company's Annual Report on
Form 10-KSB for the fiscal year ended December
31, 1993, and incorporated herein by reference).
3.1.2 Articles of Amendment to Articles of
Incorporation dated August 16, 1994 designating
a series of stock (filed as Exhibit 3.1.2 to the
Company's Annual Report on Form 10-KSB for the
fiscal year ended December 31, 1994, and
incorporated herein by reference).
3.1.3 Articles of Amendment to Articles of
Incorporation filed with Secretary of State of
Washington on August 30, 1994 (filed as Exhibit
3.1.3 to the Company's Annual Report on Form
10-KSB for the fiscal year ended December 31,
1994, and incorporated herein by reference).
3.1.4 Articles of Correction to Articles of
Amendment dated August 31, 1994 (filed as
Exhibit 3.1.4 to the Company's Annual Report
on Form 10-KSB for the fiscal year ended
December 31, 1994, and incorporated herein
by reference).
3.2 Bylaws of the Company (filed as Exhibit 3.2 to
the Company's Registration Statement of Form S-18,
Registration No. 33-11870-F, and incorporated
herein by reference).
3.2.1 Amendment to Article IV, Section 1 of the Bylaws
of the Company adopted February 23, 1993 (filed
as Exhibit 3.2.1 to the Company's Annual Report
on Form 10-K for the fiscal year ended December
31, 1992, and incorporated herein by reference).
3.2.2 Amendment to the Bylaws of the Company adopted
April 8, 1994 (filed as Exhibit 3.2.2 to the
Company's Registration Statement of Form S-4,
Registration No. 33-80392, and incorporated
herein by reference).
3.2.3 Amendment to the Bylaws of the Company adopted
April 27, 1994 (filed as Exhibit 3.2.3 to the
Company's Registration Statement of Form S-4,
Registration No. 33-80392, and incorporated
herein by reference).
10.1 Swap Agreement dated November 22, 1994 between 21
18
<PAGE>
Inland Resources Inc. and Joint Energy
Investments Limited Partnership.*
10.2 Swap Agreement dated January 18, 1995 between 28
Inland Resources Inc. and Enron Capital and
Trade Resources Corp.*
10.3 Farmout Agreement dated July 1, 1995 between 51
Inland Resources Inc. and Inland Production
Company and Randall D. Smith (without
exhibits).*
10.4 Deferred Compensation Agreement dated July 1, 59
1995 between Inland Resources Inc. and John D.
Lomax.*
27.1 Financial Data Schedule required by Item 601 of
Regulation S-B.*
_____________________
* Filed herewith.
19
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from
the consolidated balance sheet at June 30, 1995 and the consolidated
statements of operations and cash flows for the six months ended
June 30, 1995, and is qualified in its entirety by reference
to such financial statements.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> MAR-31-1995
<PERIOD-END> JUN-30-1995
<CASH> 515,942
<SECURITIES> 0
<RECEIVABLES> 663,311
<ALLOWANCES> 0
<INVENTORY> 852,344
<CURRENT-ASSETS> 2,637,707
<PP&E> 16,125,690
<DEPRECIATION> (1,245,231)
<TOTAL-ASSETS> 17,518,166
<CURRENT-LIABILITIES> 5,419,363
<BONDS> 3,405,203
<COMMON> 13,197,519
0
3,672,968
<OTHER-SE> (8,302,577)
<TOTAL-LIABILITY-AND-EQUITY> 17,518,166
<SALES> 1,128,645
<TOTAL-REVENUES> 1,128,645
<CGS> 825,732
<TOTAL-COSTS> 2,130,818
<OTHER-EXPENSES> (67,686)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 421,408
<INCOME-PRETAX> (1,355,895)
<INCOME-TAX> 0
<INCOME-CONTINUING> (1,355,895)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (1,355,895)
<EPS-PRIMARY> ($.05)
<EPS-DILUTED> 0
</TABLE>
EXHIBIT 10.1
21
<PAGE>
Enron Risk Management Services Corp.
1400 Smith Street
P. O. Box 1188
Houston, Texas 77251-1188
SWAP AGREEMENT
(Collar)
TO: INLAND RESOURCES INC.
("Counterparty")
DATE: November 22, 1994
ATTN: Kyle Miller
CONTRACT NO.: Joint Energy Development Investments Limited Partnership
("JEDI")
JEDI Contract No. I00002
Contract No. C00940.0
The purpose of this agreement ("Agreement") is to confirm the terms and
conditions of the transaction (the "Transaction") entered into between Inland
Resources Inc. ("Counterparty") and Joint Energy Development Investments
Limited Partnership ("JEDI") pursuant to a telephone conversation between Kyle
Miller and Doug Hurley on November 22, 1994. This document constitutes a
"Confirmation" as referred to in the Master Agreement (defined herein). This
Confirmation supplements, forms part of, and is subject to, the ISDA Master
Agreement dated as of August 24, 1994, as it may have been or may be amended
and supplemented from time to time (the "Master Agreement"), between you and
us. All provisions contained in the Master Agreement govern this Confirmation
except as expressly modified herein.
The 1993 ISDA Commodity Derivatives Definitions (as amended from time to
time, the "Commodity Definitions") published by the International Swaps and
Derivatives Association, Inc. ("ISDA") are incorporated by reference in this
Confirmation. All capitalized terms that are not otherwise defined herein
which are contained in the Master Agreement or the Commodity Definitions shall
have the meanings set forth therein as applicable. In the event of any
inconsistency between the Commodity Definitions and this Confirmation, this
Confirmation will govern this Transaction.
1. TRANSACTION TERMS:
(a) CEILING PREMIUM PAYOR: JEDI.
(b) CEILING PREMIUM PAYEE: Counterparty.
(c) CEILING PREMIUM: $0.
(d) FLOOR PREMIUM PAYOR: Counterparty.
22
<PAGE>
(e) FLOOR PREMIUM PAYEE: JEDI.
(f) FLOOR PREMIUM: $0.
(g) FIXED PRICE PAYOR: JEDI.
(h) FLOATING PRICE PAYOR: Counterparty.
(i) CEILING PRICE: U.S. Dollars $20.5500 per Barrel.
(j) FLOOR PRICE: U.S. Dollars $18.0000 per Barrel.
(k) FLOATING PRICE: The average of the daily settlement prices for
the Prompt Month of the NYMEX Light Sweet Crude Oil Futures Contract on
the New York Mercantile Exchange for each NYMEX business day of the
Determination Period; i.e., for January 1996 the Floating Price Index
will be the NYMEX Light Sweet Crude Oil Futures Contract settlement
average for the Business Days between and including January 1, 1996
through January 31, 1996.
(l) QUANTITY MEASUREMENT: Barrel (42 U.S. Gallons).
(m) QUANTITY PER DETERMINATION PERIOD:
For the period January 1, 1996 through December 31, 1996: 8,500
Barrels per month.
For the period January 1, 1997 through December 31, 1997: 10,900
Barrels per month.
For the period January 1, 1998 through December 31, 1998: 12,500
Barrels per month.
For the period January 1, 1999 through December 31, 1999: 14,000
Barrels per month.
For the period January 1, 2000 through December 31, 2000: 14,000
Barrels per month.
(n) PAYMENT OF PREMIUM: On November 28, 1994 ("Premium Payment
Date"), the Ceiling Premium Payor shall pay to the Ceiling Premium Payee
cash in the amount of the Premium, if any, and the Floor Premium Payor
shall pay the Floor Premium Payee cash in the amount of the Floor
Premium, if any. Any such amount payable shall be subject to Section 3
hereof and shall be paid by wire transfer of immediately available funds
to a bank account designated by the relevant payee. Payment shall be
made without deduction for taxes based on the representations made in
the Master Agreement.
(o) DETERMINATION PERIOD: Each calendar month beginning with
January 1, 1996 and ending December 31, 2000. The "Period End Date"
shall be the last day of each such calendar month.
(p) FLOATING AMOUNT: The Floating Amount in respect of a
Determination Period shall be the product of (i) the Quantity Per
Determination Period and (ii) the Floating Price per Quantity
Measurement in respect of such Determination Period.
23
<PAGE>
(q) CEILING AMOUNT: The Ceiling Amount in respect of a
Determination Period shall be the product of (i) the Quantity Per
Determination Period and (ii) the Ceiling Price in respect of such
Determination Period.
(r) FLOOR AMOUNT: The Floor Amount in respect of a Determination
Period shall be the product of (i) the Quantity Per Determination Period
and (ii) the Floor Price in respect of such Determination Period.
