United States
Securities and Exchange Commission
Washington, D. C. 20549
Form 10-Q
(Mark one)
[X] Quarterly Report Under Section 13 or 15 (d) of the Securities Exchange
Act of 1934 For the Quarterly Period Ended June 30, 1999
[ ] Transition Report Under Section 13 or 15 (d) of the Securities Exchange
Act of 1934 For the Transition Period from .......... to ..........
Commission File Number..........1-12508
MAGNUM HUNTER RESOURCES, INC.
Exact name of registrant as specified in its charter
Nevada 87-0462881
State or other jurisdiction of IRS employer identification No.
incorporation or organization
600 East Las Colinas Blvd., Suite 1200, Irving, Texas 75039
Address of principal executive offices
(972) 401-0752
Registrant's telephone number, including area code
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 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 X No
State the number of shares outstanding of each of the issuer's classes of common
equity, as of June 30, 1999: 20,107,877.
<PAGE>
PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements
The consolidated financial statements of Magnum Hunter Resources, Inc.
("Magnum Hunter"or the "Company") follow "Item 2. Management's Discussion and
Analysis of Financial Condition and Results of Operation".
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operation
The following discussion and analysis should be read in conjunction with
Magnum Hunter's consolidated financial statements and the notes associated with
them contained in its Form 10-K for the year ended December 31, 1998. This
discussion should not be construed to imply that the results discussed herein
will necessarily continue into the future or that any conclusion reached herein
will necessarily be indicative of actual operating results in the future. Such
discussion represents only the best present assessment by management of Magnum
Hunter.
On May 29, 1997, the Company placed, through a Rule 144A private placement
offering, $140 million in Senior Notes due 2007. The Notes have a 10% coupon,
with interest payable on June 1 and December 1, which commenced on December 1,
1997. Except for Bluebird Energy, Inc. ("Bluebird"), the Company's 100% owned
subsidiary formed in December 1998, there is no restriction on the ability of
any consolidated or unconsolidated subsidiary to transfer funds to the Company
in the form of cash dividends, loans or advances.
On January 28, 1998, the Company commenced a cash purchase offer for Units
of TEL Offshore Trust ("TEL"). Previous to the offer, the Company owned 161,500
Units representing 3.4% of the Units outstanding. As amended, the offer was to
purchase between forty percent (40%) and sixty percent (60%) of the Trust's
outstanding Units at $5.50 per Unit. On March 27, 1998, the Company purchased
1,745,353 Units for $10.4 million pursuant to the tender offer and, together
with the Units it previously owned, became the owner of approximately 40% of the
total number of Units outstanding.
On December 31, 1998, the Company through its newly formed 100% owned
subsidiary, Bluebird, acquired from Spirit Energy 76 ("Spirit 76") natural gas
reserves and associated assets in producing fields located in Oklahoma and Texas
currently producing approximately 12 million cubic feet of natural gas
equivalent per day. The net purchase price was approximately $25 million after
certain purchase price adjustments, including preferential rights exercised by
third parties and other customary adjustments. As part of the capitalization of
Bluebird, the Company contributed 1,840,271 units of TEL Offshore Trust.
Bluebird, as an "unrestricted subsidiary" as defined under certain credit
agreements, is neither a guarantor of the Company's 10% Senior Notes due 2007
nor can it be included in determining compliance with certain financial
covenants under the Company's credit agreements. To finance the Spirit 76
acquisition, Bluebird borrowed $26 million under a bridge loan facility with
several banks. The bridge loan was replaced on June 7, 1999 with permanent
financing from banks providing for a revolving credit facility of $75 million
with an initial borrowing base of $41.5 million, due three years from June 7,
1999 with interest rates based upon either "LIBOR" or "Base Rate" (Prime). The
loan is non-recourse to the Company. In addition to retiring the bridge loan, a
portion of the proceeds from the permanent financing was used to finance the
acquisition of properties from Vastar Resources, Inc. ("Vastar") discussed
below.
On February 3, 1999, the Company sold $50 million of its Convertible
Preferred Stock in a private placement. The Preferred Stock has a liquidation
value of $50 million and is convertible into the Company's common stock at $5.25
per share. Dividends on the preferred stock are payable in cash at the rate of
8% per annum and are cumulative. The Company used the net proceeds from the
transaction, approximately $46.3 million, to repay senior bank indebtedness.
On June 8, 1999, the Company acquired oil and gas reserves and related
assets from Vastar for a total purchase price of $32.5 million after purchase
price adjustments. The effective date of the acquisition was April 1, 1999. The
acquisition included Vastar's interest in 476 wells, a gas processing plant and
two gas gathering systems located in the states of Texas, Oklahoma and Arkansas.
2
<PAGE>
The Company uses the full cost method of accounting for its investment in
oil and gas properties. Under the full cost method of accounting, all costs of
acquisition, exploration and development of oil and gas reserves are capitalized
into a "full cost pool" as incurred, and properties in the pool are depleted and
charged to operations using the unit-of-production method based on the ratio of
current production to total proved oil and gas reserves. To the extent that such
capitalized costs (net of accumulated depreciation, depletion and amortization)
less deferred taxes exceed the SEC PV-10 of estimated future net cash flow from
proved reserves of oil and gas, and the lower of cost or fair value of unproved
properties after income tax effects, such excess costs are charged to
operations. Once incurred, a write-down of oil and gas properties is not
reversible at a later date even if oil or gas prices increase. The Company's SEC
PV-10 property valuation at June 30, 1999 exceeded the capitalized costs at that
date. Significant downward revisions of quantity estimates or declines in oil
and gas prices, which are not offset by other factors, could possibly result in
write-down for impairment of oil and gas properties in the future.
Results of Operations for the Three Month Periods in 1999 and 1998
The results of operations for the three month period ended June 30, 1999,
included three months of operations for Spirit 76 and one month of operations
for Vastar, while the corresponding period in 1998 did not include any results
of operations from these acquisitions. Unless otherwise stated, the increases in
the 1999 interim period over the 1998 period were substantially the result of
these acquisitions as well as the Company's drilling activities during the
remainder of 1998.