2. PAYMENT: If for any Determination Period the Floating Amount is
greater
than the Ceiling Amount, the Floating Price Payor shall pay to the Fixed
Price Payor the amount by which the Floating Amount is greater than the
Ceiling Amount. If for any Determination Period the Floating Amount is
less than the Floor Amount, the Fixed Price Payor shall pay to the
Floating Price Payor the amount by which the Floating Amount is less
than the Floor Amount. If for any Determination Period the Floating
Amount is not greater then the Ceiling Amount and not less than the
Floor Amount, then no payment shall be due under this Agreement with
respect to such Determination Period. Any such amount payable shall be
paid by wire transfer of immediately available funds to a bank account
designated by the party to whom such payment is owed. Payment shall be
made without deduction for taxes based on the representations made in
the Master Agreement.
3. SETOFF: (a) If the Payment Dates for this transaction and any
additional swap or option transactions under the Master Agreement fall
on the same day and if each party is required to pay an amount to the
other pursuant to any such swap or option transaction on such Payment
Date, then such amounts with respect to each party shall be aggregated,
and the parties shall discharge their obligations to pay through setoff,
in which case the party, if any, owing the greater aggregate amount
shall pay to the other the difference between the amounts owed and (b)
the amount, if any, payable in respect of an Early Termination Date (as
defined in the Master Agreement) will be subject to any setoff to which
the paying party is entitled with respect to amounts due and payable to
the paying party under such additional swap or option agreements to the
extent such setoff is exercised at such party's option.
4. PAYMENT DATE: Amounts owed pursuant to Section 2 in respect of a
Determination Period shall be due and payable on or before 12:00 noon
(Central Time) on the fifth Business Day succeeding the date on which
the Floating Price is determinable. ("Payment Date"). If such amounts
are not paid when due, such overdue amounts shall bear interest for each
day until paid in full, payable on demand, at the Interest Rate on the
basis of the actual number of days elapsed, and on the basis of a year
of three hundred sixty (360) days.
5. INTEREST RATE: With respect to a non-defaulting party, the Interest
Rate shall be a per annum rate of interest equal to the prime lending
rate as may from time to time be published in The Wall Street Journal
under "Money Rates"; provided, however, that with respect to a
Defaulting Party, the Interest Rate shall be a per annum rate of
24
<PAGE>
interest equal to such prime rate plus two percent (2%) per annum;
provided further that the Interest Rate may never exceed the maximum
lawful rate.
6. SECURITY: Counterparty's obligations hereunder are secured by
Counterparty's interest in the Collateral as provided in the Security
Instruments, each as defined in that certain Loan Agreement dated August
24, 1994 between JEDI as Lender and Counterparty as Borrower as it may
have been or may be amended from time to time (the "Loan Agreement").
7. ASSIGNMENT. This section shall control over any inconsistent
provision
in the Master Agreement. This Agreement shall be binding upon and inure
to the benefit of the parties hereto and their respective successors and
permitted assigns. Neither party shall have the right to assign or
otherwise transfer any of its rights or obligations under this Agreement
(whehter by security, pledge or otherwise or any interest in this
Agreement without the prior written consent of the other party, and any
purported assignment or transfer in violation of this provision shall be
void and of no force and effect; provided, however, without
Counterparty's prior written consent, JEDI may assign, transfer, pledge
or grant a security interset in all or party of its rights and
obligations hereunder to an entity ("Eligible Assignee") that is an
Affiliate (as defined in the Master Agreement) of Enron Corp. or JEDI or
managed by Enron Corp. or one of its Affiliates or JEDI. However, the
JEDI assignment or other action referred to in the proviso of the
immediately preceding sentence hereof does not release or otherwise
affect JEDI's obligations under this Agreement unless such obligations
are released pursuant to a written release signed by counterparty at
JEDI's request, which release shall not be unreasonably withheld or
delayed by Counterparty.
8. LOAN PREPAYMENTS. In the event Counterparty makes a partial
prepayment
of the loan under the Loan Agreement, at JEDI's option, either: (a) a
portion ("Subject Portion"), as determined by Counterparty (taking into
account, among other factors, any collateral being released from the
Security Instruments, as defined in the Loan Agreement, as a result of
the prepayment), of the Quantity Per Determination Periods which remain
to occur hereunder will be deemed released from this Agreement, an Early
Termination Date will be designated as no earlier than the date of such
prepayment as to the Subject Portion by Counterparty's notice to ERMS,
and, as to the portion of the parties' obligations released and
terminated, ERMS shall calculate the amount (if any) due and owing by it
or Counterparty as a result of such release and termination, and any
such amount shall be paid, in accordance with Section 6(e) of the Master
Agreement, (b) Counterparty will assign the Subject Portion of its
rights and obligations under this Agreement to an Eligible Assignee (as
defined in Section 6 hereof), and upon such assignment the assigned
portion shall be governed by any master swap agreement between ERMS and
the Eligible Assignee and the terms hereof to the extent they are not
inconsistent with such master agreement's terms, or (c) Counterparty
will elect not to act in accordance with (a) or (b) above. In the event
25
<PAGE>
Inland makes a total prepayment of the loan under the Loan Agreement, at
Counterparty's option, it shall either act under clause (a) or (b) of
the immediately preceding sentence hereof, but in either case such
action shall relate to and affect all obligations under this Agreement
with respect to amounts that would have been payable pursuant to Section
2 as to all Determination Periods which remain to occur after the date
of such action. The portion of this Agreement that is not released by
operation of clause (a) above or assigned by operation of clause (b)
above shall continue in effect and will be governed by the terms of this
Agreement. In no event shall either party be liable to the other for
any losses such party may incur as a result of Counterparty's acts or
omissions pursuant to this Section 8.
We are pleased to have concluded this transaction with you. Please
provide
your confirmation that the foregoing accurately reflects our transaction by
signing in the space below and delivering a duly executed counterpart hereof
(which delivery shall be deemed to have been made upon hand delivery thereof
at our principal offices in Houston, Texas or upon our receipt of a facsimile
transmission of a copy thereof to our facsimile number). Your response should
reflect the appropriate person within your organization who has the authority
to enter into this transaction and should be received by JEDI no later than
5:00 p.m. Central time on the second Business Day following the date first
written above. You agree to deliver to JEDI, in the manner set forth above, a
duly executed counterpart hereof (or to notify us of any bona fide error that
would require revision in order to accurately reflect our agreement on the
transaction) by such time. If JEDI has not been notified of a bona fide error
or received a fully executed confirmation by such time in the manner set forth
above, this Agreement shall be deemed binding on Counterparty and JEDI as
sent.
26
<PAGE>
Signature Page for Confirmation Letter
for Collar Agreement between Inland
Resources Inc. and Joint Energy Development
Investments Limited Partnership dated
November 22, 1994
Ref. No. C00940.0
Yours very truly,
JOINT ENERGY DEVELOPMENT
INVESTMENTS LIMITED PARTNERSHIP
By: ENRON CAPITAL CORP., its General
Partner
By:
Name: G. Douglas Haney
Title: Vice President
CONFIRMED:
____ day of ___________, 1994.
INLAND RESOURCES INC.
By:
Name: Kyle R. Miller
Title: President and CEO
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EXHIBIT 10.2
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Enron Capital & Trade Resources Corp.
1400 Smith Street
P. O. Box 4428
Houston, Texas 77210-4428
SWAP AGREEMENT
(Collar)
TO: Inland Resources Inc. ("Counterparty")
DATE: January 18, 1995
ATTN: Kyle Miller
CONTRACT NO.: Enron Capital & Trade Resources Corp. ("ECT")
Contract No. C01086.0
We are pleased to confirm your offer and enter into the following energy
options with your company, which transaction was entered into between our
companies pursuant to a telephone conversation between Kyle Miller and Doug
Leach. In any future correspondence concerning this transaction, please refer
to the above contract number. This Swap Agreement (this "Agreement" or
"Confirmation") is a complete and binding agreement between you and us as to
the terms and conditions of the transaction to which this Agreement relates.
Upon execution by you and us of a Master Swap Agreement, this Agreement will
supplement, form a part of, and be subject to, the Master Swap Agreement.
Prior to execution by you and us of a Master Swap Agreement, this Agreement
and all other swap agreements and option agreements between you and us shall
be considered a single agreement to the same extent as if a Master Swap
Agreement had been executed.
1. TRANSACTION TERMS:
(a) CEILING PREMIUM PAYOR: ECT.
(b) CEILING PREMIUM PAYEE: Counterparty.
(c) CEILING PREMIUM: $0.
(d) FLOOR PREMIUM PAYOR: Counterparty.
(e) FLOOR PREMIUM PAYEE: ECT.
(f) FLOOR PREMIUM: $0.
(g) FIXED PRICE PAYOR: ECT.
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(h) FLOATING PRICE PAYOR: Counterparty.
(i) CEILING PRICE: U.S. Dollars $19.00 per Quantity Measurement.
(j) FLOOR PRICE: U.S. Dollars $17.00 per Quantity Measurement.
(k) FLOATING PRICE: The unweighted average of the daily settlement
prices for the prompt month of the NYMEX Light Sweet Crude Oil Futures
Contract for each business day of the Determination Period.
(l) QUANTITY MEASUREMENT: Barrels ( 42 U.S. Gallons).
(m) QUANTITY PER DETERMINATION PERIOD: 4,000 Barrels
(n) PAYMENT OF PREMIUM: On January 20, 1995 ("Premium Payment
Date"),
the Ceiling Premium Payor shall pay to the Ceiling Premium Payee cash in
the amount of the Premium, if any, and the Floor Premium Payor shall pay
the Floor Premium Payee cash in the amount of the Floor Premium, if any.
Any such amount payable shall be subject to Section 3 hereof and shall
be paid by wire transfer of immediately available funds to a bank
account designated by the relevant payee. Payment shall be made without
deduction for taxes based on the representations made in Section 6(viii)
and (ix) of this Agreement.
(o) DETERMINATION PERIOD: Each calendar month beginning with
February
1, 1995 and ending on December 31, 1995. The "Period End Date" shall be
the last day of each such calendar month.
(p) FLOATING AMOUNT: The Floating Amount in respect of a
Determination Period shall be the product of (i) the Quantity Per
Determination Period and (ii) the Floating Price per Quantity
Measurement in respect of such Determination Period.
(q) CEILING AMOUNT: The Ceiling Amount in respect of a Determination
Period shall be the product of (i) the Quantity Per Determination Period
and (ii) the Ceiling Price in respect of such Determination Period.
(r) FLOOR AMOUNT: The Floor Amount in respect of a Determination
Period shall be the product of (i) the Quantity Per Determination Period
and (ii) the Floor Price in respect of such Determination Period.
2. PAYMENT: If for any Determination Period the Floating Amount is greater
than the Ceiling Amount, the Floating Price Payor shall pay to the Fixed
Price Payor the amount by which the Floating Amount is greater than the
Ceiling Amount. If for any Determination Period the Floating Amount is
less than the Floor Amount, the Fixed Price Payor shall pay to the
Floating Price Payor the amount by which the Floating Amount is less
than the Floor Amount. If for any Determination Period the Floating
Amount is not greater than the Ceiling Amount and not less than the
Floor Amount, then no payment shall be due under this Agreement with
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respect to such Determination Period. Any such amount payable shall be
paid by wire transfer of immediately available funds to a bank account
designated by the party to whom such payment is owed. Payment shall be
made without deduction for taxes based on the representations made in
Section 6(viii) and (ix) of this Agreement.
3. SETOFF: If the Payment Dates (including any Premium Payment Date) for
two or more swap or option agreements between the parties fall on the
same day, if each party is required to pay an amount to the other on
such Payment Date, then such amounts with respect to each party shall be
aggregated, and the parties shall discharge their obligations to pay
through offset, in which case the party, if any, owing the greater
aggregate amount shall pay to the other the difference between the
amounts owed.
4. PAYMENT DATE: Amounts owed pursuant to Section 2 in respect of a
Determination Period shall be due and payable on or before 12:00 noon
(Central Time) on the fifth Business Day succeeding the day on which the
Floating Price is determinable ("Payment Date"). If such amounts are
not paid when due, such overdue amounts shall bear interest for each day
until paid in full, payable on demand, at the Interest Rate on the basis
of the actual number of days elapsed, and on the basis of a year of
three hundred sixty (360) days.
5. INTEREST RATE: With respect to a non-defaulting party, the Interest
Rate shall be a per annum rate of interest equal to the prime lending
rate as may from time to time be published in The Wall Street Journal
under "Money Rates"; provided, however, that with respect to a
Defaulting Party, the Interest Rate shall be a per annum rate of
interest equal to two percent (2%) over such prime lending rate;
provided further that the Interest Rate may never exceed the maximum
lawful rate.
6. REPRESENTATIONS: Each of ECT and Counterparty represents and warrants
to the other that: (i) solely with respect to ECT, it is a producer,
processor, or commercial user of, or a merchant handling the Commodity
which is the subject of this transaction, or the products or by-products
thereof; (ii) it is entering into this Agreement in connection with its
line of business; (iii) the execution, delivery and performance of this
Agreement have been duly authorized by all necessary corporate or other
organization action on its part; (iv) this Agreement is its legally
valid and binding obligation, enforceable against it in accordance with
its terms, except as may be limited by bankruptcy, reorganization,
moratorium or other similar laws affecting creditors' rights generally;
(v) it is acting as a principal in this Agreement and is not acting as a
broker or agent for another party; (vi) the terms of this transaction
have been individually tailored and negotiated; (vii) it constitutes an
"eligible swap participant" as such term is defined in Rule 35.1(b)(2)
of the Commodities Futures Trading Commission, 58 Fed. Reg. 5587, 5594
(January 22, 1993), to be codified in Part 35 of Chapter 1 of Title 17
of the Code of Federal Regulations; (viii) it is a United States person
(as such term is defined in Section 7701 of the Internal Revenue Code);
(ix) during the term hereof, it will not be doing business in any
jurisdiction that imposes any withholding tax or similar levy on any
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payment made or received by it under this Agreement; and (x) it has made
or will make all decisions regarding the Transaction entered into
hereunder without relying on any advice, recommendations or information
provided to it by the other party; all such decisions are the result of
arm's-length negotiations between the parties; and it has entered into
the Transaction with full understanding of all the risks thereof and is
capable of assuming and willing to assume such risks.
7. EVENT OF DEFAULT: Shall mean with respect to a party (the "Defaulting
Party"):
(a) the failure by the Defaulting Party to make, when due, any payment
required under this Agreement if such failure is not remedied on or
before two (2) Business Days after notice of such failure is given to
the Defaulting Party; or
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(b) any representation or warranty made by the Defaulting Party in
this Agreement shall prove to have been false or misleading in any
material respect when made or deemed to be repeated; or
(c) the breach by the Defaulting Party of any other covenant or
agreement set forth in this Agreement (other than the obligation to make
payment) and such failure is not cured within 10 days after notice
thereof to the Defaulting Party; or
(d) the occurrence of a bankruptcy, reorganization, moratorium or
similar insolvency event with respect to the Defaulting Party (and, if
such a proceeding is instituted against the party, it remains
undismissed for 30 days); or
(e) the occurrence of a Material Adverse Change with respect to ECT or
Counterparty and the failure of ECT or Counterparty (as the case may be)
to establish, maintain or increase the Performance Assurance (as defined
in the Confirmation) as required by Annex A and the failure continues
for two (2) Business Days after notice from the other party; or
(f) the Defaulting Party fails to establish, maintain, renew,
substitute or increase the Performance Assurance (as defined in the
Confirmation) in accordance with the terms and provisions of Annex A and
the failure continues for two (2) Business Days after notice from the
other party; or
(g) the failure in the payment when due (whether at
maturity, by acceleration, or otherwise) of any obligation in respect of
borrowed money, in an aggregate amount in excess of $500,000 with respect
to Counterparty, or $25,000,000 with respect to Enron Corp. (such event
constituting an Event of Default with respect to ECT), and the failure to
remedy the failure within any applicable grace period, or either
Counterparty or Enron Corp. fails in the performance of, or there shall
occur any other event of default (however defined) under, any agreement
in which such obligation is created, evidenced, or secured, if such
failure or event of default is not remedied within any applicable grace
period and the effect of such failure or event of default is to cause
such obligation in such an aggregate amount to become, or to permit the
holder(s) of such obligations (or a trustee or agent on behalf of such
holder(s)) to declare such obligation, due prior to its expressed
maturity; or
(h) an Event of Default under any other swap or option agreement between
the parties hereto or between Counterparty and Joint Energy Development
Investments Limited Partnership.
8. MATERIAL ADVERSE CHANGE: shall mean (a) with respect to ECT, Enron Corp.
shall have unsecured, long-term senior indebtedness not supported by
third party credit enhancement that is rated by the Standard & Poor's
Rating Group (a division of McGraw-Hill, Inc.) or its successor ("S&P")
below "BBB-"; or (b) with repsect to Counterparty, any of the following
shall occur at any time: (i) its Net Worth falls below $2,000,000; or
(ii) the raio of its Current Assets to Current Liabilities is less than
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1 to 1.
"Current Assets" shall mean current assets of Counterparty as would be
reflected on a balance sheet of Counterparty prepared in accordance witih
GAAP.
"Current Liabilities" shall mean current liabilities of Counterparty as
would be reflected on a balance sheet of Counterparty prepared in
accordance with GAAP.