Oil and natural gas sales were $13,367,000, a 16% increase over 1998 sales
of $11,509,000. The Company sold 298,000 barrels of oil, a six percent increase
over 1998 sales of 281,000 barrels, and 4,594,000 Mcf of gas, a 31% increase
over 1998 sales of 3,496,000 Mcf. The price received for oil was $14.40 per
barrel and for natural gas was $1.98 per Mcf in 1999 versus an oil price of
$13.21 per barrel and a gas price of $2.08 per Mcf in 1998, representing a nine
percent increase in oil price and a five percent decrease in gas price. Oil and
natural gas production lifting costs increased 20% to $3,624,000 in 1999 versus
$3,012,000 in 1998 while production taxes and other costs decreased eight
percent to $1,712,000 in 1999 from $1,864,000 in 1998. The gross operating
margin from oil and natural gas production was $8,031,000 in 1999, a 21%
increase over 1998 operating margin of $6,633,000. On an equivalent unit basis,
the gross margin was $1.26 per Mcfe in 1999 versus $1.18 in 1998, a seven
percent increase. The sales price declined one percent to $2.10 per Mcfe in 1999
versus $2.12 per Mcfe in 1998 while production lifting costs decreased to $0.57
per Mcfe in 1999 from $0.58 per Mcfe in 1998, a two percent decrease. Production
taxes and other costs, including overhead, were $0.27 per Mcfe in 1999 versus
$0.36 per Mcfe in 1998, a 25% decrease. Total Mcfe sold increased 23% to
6,380,000 Mcfe in 1999 from 5,183,000 Mcfe in 1998.
Gas gathering, marketing, and processing revenues were $1,851,000 in the
1999 period, a 24% increase from 1998 revenues of $1,491,000, principally as a
result of an increase in processing throughput and in natural gas liquids
prices. Costs from these activities were $1,306,000 in 1999, a one percent
increase over 1998 costs of $1,293,000. Gross operating margin was $545,000 in
1999 versus $198,000 in 1998, a 175% increase. Gathering system throughput
decreased six percent to 19,453 Mcf per day in 1999 compared to 20,750 Mcf per
day in 1998. Natural gas plant processing throughput was 16,145 Mcf per day in
1999 versus 14,813 Mcf per day in 1998, a nine percent increase. Gross operating
margin from gathering operations was $0.17 per Mcf in 1999 versus $0.08 per Mcf
in 1998. The gross operating margin from natural gas processing was $0.15 per
Mcf in 1999 versus $0.03 per Mcf in 1998.
Revenues from oil field services and international sales were $141,000 in
1999 versus $261,000 in 1998. Operating costs decreased to $65,000 in 1999 from
$141,000 in 1998. The gross operating margin was $76,000 in 1999 versus $120,000
in 1998. Depreciation and depletion expense increased 11% to $5,467,000 in 1999
versus $4,941,000 in 1998. General and administrative expense was $646,000 in
1999, a 14% decrease from $750,000 in 1998. Operating profit increased 102% to
$2,539,000 in 1999 from $1,260,000 in 1998. The Company booked equity in loss of
affiliate of $66,000 in 1999 versus a $4,000 gain in 1998. Other income was
$125,000 in 1999 versus $182,000 in 1998. Interest expense increased eight
percent to $4,894,000 in 1999 from $4,518,000 in 1998. The Company provided for
no deferred income tax benefit on the loss before tax and minority interest of
$2,296,000 in 1999 versus a benefit of $1,169,000 on a loss of $3,072,000 in
1998, due to a valuation allowance on utilization of deferred tax
3
<PAGE>
benefits in 1999. The Company reported a net loss applicable to common shares of
$3,555,000, or $0.18 per common share in 1999 versus a loss of $2,134,000, or
$0.10 per common share in 1998. The Company accrued $1,215,000 in dividends on
its preferred stock in 1999 versus $219,000 in 1998.
Results of Operations for the Six Month Periods in 1999 and 1998
As discussed above, the Company acquired its interest in Tel in March 1998,
completed the Spirit 76 acquisition in December 1998, and completed the Vastar
acquisition in June 1999. Unless otherwise stated, the increases in the 1999
interim period over the 1998 interim period were a result of these acquisitions
as well as the Company's 1998 drilling program.
Oil and natural gas sales were $24,688,000 in 1999, a 12% increase over the
1998 amount of $22,064,000. The Company sold 584,000 barrels of oil versus
544,000 barrels, a seven percent increase, and 9,146,000 Mcf of gas versus
6,757,000 Mcf, a 35% increase, in 1999 as compared to 1998. The price received
for oil was $12.70 per barrel and for gas was $1.89 per Mcf in 1999,
representing an eight percent decrease in oil price and a nine percent decrease
in gas price compared to 1998. Oil and gas sales for the 1998 period also
included $541,000 resulting from the settlement of gas imbalances with another
producer on several of the Company's gas wells. Oil and natural gas production
lifting costs increased two percent to $6,817,000 while production taxes and
other costs decreased five percent to $3,177,000 in 1999 over 1998. The gross
operating margin from oil and natural gas production was $14,694,000 in 1999
versus $12,013,000 in 1998, a 22% increase. On an equivalent unit basis, the
gross margin was $1.16 per Mcfe in 1999, a one percent increase. The sales price
declined 9% to $1.95 per Mcfe while production lifting costs decreased 19% to
$0.54 per Mcfe in 1999. Production taxes and other costs including overhead,
were $0.25 per Mcfe in 1999, a 24% decrease from 1998. The overall increase in
the gross operating margin in 1999 compared to 1998 was principally due to a 26%
increase in Mcfe sold to 12,652,000 Mcfe from 10,019,000 Mcfe.
Gas gathering, marketing, and processing revenues were $3,477,000 in the
1999 period, a one percent decrease from 1998, principally due to lower prices
received for natural gas and natural gas liquids. Costs from these activities
were $2,582,000 in 1999, a nine percent decrease principally due to lower gas
prices. Gross operating margin was $895,000 in 1999, a 39% increase. The
increase in gross operating margin was due to increased marketing margins and
more favorable processing economics. Gathering system throughput decreased six
percent to 19,546 Mcf per day in 1999. Natural gas plant processing throughput
increased two percent to 15,618 Mcf per day in 1999. Gross operating margin from
gathering and marketing operations was $0.16 per Mcf in 1999, a 62% increase.
The gross operating margin from natural gas processing was $0.11 per Mcf in
1999, a nine percent increase.
Revenues from oil field services and international sales were $299,000 in
1999 versus $454,000 in 1998. Operating costs decreased to $136,000 in 1999 from
$240,000 in 1998. The gross operating margin from these activities decreased by
24% to $163,000 in 1999 versus the 1998 period.
Depreciation and depletion expense increased 20% to $10,615,000 in 1999
primarily due to the increase in production as a result of acquisitions. General
and administrative expense was $1,332,000 in 1999, an 11% decrease over 1998.
Operating profit increased 49% to $3,805,000 in 1999 from 1998. Equity in
loss of affiliate was $97,000 in 1999 versus a loss of $45,000 in 1998. Other
income decreased 25% to $288,000 in 1999 versus $383,000 in 1998. Interest
expense increased 28% to $11,211,000 in 1999 due to increased levels of
borrowing under the Company's revolving credit lines with banks. The Company
incurred a net loss before income tax and minority interest of $7,215,000 in
1999, versus a $5,858,000 loss in 1998, principally due to lower oil and natural
gas prices, interest expense on the acquisitions exceeding operating income and
a higher charge for depreciation and depletion. The Company did not provide for
a deferred income tax benefit on the 1999 period loss due to its inability to
predict future tax utilization of its net operations loss carryforward. In the
1998 period, the Company provided for a tax loss benefit of $2,209,000.
4
<PAGE>
Minority interest in subsidiary increased to $87,000 in the 1999 period
from $13,000 in the 1998 period. The net loss for the 1999 period was $7,302,000
versus a net loss of $3,662,000 for the 1998 period. The Company accrued
dividends of $2,049,000 on its preferred stock in 1999 versus $438,000 in 1998
due to the increase in preferred stock in the first quarter of 1999. The net
loss applicable to common shareholders was $9,351,000 ($0.46 per share) in 1999
compared to a net loss of $4,100,000 ($0.19 per share) in 1998.
Liquidity and Capital Resources
The Company has three principal operating sources of cash: (i) sales of oil
and gas, (ii) revenues from gas gathering, processing, and marketing, and (iii)
revenues from petroleum management and consulting services. The Company's cash
flow is highly dependent upon oil and gas prices. Decreases in the market price
of oil and gas could result in reductions of both cash flow and the borrowing
base under the Company's Credit Facility, which would result in decreased funds
available, including funds for capital expenditures.
In September 1998, the Company announced a stock repurchase program of up
to one million shares at a cost not to exceed $4 million. At December 31, 1998,
the Company had repurchased 625,600 shares for approximately $1.9 million. In
February 1999, the program was revised to remove the share limitation discussed
above. Since December 31, 1998, the Company has purchased an additional 601,472
shares for approximately $1.7 million.
In December 1998, the Company's 100% owned subsidiary, Bluebird, acquired
for approximately $25 million, certain natural gas reserves and related assets
from Spirit 76. Additionally, the Company capitalized Bluebird with 1,840,271
units of TEL Offshore Trust. To finance the Spirit 76 acquisition, Bluebird
borrowed $26 million under a bridge loan facility with several banks. The bridge
loan was replaced on June 7, 1999 with permanent financing from banks providing
for a revolving credit facility of $75 million with an initial borrowing base of
$41.5 million, due three years from the date of closing with interest rates
based upon either "LIBOR" or "Base Rate" (Prime). The loan is non-recourse to
the Company. In addition to retiring the bridge loan, a portion of the proceeds
from the permanent financing was used to finance the acquisition of properties
from Vastar discussed below.
In December 1998, the Company announced a letter of intent for a strategic
alliance with ONEOK Resources Company, to include the purchase by this company
of $50 million of the Company's Convertible Preferred Stock. In February 1999,
this transaction was consummated. The Preferred Stock has a liquidation value of
$50 million and is convertible into the Company's common stock at $5.25 per
share. Dividends on the Preferred Stock will be payable in cash beginning August
of 1999 at the rate of 8% per annum and will be cumulative. The net proceeds of
$46.3 million received from the sale of Preferred Stock was used to repay senior
bank indebtedness.
On June 8, 1999, the Company acquired oil and gas reserves and related
assets from Vastar for a total purchase price of $32.5 million after purchase
price adjustments. The effective date of the acquisition was April 1, 1999. The
acquisition included Vastar's interest in 476 wells, a gas processing plant and
two gas gathering systems located in the states of Texas, Oklahoma and Arkansas.
For the six months ended June 30, 1999, the Company had a net decrease in
cash of $3.7 million. The Company's operating activities used net cash of $1.4
million, principally from an increase in accounts receivable and a decrease in
accounts payable. The Company used $41.2 million in investing activities,
principally for additions to property and equipment of $40.8 million. Financing
activities provided $38.9 million of cash, principally from the aggregate
proceeds from the issuance of preferred stock of $46.3 million. The Company also
paid $438,000 in cash dividends on preferred stock and accrued an additional
$1,611,000 for dividends earned through June 1999 but not payable until August
1999.
5
<PAGE>
Capital Requirements
For fiscal 1999, the Company has budgeted approximately $25 million for
development and exploration activities, including $15 million for participation
in a new drilling program in twelve separate outer continental shelf blocks in
the shallow water area of the Gulf of Mexico. Commencement of the drilling of
the first well in this program was in May 1999. The Company is not contractually
obligated to proceed with any of its budgeted capital expenditures. The amount
and allocation of future capital expenditures will depend on a number of factors
that are not entirely within the Company's control or ability to forecast,
including drilling results and changes in oil and gas prices. Due to the decline
in oil prices experienced over the past year, the Company redirected a
significant portion of its budgeted funds from oil projects to natural gas. As a
result, actual capital expenditures may vary significantly from current
expectations.