"Net Worth" shall mean total assets of Counterparty (exclusive of
intangible assets and amounts attributable to notes receivable), minus
its total liabilities, each as would be reflected on a balance sheet of
Counterparty prepared in accordance with GAAP.
9. CREDIT SUPPORT AGREEMENT: Counterparty and ECT shall establish, maintain,
renew, substitute and increase Performance Assurance as (and only to the
extent) required by Annex A.
10. PERFORMANCE ASSURANCE: Shall mean one or more irrevocable, transferable
standby letters of credit (each a "Letter of Credit") from a major U.S.
commercial bank or a foreign bank with a U.S. branch office, with such
bank having a Credit Rating of at least "A-" from S&P, or "A3" from
Moody's Investors Service, Inc. or its successor ("Moody's"), such Letter
of Credit
being issued in the form of Annex B attached hereto, with only such
changes as may be required by the issuing bank and as are acceptable to
the party in whose favor the Letter of Credit is issued.
"Credit Rating" means, with respect to a party or entity on any date of
determination, the respective rating then assigned to its unsecured and
senior long-term debt or deposit obligations (not supported by third
party credit enhancement) by S&P, Moody's or the specified rating agency.
11. FINANCIAL INFORMATION: Upon written request, ECT shall deliver to
Counterparty (i) as soon as available and in any event within 120 days
after the end of Enron Corp.'s fiscal year a copy of Enron Corp.'s annual
reports containing consolidated financial statements for such fiscal year
certified by independent certified public accountants and prepared in
accordance with generally accepted accounting principles, consistently
applied ("GAAP"), (ii) as soon as available and in any event within sixty
(60) days after the end of each of Enron Corp.'s first three fiscal
quarters of each fiscal year, copies of Enron Corp.'s quarterly reports
containing unaudited consolidated financial statements for such fiscal
quarter prepared in accordance with GAAP, and (iii) such other publicly
available financial information as Counterparty may reasonably request.
Counterparty shall deliver to ECT (i) as soon as available and in any
event within 120 days after the end of its fiscal year a copy of its
annual report(s) containing consolidated financial statements for such
fiscal year certified by independent certified public accountants and
prepared in accordance with generally accepted accounting principles,
consistently applied ("GAAP"), (ii) as soon as available and in any event
within sixty (60) days after the end of each of its first three fiscal
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quarters of each fiscal year, copies of its quarterly reports containing
unaudited consolidated financial statements for such fiscal quarter
prepared in accordance with GAAP, and (iii) such other publicly available
financial information as ECT may reasonably request. Concurrently with
the furnishing of the annual and quarterly financial statements pursuant
to this Section 11, Counterparty shall deliver to ECT a Certificate of
Compliance substantially in the form set forth in Annex "C".
12. REMEDIES: If an Event of Default shall have occurred and shall be
continuing the non-defaulting party may, in its sole discretion, upon two
(2) Business Days notice to the Defaulting Party designate an early
termination date ("Early Termination Date"); provided, if an Event of
Default under Section 7(d) shall have occurred and be continuing, the
date of occurrence of such Event of Default shall be deemed to be the
Early Termination Date. On the Early Termination Date, all obligations
under this Agreement with respect to amounts which would have been
payable pursuant to Section 2 with respect to all Determination Periods
which would have ended after the Early Termination Date shall be
terminated, except as provided below.
If an Early Termination Date has been designated the non-defaulting
party shall in good faith calculate its Gains or Losses and Costs under
the Agreement resulting from the termination of the parties' obligations
with respect to all Payment Dates which would have occurred after the
Early Termination Date had the Early Termination Date not occurred. The
non-defaulting party shall aggregate the Gains, Losses and Costs so
calculated and notify the Defaulting Party of the aggregate amount. If
the non-defaulting party's aggregate Losses and Costs exceed its
aggregate Gains, the Defaulting Party shall, within five (5) days of
receipt of such notice, pay the excess to the non-defaulting party, which
amount shall bear interest at the Interest Rate from the Early
Termination Date until paid. If the non-defaulting party's aggregate
Gains exceed its Losses and Costs, if any, resulting from the Event of
Default, the non-defaulting party shall pay the excess to the Defaulting
Party on the later of (i) the Payment Date for the next succeeding
Determination Period or (ii) the date five (5) days after receipt by the
Defaulting Party of the non-defaulting party's notice given above which
amount shall bear interest at the Interest Rate from the Early
Termination Date until paid. Any notice of any amount due hereunder
shall be accompanied by a statement in reasonable detail indicating how
the relevant amount was calculated. No party shall be required to pay
incidental, consequential or indirect damages to the other party (except
to the extent that the payments required to be made pursuant to this
Agreement are deemed to be such damages). If and to the extent any
payment made pursuant to this Agreement is deemed to constitute
liquidated damages, the parties acknowledge and agree that damages are
difficult or impossible to determine and that such payment constitutes a
reasonable approximation of the amount of such damages, and not a
penalty.
As used herein:
(a) COSTS: Shall mean, with respect to a party, brokerage fees,
commissions and other similar transaction costs and expenses reasonably
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incurred by a party either in terminating any arrangement pursuant to
which the party has hedged its obligations hereunder or entering into new
arrangements which replace this Agreement.
(b) GAINS: Shall mean, with respect to a party, an amount equal to the
present value of the economic benefit, if any, to the party resulting
from the termination of parties' obligations with respect to this
Agreement, determined in a commercially reasonable manner and without
taking into account Costs.
(c) LOSSES: Shall mean, with respect to a party, an amount equal to the
present value of the economic loss, if any, (exclusive of Costs) to the
party resulting from the termination of the parties' obligations with
respect to this Agreement, determined in a commercially reasonable
manner.
13. BUSINESS DAY: Shall mean a day on which banks in Houston, Texas
or New York, New York are not authorized or required to be closed
for business.
14. TRADING DAY: Shall mean a day on which a Floating Price is
determinable.
15. GOVERNING LAW: This Agreement shall be governed by and construed
in accordance with the laws of the State of Texas, excluding
conflict of laws principles.
16. EXHIBITS and ANNEXES: All Exhibits and Annexes attached hereto,
if any, are deemed to be a part of this Agreement.
17. ASSIGNMENT: This Agreement shall be binding upon and inure to the
benefit of the parties hereto and their respective successors and
permitted assigns. Neither party shall have the power to assign
or otherwise transfer any of its rights or obligations under this
Agreement (whether by security, pledge or otherwise) or any
interest in this Agreement without the prior written consent of
the other party, and any purported assignment or transfer in
violation of this provision shall be void and of no force and
effect. Any assignment or purported assignment in violation
hereof, even though void, shall constitute a failure to perform a
covenant under this Agreement. Notwithstanding the foregoing, each
party covenants that if it attempts to assign or otherwise
transfer its rights under this Agreement (whether by security,
pledge or otherwise) or any interest in this Agreement in
violation of this provision, it will obtain from the assignee or
transferee a written agreement, for the benefit of the other party
to this Agreement, acknowledging and agreeing that such assignment
or transfer, shall not impair such other party's rights under this
Agreement, including its right of setoff under Section 3 or
otherwise.
18. (a) ADDRESS FOR NOTICES TO ECT:
Enron Capital & Trade Resources Corp.
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P. O. Box 4428
Houston, Texas 77210-4428
Attn: Director, Documentation Department
Telephone: (713) 853-3300
Fax No.: (713) 646-4816
A copy of any notice sent to ECT pursuant to Section 7, 12 or Annex A
must also be sent to the above address to: (i) Enron Capital & Trade
Resources Corp., Attention: Corporate Secretary, Fax No. (713)
853-2534, and (ii) Attention: Assistant General Counsel, Trading Group,
Fax No. (713) 646-4818.
(b) ADDRESS FOR NOTICES TO COUNTERPARTY:
Inland Resources Inc.
475 17th Street, Suite 1500
Denver, CO 80202
Attn: Kyle Miller
Telephone: (303) 292-0900
Fax No.: (303) 296-4070
We are pleased to have concluded this transaction with you. Please provide
your confirmation that the foregoing accurately reflects our transaction by
signing in the space below and delivering a duly executed counterpart hereof
(which delivery shall be deemed to have been made upon hand delivery thereof
at our principal offices in Houston, Texas or upon our receipt of a facsimile
transmission of a copy thereof to our facsimile number). Your response should
reflect the appropriate person within your organization who has the authority
to enter into this transaction and should be received by ECT no later than
5:00 p.m. Central Time on the fifth Business Day following the date first
written above. You agree to deliver to ECT, in the manner set forth above, a
duly executed counterpart hereof (or to notify us of any bona fide error that
would require revision in order to accurately reflect our agreement on the
transaction) by such time. If ECT has not been notified of a bona fide error
or received a fully executed confirmation by such time in the manner set forth
above, this Agreement shall be deemed binding on Counterparty and ECT as sent.