On June 8, 1999, the Company purchased from Vastar oil and gas reserves and
related equipment, a gas processing plant and two gas gathering systems, located
in Texas, Oklahoma and Arkansas for approximately $32.5 million after purchase
price adjustments.
On June 8, 1999, the Company's borrowing base under its revolving credit
line was reduced from $65 million to $60 million as a result of the December 31,
1998 reserve engineering report.
Based upon the Company's anticipated level of operations, the Company
believes that cash flow from operations together with the availability under the
Credit Facility (approximately $11.5 million as of June 30, 1999) will be
adequate to meet its anticipated requirements for working capital, capital
expenditures and scheduled interest and dividend payments for the foreseeable
future.
In the normal course of business, the Company reviews opportunities for the
possible acquisition of oil and gas reserves and activities related thereto.
When potential acquisition opportunities are deemed consistent with the
Company's growth strategy, bids or offers in amounts and with terms acceptable
to the Company may be submitted. It is uncertain whether any such bids or offers
which may be submitted by the Company from time to time will be acceptable to
the sellers. In the event of a future significant acquisition, the Company may
require additional financing in connection therewith.
Inflation and Changes in Prices
During 1998, the Company experienced a significant erosion in prices for
oil (28%) and for natural gas (10%). Due to the severity of the decline in
commodity prices, the Company experienced a loss due primarily from the
write-down of its full cost pool in December 1998. While oil prices recovered
somewhat during the second quarter of 1999, prices for the first six months of
1999 were still significantly lower than the comparable 1998 period. The results
of operations and cash flow of the Company have been, and will continue to be,
affected by the volatility in oil and gas prices. Should the Company experience
a significant increase in oil and gas prices that is sustained over a prolonged
period, it would expect that there would also be a corresponding increase in oil
and gas finding costs, lease acquisition costs, and operating expenses.
Periodically the Company enters into futures, options, and swap contracts to
reduce the effects of fluctuations in crude oil and gas prices. It is the policy
of the Company not to enter into any such arrangements which exceed 75% of the
Company's oil and gas production during the next 12 months.
The Company markets oil and gas for its own account, which exposes the
Company to the attendant commodities risk. A substantial portion of the
Company's gas production is currently sold to NGTS, LLC or end-users either on
the spot market on a month-to-month basis at prevailing spot market prices or
under long-term contracts based on current spot market prices. The Company
normally sells its oil under month-to-month contracts to a variety of
purchasers.
6
<PAGE>
Market Risk Disclosures
Fixed and Variable Debt
The Company has fixed rate bond debt and variable bank debt in its debt
portfolio. On June 30, 1999, the Company entered into two interest rate swaps in
order to shift a portion of the fixed rate bond debt to a floating rate debt
over the next three years and to effectively lower interest expense over the
next twelve months. The effect of these transactions, which are discussed under
Interest Rate Swaps below, will be to save approximately $420,000 in interest
expense over the next twelve months. Thereafter, the economic impact depends on
whether or not variable (LIBOR) rates increase significantly.
Hedging Activity
Crude Oil and Natural Gas Hedges
Periodically, the Company enters into futures, options, and swap contracts
to mitigate the effects of significant fluctuations in crude oil and natural gas
prices. At June 30, 1999, the Company had the following open contracts:
Type Volume/Month Duration Avg. Price
Oil
Collar........... 15,000 Bbl July 99 - Dec 99 Floor - $15.00
Cap - $19.20
Option........... 15,000 Bbl July 99 - Dec 99 $19.20
Swap (1)......... 15,000 Bbl July 99 - Dec 99 $14.80
Swap............. 15,000 Bbl July 99 - Dec 99 $15.12
Collar (1)....... 15,000 Bbl July 99 - Dec 99 Floor - $14.00
Cap - $16.50
Collar........... 15,000 Bbl July 99 - Dec 99 Floor - $15.00
Cap - $17.12
Gas
Swap............. 600,000 MMBtu July 99 - Oct 99 $ 2.04
Collar (2)....... 300,000 MMBtu July 99 - Oct 99 Floor - $ 1.70
Cap - $ 2.05
Collar .......... 300,000 MMBtu Apr 00 - Oct 00 Floor - $ 1.80
Cap - $ 2.25
(1) Hedges were modified on July 12, 1999 by rolling both into a new
swap of 30,000 Bbls/month from August 1999 through December 2000 at a fixed
price of $17.60/Bbl, with an option granted to the counterparty for any month
between August 1999 and December 1999 in which oil prices average below
$16.50/Bbl whereby the hedge would not be effective for that period. In
addition, the counterparty was granted an option exercisable on December 30,
1999 to cancel the swap for calendar year 2000.
(2) The counterparty was granted an option exercisable on October 22,
1999 to continue the hedge for the period November 1999 through March 2000 for
300,000 MMBtu's per month with a floor price of $2.00/MMBtu and a ceiling price
of $2.32/MMBtu.
7
<PAGE>
Net gains or losses related to derivative transactions for the three month
periods ended June 30, 1999 and 1998 were a loss of $358,000 and a gain of
$517,000, respectively. For the six month periods ending June 30, 1999 and 1998,
the gains were $1,085,000 and $1,244,000, respectively. At June 30, 1999, the
unrealized loss from derivative transactions was $722,330.
Interest Rate Swaps
On June 30, 1999, the Company entered into two interest rate swaps in order
to shift a portion of the fixed rate bond debt to floating rate debt, to
capitalize on what was perceived as a market overreaction to pending interest
rate increases by the federal reserve and to effectively lower interest rate
expense over the next twelve months.