Yours very truly,
ENRON CAPITAL & TRADE
RESOURCES CORP.
By:
Agent and Attorney-in-Fact
Name: Enron Capital & Trade Resources
Corp.
Title:
CONFIRMED AS OF
____ day of _________, 199___.
INLAND RESOURCES INC.
By:
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Name: Kyle R. Miller
Title: President & CEO
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ANNEX A
COLLATERAL AND EXPOSURE PROVISIONS
This Annex A supplements, forms part of, and is incorporated into the
Confirmation to which it is attached. Capitalized terms not defined in the
Confirmation (including all Annexes) and used in this Annex shall have the
meanings given to them herein.
1. Certain Definitions. As used herein:
(a) "Exposure" for a Swap shall mean (1) if a payment amount under
the Confirmation (or a payment amount under any other Swap) has been
determined and is due but not yet paid, the amount of such payment,
with the party (the "Exposed Party") due and owed such amount having
Exposure to the other party (the "Non-Exposed Party") in such
amount; and (2) the Current Value of the Swap, with the party that
would be due and owed such amount from the other party having
Exposure to the other party in such amount. All calculations of
Exposure shall be done by ECT in a commercially reasonable manner.
To the extent that a Swap is covered in part by clause (1) and (2),
such Swap shall be treated as separate Swaps for purposes of these
calculations, to the extent covered by each such clause.
(b) "Exposure Threshold" shall mean, with respect to Counterparty,
$100,000, and with respect to ECT, $25,000,000; provided, however,
that the Exposure Threshold for a party shall be zero upon the
occurrence and during the continuance of a Material Adverse Change
or an Event of Default (or an event which, with the giving of notice
or the lapse of time or both would constitute an Event of Default)
with respect to such party. The Exposure Threshold assigned to a
party shall be the threshold applied to such party for all Swaps.
(c) The "Current Value" of a Swap at any time shall mean the
amount, as calculated by ECT in a reasonably commercial manner,
which a party would pay to or receive from a third party in an
arm's-length swap, as consideration for entering into a new swap at
that time in which such party holds the same position as in the
outstanding Swap, assuming that the term of such Swap encompasses
only incomplete Determination Periods and that such swap is in all
other respect identical to the outstanding Swap.
(d) "Exposure Amount" for each party shall be calculated for all
Swaps by calculating each party's Exposure to the other party in
respect of all Swaps. The party having the greater Exposure Amount
at any time (the "Exposed Party") shall be deemed to have a "Net
Exposure" to the other party (the "Non-Exposed Party") equal to the
difference between its Exposure Amount and the other party's
Exposure Amount.
(e) The "Collateral Requirement" for a Non-Exposed Party shall
mean the excess, if any, of (i) the Exposed Party's Net Exposure
over (ii) the Non-Exposed Party's Exposure Threshold plus the
remaining, undrawn portion of any outstanding Letters of Credit
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maintained by Non-Exposed Party for the benefit of Exposed Party in
connection with the Swap Agreement.
(f) "Letter of Credit" shall mean an irrevocable, transferable
standby letter of credit issued by a major U.S. commercial bank or
a foreign bank with a U.S. branch office, with such bank having a
Credit Rating of at least "A-" from S&P" or "A3" from Moody's, and
such Letter of Credit being in the form of Annex B attached hereto,
with only such changes as may be required by the issuing bank and as
are acceptable to the Non-Exposed Party.
(g) "Swaps" shall mean (i) any outstanding swap or option
agreement entered into between Counterparty and ECT prior to, on or
after the date hereof, other than the Confirmation to which this
Annex is attached, and (ii) the swap or option under the
Confirmation. "Swap" shall mean any of the Swaps.
(h) Defined terms used but not defined herein shall have the
meanings given such terms in the Confirmation to which this Annex is
attached.
2. Letters of Credit. Performance Assurance in the form of a Letter
of Credit shall be subject to the following provisions:
(a) On any Business Day, the Exposed Party may demand in writing
that the Non-Exposed Party (1) establish and maintain (subject to
increase as provided below) a Letter of Credit for the benefit of
the Exposed Party equal to the Non-Exposed Party's Collateral
Requirement, rounded up to the next higher integral multiple of
$10,000 as to Counterparty, and $1,000,000 as to ECT, or (2)
increase the principal amount of any outstanding Letter of Credit so
that after such increase the Collateral Requirement has been fully
satisfied. Within three (3) Business Days after receipt of such
demand, the Non-Exposed Party shall either establish such Letter of
Credit or increase any outstanding Letter of Credit. The
Non-Exposed Party shall increase the amount of the Letter of Credit
or establish additional Letters of Credit if the Collateral
Requirement increases and the Exposed Party demands such increased
or additional Letter of Credit in the manner provided above.
(b) Unless otherwise agreed in writing by the parties, a Letter of
Credit shall be provided in accordance with this Annex, and the
Letter of Credit shall be maintained for the benefit of the Exposed
Party. The Non-Exposed Party shall (i) renew or cause the renewal
of each outstanding Letter of Credit on a timely basis as provided
in the relevant Letter of Credit, and (ii) if the bank that issued
an outstanding Letter of Credit has indicated its intent not to
renew such Letter of Credit, then the Non-Exposed Party shall
provide a substitute Letter of Credit at least twenty (20) Business
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Days prior to the expiration of the outstanding Letter of Credit.
Furthermore, if a bank issuing a Letter of Credit shall fail to
honor the Exposed Party's properly documented request to draw on an
outstanding Letter of Credit, then the Non-Exposed Party shall
provide for the benefit of the Exposed Party a substitute Letter of
Credit that is issued by a bank, other than the bank failing to
honor the outstanding Letter of Credit, within two (2) Business Days
after such refusal.
(c) When providing Performance Assurance, the Non-Exposed Party
may increase the amount of an outstanding Letter of Credit or
establish one or more additional Letters of Credit.
(d) (i) A Letter of Credit shall provide that the Exposed Party
may draw upon the Letter of Credit in an amount that is equal to all
amounts that are due and owing from the Non-Exposed Party but have
not been paid to the Exposed Party within the time allowed for such
payments under the relevant swap agreement (including any related
notice or grace period or both). A Letter of Credit shall provide
that a drawing may be made on the Letter of Credit upon submission
to the bank issuing the Letter of Credit of one or more certificates
specifying the amounts due and owed to the Exposed Party in
accordance with the specific requirements of the Letter of Credit.
The Non-Exposed Party shall remain liable for any amount due and
owing to the Exposed Party and remaining unpaid after the
application of the amounts so drawn by the Exposed Party.
(ii) If the Non-Exposed Party shall fail to establish, renew,
substitute, or sufficiently increase the amount of (as the case may
be) one or more Letters of Credit, then the Exposed Party may draw
on the entire, undrawn portion of any outstanding Letter of Credit
upon submission to the bank issuing such Letter of Credit of one or
more certificates specifying the amounts due and owed to the Exposed
Party in accordance with the specific requirements of the Letter of
Credit. The Non-Exposed Party shall remain liable for any amounts
due and owing to the Exposed Party and remaining unpaid after the
application of the amounts so drawn by the Exposed Party.
(e) Upon or at any time after the occurrence or deemed occurrence
of an Event of Default with respect to the Non-Exposed Party or
Early Termination Date as a result of an Event of Default and the
failure of the Non-Exposed Party to make all payments due and owing
to the Exposed Party in accordance with the terms of the relevant
swap or option agreement (including any related grace or notice
period or both), the Exposed Party may draw on any outstanding
Letter of Credit in an amount equal to such amounts owed to it. The
Non-Exposed Party shall remain liable for any amounts owed to the
Exposed Party and remaining unpaid after the application of the
amounts so drawn by the Exposed Party.
(f) The Non-Exposed Party may substitute a Letter of Credit for
one or more other outstanding Letter(s) of Credit issued for the
benefit of the Exposed Party, provided that the amount of such
substitute Letter of Credit shall be at least equal to that of the
Letter(s) of Credit being replaced (determined in good faith and in
a commercially reasonable manner by the Exposed Party), and provided
further that no Letter of Credit shall be canceled unless and until
the Letter of Credit to be substituted therefor shall have been
validly executed and issued for the benefit of the Exposed Party in
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accordance with applicable law.
(g) In all cases, the costs and expenses (including but not
limited to the reasonable costs, expenses, and attorneys' fees of
the Exposed Party) of establishing, renewing, substituting,
canceling, and increasing the amount of (as the case may be) one or
more Letters of Credit shall be borne by the Non-Exposed Party.
3. Additional Representation. Each party continuously represents
and warrants to the other party that on each occasion that it, as
the Non-Exposed Party, causes the issuance, renewal, substitution,
or increase (as the case may be) of a Letter of Credit, such
Letter of Credit will be the legal, valid, and binding obligation
of the issuer thereof, enforceable in accordance with its terms.
42
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ANNEX B
IRREVOCABLE TRANSFERABLE STANDBY LETTER OF CREDIT FORMAT
AMOUNT: UP TO THE MAXIMUM AMOUNT OF UNITED STATES
$___________________
DATE OF ISSUANCE: _____________________
________________________
________________________
________________________
Re: Credit No. _________________
Gentlemen:
We hereby establish our Irrevocable Transferable Standby Letter of
Credit in your for the account of ________________________ (the "Account
Party"), for the aggregate amount not exceeding ____________________ United
States Dollars ($_______________), available to you on or before the
expiration hereof against presentation to us of the Drawing Documents (as
defined herein):
A sight draft, in the form attached hereto as Annex B-1, presented by
you during business hours on any business day at [list office(s), branch(es),
other location(s)] with notation that the same is drawn under this Letter of
Credit, identifying the same by number, and accompanied by any one or more of
the following additional documents (collectively, the "Drawing Documents"):
(a) a completed certificate, in the form attached hereto as Annex B-2,
signed by a person purporting to be an officer or authorized agent of you or
your transferee and dated the date of presentation; or
(b) a completed certificate, in the form attached hereto as Annex B-3,
signed by a person purporting to be an officer or authorized agent of you or
your transferee and dated the date of presentation.
The amount which may be drawn by you under this Letter of Credit shall
be automatically reduced by the amount of any drawing hereunder. Any number
of partial drawings are permitted from time to time hereunder.
This Letter of Credit shall expire ___________________ (_____) days from
43
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the date of issuance, but shall automatically extend without amendment for
additional ______________________ (_______)-day periods from such expiration
date and from subsequent expiration dates, if you, as beneficiary, and the
Account Party have not received due notice of our intention not to renew
ninety (90) days prior to any such expiration date.
We hereby engage with you that documents drawn under and in compliance
with the terms of this Letter of Credit shall be duly honored upon
presentation as specified.
This Letter of Credit does not incorporate, and shall not be deemed
modified, amended, or amplified by reference to, any document, instrument or
agreement (a) that is referred to herein (except for the UCP, as defined
below), or (b) in which this Letter of Credit is referred to or to which this
Letter of Credit relates.
This Letter of Credit is transferable at our counters in [New York]
only to the parent company or an affiliate of ______________________.
Transfer of this Letter of Credit shall be effected by the presentation to us
of this Letter of Credit accompanied by [Bank's] specific transfer application
in the form attached hereto as Annex B-4.
This Letter of Credit shall be governed by the Uniform Customs and
Practices for Documentary Credits, 1993 Revision, International Chamber of
Commerce Publication No. 500 (the "UCP"), except to the extent that the terms
hereof are inconsistent with the provisions of the UCP, including but not
limited to Articles 13(b) and 17 of the UCP, in which case the terms of this
Letter of Credit shall govern.
In the event of an Act of God, riot, civil commotion, insurrection,
war, strike, lockout or any other cause beyond our control that interrupts our
business (collectively, an "Interruption Event"), our obligations under this
Letter of Credit will merely be suspended until such time as the Interruption
Event has ended, regardless of whether this Letter of Credit would have
expired (in accordance with the fifth preceding paragraph of this Letter of
Credit or otherwise) during the continuance of such Interruption Event. If an
Interruption Event occurs which suspends our obligations to you under this
Letter of Credit and this Letter of Credit would have expired (in accordance
with the fifth preceding paragraph of this Letter of Credit or otherwise)
during the continuance of such Interruption Event, then our obligations to you
under this Letter of Credit shall continue until the earlier of (i) the
termination of all outstanding transactions entered into pursuant to the Swap
Agreement, dated as of [ ], by and between you and the Account Party and
the payment in full to you of all amounts that the Account Party owes, or will
owe, to you in respect of such transactions, or (ii) the passing of a number
of days, after the cessation of such Interruption Event, equal to the number
of days that such Interruption Event existed. In addition, we will
make a good-faith effort to perform our obligations hereunder during the
continuance of an Interruption Event.
This Letter of Credit may not be amended, changed or modified without
the express written consent of you or your transferee (as beneficiary), us and
the Account Party.
Notices concerning this Letter of Credit may be sent to a party by
courier, certified mail, registered mail, telegram, telex, facsimile, or
similar communications facility, to its respective address set forth below or
such other address as may hereafter be furnished by such party to the other
parties by like notice. All such notices and communications shall be
effective when actually received by the intended recipient party.
If to the beneficiary of this Letter of Credit or its transferee:
[Name]
[Address]
44
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[City, State Zip Code]
Telex No.: Answerback:
If to the Account Party:
[Name]
[Address]
[City, State Zip Code]
Telex No.: Answerback:
45
<PAGE>
If to [Bank]:
[Name]
[Address]
[City, State Zip Code]
Telex No.: Answerback:
[BANK]
By:
Name:
Title:
46
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ANNEX B-1
To That Certain
Irrevocable Transferable Standby
Letter of Credit Format
[Attach a sample sight draft acceptable to the bank
issuing the Letter of Credit]
ANNEX B-2
To That Certain
Irrevocable Transferable Standby
Letter of Credit Format
CERTIFICATE
The undersigned hereby certifies to [BANK] ("Bank"), with reference to
Irrevocable Transferable Standby Letter of Credit No. ________________ issued
by Bank in favor of _________________________________ (together with its
parent company or any affiliate as transferee under the Letter of Credit,
called "Beneficiary"), that because Bank has notified Beneficiary that Bank
does not intend to renew the Letter of Credit, and __________________ has not
provided a substitute Letter of Credit or alternate security in accordance
with the terms and provisions (including any applicable notice or grace period
or both) of the Swap Agreement dated as of _______________, 19___, between
Enron Capital & Trade Resources Corp. or its nominee affiliate and Inland
Resources Inc., as the same may have been amended, Beneficiary is drawing upon
the Letter of Credit in an amount equal to the remaining undrawn portion of
the Letter of Credit as of the date of this Certificate.
Name of Beneficiary:
By:
Name:
Title:
, 19
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ANNEX B-3
To That Certain
Irrevocable Transferable Standby
Letter of Credit Format
CERTIFICATE
The undersigned hereby certifies to [BANK] ("Bank"), with reference to
Irrevocable Transferable Standby Letter of Credit No. ______________ issued
by Bank in favor of __________________________________, (together with its
parent company or any affiliate as transferee under the Letter of Credit,
called "Beneficiary"), that the Account Party has failed to pay Beneficiary in
accordance with the terms and provisions (including any applicable notice or
grace period or both) of the Swap Agreement dated as of ________________,
199___(the "Contract") between Inland Resources Inc. and Enron Capital & Trade
Resources Corp. or its nominee affiliate, and thus Beneficiary is drawing upon
the Letter of Credit in an amount equal to $ .
Name of Beneficiary:
By:
Name:
Title:
_____________________, 199___
ANNEX B-4
To That Certain
Irrevocable Transferable Standby
Letter of Credit Format
[Attach a copy of the specific transfer application acceptable
to the bank issuing the Letter of Credit]
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ANNEX C
FORM OF COMPLIANCE CERTIFICATE
___________________, 199__
Enron Capital & Trade Resources Corp.
Attn: ECT Credit Department
1400 Smith Street
Houston, Texas 77002
Re: Swap Agreement dated _________________, 1995 (the "Agreement") by
and between Enron Capital & Trade Resources
Corp. ("ECT") and Inland Resources Inc.
("Counterparty")
Gentlemen:
Pursuant to applicable requirements of the Agreement, the Counterparty,
____________ by and through the undersigned, hereby certifies to you the
following information as true and correct as of the date hereof or for the
period indicated, as the case may be:
The compliance, as of the close of business on __________________, with the
financial covenants contained in the Agreement is evidenced by the following:
Counterparty
(a) Minimum Net Worth:
Required Actual
Not less than $2,000,000 $_______________
(b) Ratio of Current Assets to Current Liabilities:
Required Actual
Not less than 1 to 1 __ to __
(c) There has occurred no Material Adverse Change (as defined in the
Agreement) with respect to Counterparty since the date of the financial
statements enclosed or the most recent financial statements previously
submitted to ECT, as the case may be. As of the date hereof, no Event of
Default (or event which, with the giving of notice or the passage of time or
both would be an Event of Default) has occurred and is continuing with respect
to Counterparty.