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
Type Notional Amount Termination Date Pay Rate Receive Rate
Pay Variable/Receive Fixed $50,000,000 06/01/02 LIBOR + 3.34% 10% fixed
through 05/31/00
LIBOR + 3.69%
from 06/01/00 to
06/01/02
Pay Fixed/Receive Variable $50,000,000 06/01/00 9.16% fixed LIBOR + 3.34%
</TABLE>
The pay variable/receive fixed swap has an early termination provision
granting the counterparty the right to terminate the swap on June 1, 2000, in
exchange for a fee payment to the Company of $125,000. As a result of these two
swaps, the Company will save approximately $420,000 in interest expense during
the first twelve months. Thereafter, the economic impact depends on whether or
not LIBOR rates increase significantly.
Year 2000 Compliance
Year 2000 issues relate to the ability of computer programs or equipment to
accurately calculate, store or use dates after December 31, 1999. These dates
can be handled or interpreted in a number of different ways, but the most common
errors are for the system to contain a two digit year which may cause the system
to interpret the year 2000 as 1900 or 1980, and the system will not recognize
the year 2000 as a leap year. Errors such as these can result in system
failures, miscalculations and the disruption of operations, including, among
other things, a temporary inability to process transactions, send invoices or
engage in similar normal business activities. In response to the Year 2000
issues, the Company has developed a strategic plan divided into the following
phases: inventory, product compliance based on vendor representations and
in-house testing, third party integration and development of a contingency plan.
All of the Company's processing needs are handled by third party systems,
none of which have been substantially modified and all of which have been
purchased or upgraded within the last few years. Therefore, the Company's
initial review of its in-house systems with regard to Year 2000 issues required
an inventory of its systems and a review of the vendor representations. The
Company has completed this initial review of its information systems, various
types of equipment and non-information technology have also been reviewed, and
based on vendor representations, are either compliant, will be compliant with
the next forthcoming software release or are systems that are not date specific.
The Company's non-information technology consists primarily of various oil
and gas exploration and production equipment. The initial review has established
that the primary non-information technology systems functions are either not
date sensitive or are Year 2000 compliant based on vendor representations, and
are therefore predicted to operate in customary manners when faced with Year
2000 issues. However, the Company has determined that in the event such systems
are unable to address the Year 2000, employees can manually perform most, if not
all, functions.
8
<PAGE>
In anticipation of Year 2000 issues, the Company is also evaluating the
Year 2000 readiness status of its third party service suppliers. In addition to
reviewing Year 2000 readiness statements issued by the third parties handling
the Company's processing needs, to date the Company has received and is relying
upon, Year 2000 readiness reports periodically issued by its financial services
and electrical service providers, vendors and purchasers of the Company's oil
and natural gas products. The Company is continuing to review Year 2000
readiness of third party service suppliers and based on their representations,
does not currently foresee material disruptions in the Company's business as a
result of Year 2000 issues. Unanticipated prolonged losses of certain services,
such as electrical power, could cause material disruptions for which no
economically feasible contingency plan has been developed.
The Company has completed in-house testing of the core systems and
non-information technology. The vast majority of all systems tested adequately
address possible Year 2000 scenarios. The Company has developed plans to remedy
the systems which do not adequately address the Year 2000 issues. All systems
are expected to be fully Year 2000 compliant by the end of the third quarter of
1999.
Although the effects of Year 2000 issues cannot be predicted with
certainty, the Company believes that the potential impact, if any, of such
events will, at most, require employees to manually complete otherwise automated
tasks or calculations, other than those which might occur in a "worst case"
scenario as described below, which the Company does not anticipate will occur.
After considering Year 2000 effects on in-house operations, the company
expects a minimal level of additional training would be required to perform
these tasks on a manual basis due to the level of experience of its personnel
and the routine nature of the tasks being performed. If, based on the results of
its in-house testing, the Company should determine that certain systems are not
Year 2000 compliant and it appears as though the system is not likely to be
compliant within a reasonable time period, the Company will either elect to
perform the task manually or will attempt to purchase a different system for
that particular task and convert before December 31, 1999. The Company does not
believe that either option would impact the Company's ability to continue
exploration drilling, production or sales activities, although the tasks may
require additional time and personnel to complete the same functions or may
require incremental time and personnel during 1999 for a conversion to a new
system.
The Company's core business consists primarily of oil and gas acquisitions,
development and exploration activities. The equipment that is deemed "mission
critical" to the Company's activities requires external power sources such as
electricity supplied by third parties. Although the Company maintains limited
on-site secondary power sources such as generators, it is not economically
feasible to maintain secondary power supplies for any major component of its
"mission critical" equipment. Therefore, the most reasonable likely worst case
Year 2000 scenario for the Company would involve a disruption of third party
supplied electrical power, which would result in a substantial decrease in the
Company's oil production. Such event could result in a business interruption
that could materially affect the Company's operations, liquidity or capital
resources.
The Company has initiated the third party integration phase and will
continue to have formal communications with its significant suppliers, business
partners and key customers to determine the extent to which the Company is
vulnerable to either the third parties or its own failure to correct their Year
2000 issues. The Company has been communicating with such third parties to keep
them informed of the Company's internal assessment of its Year 2000 review and
plans. This portion of the review and discussions with third parties have
provided certain favorable representations as to their Year 2000 readiness and
received similar representations from the Company. There can be no guarantee
that the systems of the other companies on which the Company relies will be
timely converted or that the conversion will be compatible with the Company's
systems. However, after reviewing and estimating the effects of such events, the
Company's contingency plan involves identifying and arranging for other vendors,
purchasers and third party contractors to provide such services, if necessary,
in order to maintain its normal operations.
The Company has, and will continue to, utilize both internal and external
resources to complete tasks and perform testing necessary to address the Year
2000 issue. The Company has not incurred, and does not anticipate that it will
incur, any significant costs relating to the assessment and remediation of Year
2000 issues.
9
<PAGE>
Recently Issued Accounting Pronouncements
In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, which established a new model for accounting
for derivatives and hedging activities. SFAS No. 133, which will be effective
for the Company's fiscal year 2001, requires that all derivatives be recognized
in the balance sheet as either assets or liabilities and measured at fair value.
The Statement also requires that changes in fair value be reported in earnings
unless specific hedge accounting criteria are met. The Company is currently
evaluating the effect of the adoption of the Statement on its consolidated
financial position and results of operations.
10
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(in thousands of dollars)
<TABLE>
<CAPTION>
<S> <C> <C>
June 30, December 31,
1999 1998
----------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents..............................................$ 1,167 $ 4,853
Restricted cash ....................................................... 976 459
Accounts receivable
Trade, net of allowance of $166 for 1999 and 1998................. 8,799 5,686
Due from affiliates............................................... 61 310
Notes receivable from affiliate........................................ 688 747
Current portion of long-term notes receivable, net of allowance of $790
for 1999 and 1998.................................................... 57 57
Prepaid and other...................................................... 1,091 1,577
----------------------------------------------------
Total Current Assets............................................. 12,839 13,689
----------------------------------------------------
Property, Plant, and Equipment
Oil and gas properties, full cost method
Unproved......................................................... 4,989 1,655
Proved........................................................... 333,919 296,545
Pipelines.............................................................. 9,161 9,131
Other property......................................................... 1,686 1,554
----------------------------------------------------
Total Property, Plant and Equipment.................................... 349,755 308,885
Accumulated depreciation, depletion, amortization and impairment. (91,064) (80,449)
----------------------------------------------------
Net Property, Plant and Equipment...................................... 258,691 228,436
----------------------------------------------------
Other Assets
Deposits and other assets.............................................. 6,540 6,644
Investment in unconsolidated affiliate................................. 4,169 4,266
Deferred tax asset .................................................... 13,351 13,351
Long-term notes receivable, net of imputed interest.................... 1,222 756
----------------------------------------------------
Total Assets $ 296,812 $ 267,142
----------------------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Trade payables and accrued liabilities.................................$ 7,528 $ 11,821
Dividends payable...................................................... 1,830 219
Suspended revenue payable.............................................. 721 359
Current maturities of long-term debt................................... 11 13
Notes payable.......................................................... - 2,000
----------------------------------------------------
Total Current Liabilities........................................ 10,090 14,412
----------------------------------------------------
Long-Term Liabilities
Long-term debt - with recourse, less current maturities................ 188,501 231,007
Long-term debt - nonrecourse........................................... 41,500 -
Production payment liability........................................... 571 633
Minority interest...................................................... 185 98
Commitments and Contingencies
Stockholders' Equity
Preferred stock - $.001 par value; 10,000,000 shares authorized,
216,000 designated as Series A; 80,000 issued and outstanding,
liquidation amount $0................................................ - -
1,000,000 designated as 1996 Series A Convertible; 1,000,000
issued and outstanding, liquidation amount $10,000,000............... 1 1
50,000 designated as 1999 Series A 8% Convertible; 50,000 issued
and outstanding, liquidation amount $50,000,000...................... - -
Common Stock - $.002 par value; 50,000,000 shares authorized,
21,738,320 shares issued............................................. 43 43
Additional paid-in capital............................................. 124,253 80,000
Accumulated other comprehensive income................................. (1,685) (1,429)
Accumulated deficit.................................................... (63,016) (55,714)
----------------------------------------------------
59,596 22,901
Treasury stock, at cost (1,630,443 and 1,054,507 shares of common stock,
respectively) (3,631) (1,909)
----------------------------------------------------
Total Stockholders' Equity...................................................... 55,965 20,992
----------------------------------------------------
Total Liabilities and Stockholders' Equity......................................$ 296,812 $ 267,142
----------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
11
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS and COMPREHENSIVE INCOME
(Unaudited)
(in thousands, except for per share amounts)
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------------------------------------
1999 1998 1999 1998
----------------------------------------------------------------------
Operating Revenues:
Oil and gas sales......................................... $ 13,367 $ 11,509 $ 24,688 $ 22,064
Gas gathering, marketing and processing................... 1,851 1,491 3,477 3,496
Oil field services and international sales................ 141 261 299 454
----------------------------------------------------------------------
Total Operating Revenues............................. 15,359 13,261 28,464 26,014
----------------------------------------------------------------------
Operating Costs and Expenses:
Oil and gas production lifting costs...................... 3,624 3,012 6,817 6,701
Production taxes and other costs.......................... 1,712 1,864 3,177 3,350
Gas gathering, marketing and processing................... 1,306 1,293 2,582 2,852
Oil field services and international sales................ 65 141 136 240
Depreciation and depletion................................ 5,467 4,941 10,615 8,816
General and administrative................................ 646 750 1,332 1,500
----------------------------------------------------------------------
Total Operating Costs and Expenses................... 12,820 12,001 24,659 23,459
----------------------------------------------------------------------
Operating Profit ............................................ 2,539 1,260 3,805 2,555
Equity in earnings (loss) of affiliate, net of income tax. (66) 4 (97) (45)
Other income.............................................. 125 182 288 383
Interest expense.......................................... (4,894) (4,518) (11,211) (8,751)
----------------------------------------------------------------------
Net Loss before income tax and minority interest............. (2,296) (3,072) (7,215) (5,858)
Benefit for deferred income tax........................... - 1,169 - 2,209
----------------------------------------------------------------------
Net Loss before minority interest............................ (2,296) (1,903) (7,215) (3,649)
Minority interest in subsidiary earnings ................. (44) (12) (87) (13)
----------------------------------------------------------------------
Net Loss..................................................... (2,340) (1,915) (7,302) (3,662)
Dividends Applicable to Preferred Stock................... (1,215) (219) (2,049) (438)
----------------------------------------------------------------------
Loss Applicable to Common Shares............................. $ (3,555) $ (2,134) $ (9,351) $ (4,100)
----------------------------------------------------------------------
Net Loss..................................................... $ (2,340) $ (1,915) $ (7,302) $ (3,662)
Other Comprehensive Loss, net of tax
Unrealized Loss on Investments............................ (129) - (256) -
----------------------------------------------------------------------
Comprehensive Loss........................................... $ (2,469) $ (1,915) $ (7,558) $ (3,662)
----------------------------------------------------------------------
Loss per Common Share - Basic $ (0.18) $ (0.10) $ (0.46) (0.19)
----------------------------------------------------------------------
Loss per Common Share - Diluted $ (0.18) $ (0.10) $ (0.46) (0.19)
----------------------------------------------------------------------
Common Shares Used in Per Share Calculation..................