(d) Counterparty hereby delivers to ECT with this certificate the
following reports required by Section 11 of the Agreement, including:
[CHECK AS APPLICABLE]
__________________ quarterly unaudited financial statements of
Counterparty as required by Section 11 of the Agreement, which the undersigned
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officer certifies as being true and correct and prepared in accordance with
GAAP consistently applied, subject to changes resulting from year-end audit
adjustments.
___________________ annual audited financial statements of Counterparty
as required by Section 11 of the Agreement, which the undersigned officer
certifies as being true and correct and prepared in accordance with GAAP.
INLAND RESOURCES INC.
By:
Title:
Name:
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EXHIBIT 10.3
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FARMOUT AGREEMENT
I. PARTIES
Inland Production Company
475 17th Street, Suite 1500
Denver, Colorado 80202
and
Inland Resources Inc.
475 17th Street, Suite 1500
Denver, Colorado 80202
Herein collectively "Farmor"
Randall D. Smith
885 3rd Avenue, 34th Floor
New York, New York 10022
Herein "Farmee"
and
Inland Production Company
475 17th Street, Suite 1500
Denver, Colorado 80202
Herein "Operator"
II. CONTRACT AREA AND EARNED DRILLSITES
The Farmor agrees to farmout, and Farmee agrees to farmin, a number of
drilling and injection well locations within the area of land described on
Exhibit A attached hereto and made a part hereof and which is referred to
herein as the "Contract Area".
Each well drilled pursuant to this agreement shall be located within a
mutually selected 40-acre drillsite spacing unit within the Contract Area. At
such time as a well is drilled on a 40-acre drillsite spacing unit, and
whether completed as a dry hole or as a well capable of producing oil and/or
gas and associated hydrocarbons in paying quantities or as an injection well,
such 40-acre drillsite spacing unit will be thereafter referred to herein as
an "Earned Drillsite".
III. FARMOUT OPERATIONS
Upon his execution hereof, Farmee shall be deemed to have allocated the
sum of $6,600,000.00 (the Allocated Sum ) to the drilling program
contemplated hereby. These monies shall be used by Operator to pay all of
Farmee's costs associated with drilling, completing, and equipping wells
within drillsite spacing units, whether such wells are completed as dry holes,
wells capable of producing hydrocarbons in paying quantities, or as injection
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wells that benefit lands within the Contract Area.
The drilling program contemplated by this agreement shall begin on July
1, 1995, and is anticipated to be completed by December 31, 1995. All wells
commenced during 1995 for the account of Farmee shall be completed in a good
and workmanlike manner even if the completion of such wells causes the total
expenditures of the program to exceed the Allocated Sum.
It is anticipated that Operator shall bill Farmee on a monthly basis in
the approximate sum of $1,100,000.00 per month beginning July 1, 1995. The
billings shall require pre-payment for expenses estimated to be incurred
during that month, and any funds not expended from a prior month's billing and
payment shall be credited in the next ensuing month's invoice such that if
there are dollars to be carried forward from July, 1995 to August, 1995, then
the billing for August, 1995, shall be the difference between $1,100,000.00,
and the surplus funds from July. Each month's billings shall be conducted
likewise, with all prior month's surplus rolling forward to the next ensuing
billing. Each month's billing shall be paid by Farmee to Farmor by wire
transfer within five (5) business days of Farmee's receipt of such billing.
For each well to be drilled pursuant to this agreement, the Operator
will be entitled to a "supervisory fee" in the amount of $25,000.00,
proportionately reduced to Farmor's working interest ownership in the
drillsite spacing unit upon which the well is located. It is understood and
acknowledged that Farmee does not have land, geological, engineering and oil
and gas accounting staff currently on hand, and thus, Farmee desires these
services to be provided by Operator for Farmee's benefit. Farmor's
supervisory services shall include all land, geological, engineering and
accounting services required to initiate, complete and account for the
operations contemplated hereby, The supervisory fee will be payable when a
well reaches its total objective depth, and will be in lieu of, and not in
addition to, the COPAS drilling rate charges customarily allowed an operator
pursuant to a joint operating agreement.
All funds paid by Farmee shall be maintained in a segregated account and
Operator will maintain appropriate cash basis accounting records pertaining
thereto. Operator shall reconcile this account monthly and submit such
reconciliation to Farmee on or before the 15th of the next ensuing month.
Account funds shall be used only for the purposes set forth in this agreement.
Any unexpended funds remaining as of January 1, 1996 shall be promptly
returned to Farmee unless there are drilling, completion, or equipping
activities which are still ongoing as of January 1, 1996. In such event, these
activities will be wound up in the ordinary course of business, and any excess
funds remaining thereafter shall be promptly returned to Farmee, together with
a final reconciliation.
IV. RIGHTS EARNED
A. Assignments
Prior to the commencement of operations for any well that will
potentially result in an Earned Drillsite, Farmor will assign to Farmee 100%
of Farmor's interest in the drillsite spacing unit from the surface of the
earth to the base of the Green River formation. Assignments will be made
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without warranty of title, either express or implied, except by, through, and
under Farmor, but not otherwise. If, for any reason, this well is either not
drilled, or does not result in Farmee obtaining an Earned Drillsite, then
Farmee agrees to reassign his entire interest in this affected acreage to
Farmor.
B. After Payout Reversion
As to each lease on which there exists one or more Earned
Drillsites, at such time as the interest of Farmee in such lease has reached
Payout as hereinafter defined, Farmee shall reconvey all of his interest in
the affected lease as received from Farmor, back to Farmor, or either of them,
in their respective percentage share of ownership. "Payout" as used herein
shall mean that point in time when Farmee has recovered from production
attributable to his net working interest in the affected lease 100% of his
cost of drilling, testing, completing, equipping, and producing and operating
the well or wells located on the affected lease during the Payout period.
Such costs shall also include supervisory fees and applicable severance and
production taxes, plus an additional sum equal to an annual 22% rate of return
on all the sums spent by Farmee and attributable to this lease during the
Payout period. The rate of return and status of Payout shall be calculated
monthly. Payout shall be effective the first day of the month following the
occurrence of Payout.
V. ACCESS TO INFORMATION
Farmee and his representatives will have free access at their own risk
to the Contract Area and drillsite spacing, and will have the right to inspect
and make copies of all information and records pertaining to the operations
conducted hereunder. Additionally, Operator will furnish by telephone,
telecopier or mail, as the case may be: daily drilling reports, copies of all
electrical survey logs and other logs which may be taken during the course of
drilling or testing; and copies of results of all tests run.
VI. DELAY RENTALS AND SHUT-IN WELL PAYMENTS
During the term of this agreement, Operator will make a bona fide effort
to pay the annual delay rentals that may come due on any lease affecting the
Contract Area, but Operator will not be liable for any loss resulting from a
"good faith" failure to pay said rentals, or for improper payment through
clerical oversight. If a rental is due and paid by Operator regarding any
lease affecting one or more Earned Drillsites, Farmee shall reimburse Operator
for such rental in accordance with his working interest in said lease.
In the event any well is completed on an Earned Drillsite as a gas well,
as determined by state or federal regulatory authorities, and if the well is
shut-in for any reason allowed by the affected oil and gas lease(s), Operator
will make such shut-in royalty payments as are necessary under the terms of
the affected oil and gas lease(s) necessary to keep such lease(s) in force and
effect, and Farmee shall reimburse Operator for such payments in accordance
with the working interest then owned by Farmee in the affected Earned
Drillsite.
VII. OPERATING AGREEMENT
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Each well drilled in accordance with this agreement shall be drilled
pursuant to a joint operating agreement. If no agreement exists as to an
intended drillsite spacing unit, then the parties will execute, and operations
will be conducted in accordance with, the AAPL 1989 Model Form Operating
Agreement attached hereto and made a part hereof as Exhibit B. In the event a
joint operating agreement already exists as to an intended drillsite spacing
unit, then Farmee will be subject to the terms and conditions thereof and, if
appropriate, will become a party thereto. Should Farmee fail or refuse to
become a party thereto, Farmee hereby appoints Operator as his agent and
attorney-in-fact to execute such agreement on his behalf, providing the terms
and conditions thereof do not differ substantially from those set forth in the
model agreement at Exhibit B.
If there exists any conflict between the provisions of this agreement
and those of any existing or future joint operating agreement, then as between
Farmor, Farmee, and Operator, the provisions of this agreement shall control.
VIII. INDEMNIFICATION
Operator will indemnify and hold Farmee harmless from and against any
and all claims of any nature whatsoever, including personal injury and death,
and including reasonable attorney's fees and costs, and whether such claims
are based on negligence or otherwise, in connection with Operator's operations
on the Contract Area.
Farmor and Operator shall keep Earned Drillsites free and clear of liens
and encumbrances of every kind or character. Farmee shall keep Earned
Drillsites free and clear of liens and encumbrances of every kind or
character, unless approved in writing by Farmor which consent shall not be
unreasonably withheld.