Basic..................................................... 20,100,862 21,214,239 20,191,265 21,209,339
----------------------------------------------------------------------
Diluted................................................... 20,100,862 21,214,239 20,191,265 21,209,339
----------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
12
<PAGE>
Magnum Hunter Resources, Inc. and Subsidiaries
Consolidated Statements of Stockholders' Equity
For the Period Ended June 30, 1999
(Unaudited)
(dollars in thousands)
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
Preferred Stock Common Stock Treasury Stock
Shares Amount Shares Amount Shares Amount
--------------------------------------------------------------------------------
Balance at December 31, 1998........................ 1,080,000 $ 1 21,738,320 $ 43 (1,054,507) $ (1,909)
--------------------------------------------------------------------------------
Issuance of 1999 Series A 8% Convertible
Preferred Stock, net of offering costs......... 50,000 -
Exercise of employees' common stock options...... 25,536 -
Purchase of treasury stock....................... (601,472) (1,722)
Dividends declared or accrued on preferred
stock..........................................
Net income (loss)................................
Unrealized (loss) on investment..................
--------------------------------------------------------------------------------
Balance at June 30, 1999............................ 1,130,000 $ 1 21,738,320 $ 43 (1,630,443) $ (3,631)
--------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <C> <C>
Paid-In Comprehensive Accumulated
Capital Income (Loss) Deficit
--------------------------------------------------------------------------------
Balance at December 31, 1998........................ $ 80,000 $ (1,429) $ (55,714)
--------------------------------------------------------------------------------
Issuance of 1999 Series A 8% Convertible
Preferred Stock, net of offering costs......... 46,283
Exercise of employees' common stock options...... 19
Purchase of treasury stock.......................
Dividends declared or accrued on preferred
stock.......................................... (2,049)
Net income (loss)................................ (7,302)
Unrealized (loss) on investment.................. (256)
--------------------------------------------------------------------------------
Balance at June 30, 1999............................ $ 124,253 $ (1,685) $ (63,016)
--------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
13
<PAGE>
Magnum Hunter Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(Unaudited)
(in thousands)
<TABLE>
<CAPTION>
<S> <C> <C>
Six Months Ended
June 30,
-------------------------------------------------
1999 1998
-------------------------------------------------
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income (loss)............................................................ $ (7,302) $ (3,662)
Adjustments to reconcile net income (loss) to cash provided by
(used for) operating activities:
Depreciation and depletion.............................................. 10,615 8,816
Amortization of financing fees.......................................... 1,611 357
Deferred income taxes................................................... - (2,209)
Equity in unconsolidated affiliate...................................... 97 45
Minority interest....................................................... 87 13
Other................................................................... - 2
Changes in certain assets and liabilities
Accounts and notes receivable..................................... (3,114) 4,722
Other current assets.............................................. 486 94
Accounts payable and accrued liabilities.......................... (3,830) (624)
-------------------------------------------------
Net Cash Provided By (Used By) Operating Activities.......................... (1,350) 7,554
-------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets................................................. - 318
Additions to property and equipment.......................................... (40,825) (26,374)
Increase in deposits and other assets........................................ - (2,511)
Loan made for promissory note receivable..................................... (473) (40)
Payments received on promissory note receivable ............................. 66 28
Investment in unconsolidated affiliate....................................... - (50)
-------------------------------------------------
Net Cash Used In Investing Activities........................................ (41,232) (28,629)
-------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuance of long-term debt and production payment.......... 78,000 25,500
Fees paid related to financing activities.................................... (1,659) -
Payments of principal on long-term debt and production payment............... (79,070) (3,836)
Payment of short-term notes payable ......................................... (2,000) -
Proceeds from issuance of common and preferred stock, net of offering costs.. 46,302 12
Purchase of treasury stock .................................................. (1,722) -
Increase in segregated funds for payment of notes payable ................... (517) -
Cash dividends paid.......................................................... (438) (438)
-------------------------------------------------
Net Cash Provided By (Used By) Financing Activities.......................... 38,896 21,238
-------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............................ (3,686) 163
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD................................ 4,853 3,030
-------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD...................................... $ 1,167 $ 3,193
-------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
14
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 1999
(Unaudited)
NOTE 1 - MANAGEMENT'S REPRESENTATION
The consolidated balance sheet as of June 30, 1999, the consolidated
statements of operations and comprehensive income for the three and six months
ended June 30, 1999 and 1998, the consolidated statement of stockholder's equity
for the period ended June 30, 1999 and the consolidated statements of cash flows
for the six months ended June 30, 1999 and 1998 are unaudited. In the opinion of
management, all necessary adjustments (which include only normal recurring
adjustments) have been made to present fairly the financial position, results of
operations, changes in stockholder's equity and changes in cash flows for the
three and six month periods.
Certain information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted. It is suggested that these condensed financial
statements be read in conjunction with the financial statements and notes
thereto included in the December 31, 1998 annual report on Form 10-K for the
Company. The results of operations for the three and six month periods ended
June 30, 1999, are not necessarily indicative of the operating results for the
full year.
The accompanying consolidated financial statements include the accounts of
the Company and its subsidiaries. All significant intercompany transactions and
balances have been eliminated in consolidation. Certain items have been
reclassified to conform with the current presentation.