IX. TERM
This agreement shall remain in full force and effect until the close of
business on December 31, 1995, unless otherwise extended, or previously
terminated, in accordance with the terms hereof. The parties intend that
operations under this farmout agreement shall be diligently carried out until
substantially all of the Allocated Sum shall have been expended. However, in
the event either Farmor or Farmee shall elect at any time to curtail or
terminate further drilling operations, then the electing party shall so notify
the other party in writing, and thereafter the operations shall be wound down
in a businesslike manner. No liability shall accrue to either party as a
result of having elected to curtail or terminate early.
X. BONDING
The costs of any bonds that Farmee is required to obtain shall be borne
solely by Farmee, but allocated as additional drilling costs. To the extent
possible, Farmee will be joined on either Farmor's or Operator's bonds that
are now in existence.
XI. REASSIGNMENT
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If, during the time that Farmee owns an interest in an Earned Drillsite,
Farmee elects to surrender, let expire, abandon, or release all or any part of
his rights in an Earned Drillsite, Farmee will notify Farmor not less than
sixty (60) days in advance of such surrender, expiry, abandonment, or release.
At Farmor's request, Farmee will then immediately reassign his rights in such
affected Earned Drillsite to Farmor and, upon receipt of that reassignment,
Farmor will pay Farmee the reasonable salvage value of any material or
equipment received.
XII. GENERAL
A. Notice
Any notice required under the terms of this agreement will be
given to Farmor, Farmee, and/or Operator at the addresses and telephone and
fax numbers listed in the joint operating agreement attached as Exhibit A.
B. Inurement
This agreement is binding upon the successors and assigns of the
parties; however, it is personal in nature and may not be assigned by Farmee
without the prior written consent of Farmor, which consent will not be
unreasonably withheld.
C. Entire Agreement
This agreement constitutes the entire agreement by and between the
parties, and may not be modified except by a written instrument signed by all
parties hereto.
D. Governing Laws
This agreement shall be governed by the laws of the state of
Colorado, except that any real property issue shall be governed by the laws of
the state where such property is located. Venue for any action involving this
agreement shall exclusively lie in the District Court for the City and County
of Denver, Colorado.
This agreement is dated the date of acknowledgment for each of the
undersigned, effective July 1, 1995, at Denver, Colorado.
FARMOR:
INLAND PRODUCTION COMPANY
ATTEST:
______________________ By:
Secretary President
INLAND RESOURCES INC.
ATTEST:
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__________________________ By:
Secretary President
FARMEE:
__________________________________
Randall D. Smith
OPERATOR:
INLAND PRODUCTION COMPANY
ATTEST:
_____________________________ By:
Secretary President
STATE OF COLORADO )
)ss.
CITY AND COUNTY OF DENVER )
The foregoing instrument was acknowledged before me this ___ day of
______________________, 1995, by __________________________, _______
President of INLAND PRODUCTION COMPANY, a ________________ corporation.
Witness my hand and official seal.
(SEAL)
______________________________________
Notary Public
My commission expires:
______________________
STATE OF COLORADO )
)ss.
CITY AND COUNTY OF DENVER )
The foregoing instrument was acknowledged before me this ___ day of
______________________, 1995, by __________________________, _______ President
of INLAND RESOURCES INC., a ________________ corporation.
Witness my hand and official seal.
(SEAL)
______________________________________
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Notary Public
My commission expires:
_____________________________
STATE OF ____________________ )
)ss.
COUNTY OF ___________________ )
The foregoing instrument was acknowledged before me this ___ day of
______________________, 1995, by RANDALL D. SMITH.
Witness my hand and official seal.
(SEAL)
______________________________________
Notary Public
My commission expires:
_______________________________
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EXHIBIT 10.4
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DEFERRED COMPENSATION AGREEMENT
This Deferred Compensation Agreement ("Agreement") is entered effective
July 1, 1995 by and between JOHN D. LOMAX ("Lomax") and INLAND RESOURCES INC.
("Inland").
WHEREAS, Lomax and Inland entered into an Employment Agreement dated
effective September 21, 1994; and
WHEREAS, Inland desires to terminate such Employment Agreement pursuant
to the provisions of Section 2.7 thereof; and
WHEREAS, upon the effective date of this Agreement, the Employment
Agreement shall be deemed terminated and superseded in its entirety, except
that Sections 4 and 7 thereof shall survive such termination.
NOW, THEREFORE, in consideration of the foregoing recitals and the
mutual covenants and agreements set forth herein, together with other good and
valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the parties hereto agree as follows:
1. Effective as of the effective date of this Agreement, the
Employment Agreement is terminated and of no further force or effect, except
that the parties hereto expressly acknowledge and agree that Sections 4 and 7
of the Employment Agreement shall not be superseded by this Agreement and
shall survive termination of the Employment Agreement as provided in said
Sections 4 and 7.
2. Inland hereby agrees to make deferred severance payments to Lomax
in the aggregate amount of $142,205, payable as follows: $2,205 to be paid on
July 7, 1995, with the balance of $140,000 to be paid at the rate of $70,000
per year, commencing July 21, 1995, in twenty-six equal payments per year of
$2,692.31 each, payable in accordance with the regular bi-weekly payroll
schedule of Inland. Inland will deduct and remit the employee portion of any
payroll taxes from the gross amount of each check.
3. Inland agrees to continue to retain Lomax on its current or any
subsequent health insurance plan and pay Lomax's health insurance premiums
through June 30, 1996. After that date, Lomax may apply for COBRA coverage as
allowed by law.
4. The parties hereto agree that unless Lomax notifies Inland in
writing to the contrary, Inland will continue to deduct 401(k) contributions
by Lomax, and match those contributions, during the term of this Agreement.
5. Inland agrees to continue to maintain, until July 1, 1996, a term
life insurance policy on the life of Lomax with a $100,000 death benefit to
the beneficiary of Lomax, as designated by Lomax.
6. Inland hereby transfers to Lomax ownership of the following
equipment located in Laguna Beach, California: (i) a "D" size digitizer tablet
with four button pack, (ii) a Houston instrument DPM-61 plotter, (iii) a MV
Mp-6A Multipen module, and (iv) a H/P C1750A Scanjet IIc printer.
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7. In addition to the above payments, Inland further agrees to pay an
additional $1,500 on Lomax's check payable July 21, 1995 to cover payments
under Sections 2.3 of the Employment Agreement, such $1,500 payment to be
reduced by any applicable employee payroll taxes as well.
8. Each of the parties hereto represents and warrants to the other
party hereto that:
(a) Such party has full legal power and authority to enter into and
perform this Agreement and the consummation of the transactions contemplated
by this Agreement in accordance with its terms will not result in the breach
or termination of any provision of or constitute a default under any contract,
agreement, instrument or other document to which such party is a party or by
which such party or any of such party's property may be bound.
(b) Each party that is a corporation is a corporation duly
organized, validly existing and in good standing under the laws of its state
of incorporation and is duly authorized under applicable state and federal
laws to conduct its business as heretofore conducted, and has all requisite
corporate power and authority to own, lease and operate its properties and
carry on its business as now being conducted; and the person signing this
Agreement on behalf of such party has been duly authorized to sign this
Agreement and any further agreements or instruments referenced herein.
(c) This Agreement has been duly executed by, and constitutes a
legal, valid and binding obligation of such party, enforceable in accordance
with its terms, except as such enforceability may be limited by bankruptcy,
moratorium, insolvency or similar laws of general application affecting
enforcement of rights of creditors and by general equity principles,
including, but not limited to, those restricting specific enforcement.
9. This Agreement may be executed in any number of counterparts, each
and all of which shall be deemed for all purposes to be one agreement, and
shall be binding upon and inure to the benefit of each of the parties
hereto and their respective successors and assigns. This Agreement contains
the entire agreement between the parties hereto with respect to the
transactions contemplated herein, and cannot be amended without the written
consent of the parties hereto. This Agreement shall be governed by and
construed in accordance with the laws of the State of Texas. The headings in
this Agreement are intended solely for convenience of reference and shall be
given no effect in the construction or interpretation of this Agreement.
10. In the event this Agreement or the breach thereof gives rise to any
litigation between the parties hereto, the prevailing party in such litigation
shall be entitled to have and recover from the losing party costs of such
litigation, including reasonable attorneys' fees, as may be determined by the
court and judgment for the recovery of such cost, including attorneys' fees,
shall be included in any final judgment or decree entered by the court where
such litigation is brought.
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EXECUTED to be effective as of the effective date first set forth above.
INLAND RESOURCES INC.
By: ______________________________
Kyle R. Miller, President
____________________________________
John D. Lomax
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