The Company is a holding company with no significant assets or operations
other than its investments in its subsidiaries. The wholly-owned subsidiaries of
the Company, except for Bluebird Energy, Inc. ("Bluebird"), are direct
Guarantors of the Company's 10% Senior Notes and have fully and unconditionally
guaranteed the Notes on a joint and several basis. The Guarantors comprise all
of the direct and indirect subsidiaries of the Company (other than Bluebird and
inconsequential subsidiaries), and the Company has not presented separate
financial statements and other disclosures concerning each Guarantor because
management has determined that such information is not material to investors.
Except for Bluebird, there is no restriction on the ability of consolidated or
unconsolidated subsidiaries to transfer funds to the Company in the form of cash
dividends, loans, or advances.
NOTE 2 - RECENT EVENTS
On February 3, 1999, the Company sold $50 million of its Convertible
Preferred Stock in a private placement. The Preferred Stock has a liquidation
value of $50 million and is convertible into the Company's common stock at $5.25
per share. Dividends on the preferred stock are payable in cash at the rate of
8% per annum and are cumulative. The Company used the net proceeds from the
transaction, approximately $46.3 million, to repay senior bank debt.
On February 17, 1999, the Company revised its previously announced stock
repurchase program to spend up to $4 million without a share limitation.
Subsequent to December 31, 1998, the Company repurchased 601,472 shares of its
common stock for approximately $1.7 million.
On June 8, 1999, Bluebird entered into a $75 million Senior Secured
Revolving Credit Facility with certain banks. The revolving line of credit has
an initial borrowing base of $41.5 million and is non-recourse to the Company
and its other subsidiaries. The new facility refinanced a bridge loan facility
used to acquire properties in December 1998.
On June 9, 1999, the Company executed an agreement with an April 1, 1999
effective date to purchase oil and gas reserves and related equipment, a gas
processing plant and two gas gathering systems, located in Texas, Oklahoma and
Arkansas for approximately $32.5 million after purchase price adjustments.
15
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 1999
(Unaudited)
On July 16, 1999, the Company issued a total of 10,512,150 warrants on the
basis of one warrant for every three common shares owned, .63492 warrants for
every share of 1996 Series A Convertible Preferred Stock owned and 63.492
warrants for every share of 1999 Series A 8% Convertible Preferred Stock owned.
The warrants have an exercise price of $6.50 per share, expire on June 30, 2002
and are redeemable by the Company at any time at $.01 per share. The warrants
are publicly traded.
NOTE 3 - SEGMENT DATA
The Company has three reportable segments. The Exploration and Production
segment is engaged in exploratory drilling and acquisition, production, and sale
of crude oil, condensate, and natural gas. The Gas Gathering, Marketing and
Processing segment is engaged in the gathering and compression of natural gas
from the wellhead, the purchase and resale of natural gas which it gathers, and
the processing of natural gas liquids. The Oil Field Services segment is engaged
in the managing and operation of producing oil and gas properties for interest
owners.
The Company's reportable segments are strategic business units that offer
different products and services. They are managed separately because each
business requires different technology and marketing strategies. The Exploration
and Production segment has six geographic areas that are aggregated. The Gas
Gathering, Marketing and Processing segment includes the activities of the two
gathering systems and one natural gas liquids processing plant in two geographic
areas that are aggregated. The Oil Field Services segment has seven geographic
areas that are aggregated. The reason for aggregating the segments, in each
case, was due to the similarity in nature of the products, the production
processes, the type of customers, the method of distribution, and the regulatory
environments.
The accounting policies of the segments are the same as those for the
Company as a whole. The Company evaluates performance based on profit or loss
from operations before income taxes. The accounting for intersegment sales and
transfers is done as if the sales or transfers were to third parties, that is,
at current market prices.
Segment data for the periods ended June 30, 1999 and 1998 follows (in
thousands):
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
Gas Gathering,
Exploration & Marketing & Oil Field
Three Months Ended June 30, 1999: Production Processing Services All Other Elimination Consolidated
--------------------------------- ---------- ---------- --------- --------- ----------- ------------
Revenue from external customers........ $ 13,367 $ 1,851 $ 141 $ - $ - $ 15,359
Intersegment revenues................... - 3,368 1,391 - (4,759) -
Depreciation, depletion, amortization and
impairment .......................... 5,251 163 49 4 5,467
Segment profit (loss)................. 2,052 321 821 (655) 2,539
Equity earnings (losses) of affiliates.. (66) (66)
Interest expense........................ (4,894) (4,894)
Other income............................ 125 125
------------
Loss before income taxes................ $ (2,296)
Benefit for deferred income tax......... - -
Minority interest....................... (44) (44)
------------
Net loss................................ $ (2,340)
------------
Capital expenditures (net of asset sales) $ 38,897 $ 14 $ 103 $ - $ 39,014
</TABLE>
16
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 1999
(Unaudited)
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
Gas Gathering,
Exploration & Marketing & Oil Field
Three Months Ended June 30, 1998: Production Processing Services All Other Elimination Consolidated
--------------------------------- ---------- ---------- --------- --------- ----------- ------------
Revenue from external customers........ $ 11,509 $ 1,491 $ 261 $ - $ - $ 13,261
Intersegment revenues.................. - 3,112 1,124 - (4,236) -
Depreciation, depletion, amortization and
impairment........................... 4,733 164 41 3 4,941
Segment profit (loss)................. 1,404 (11) 194 (327) 1,260
Equity earnings (losses) of affiliates.. 4 4
Interest expense........................ (4,518) (4,518)
Other income............................ 182 182
---------------
Loss before income taxes................ $ (3,072)
Benefit for deferred income tax ........ 1,169 1,169
Minority interest....................... (12) (12)
----------------
Net loss................................ $ (1,915)
----------------
Capital expenditures (net of asset sales) $ 9,965 $ 19 $ 116 $ - $ 10,100
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
Gas Gathering,
Exploration & Marketing & Oil Field
Six Months Ended June 30, 1999: Production Processing Services All Other Elimination Consolidated
------------------------------- ---------- ---------- --------- --------- ----------- ------------
Revenue from external customers........ $ 24,688 $ 3,477 $ 299 $ - $ - $ 28,464
Intersegment revenues................... - 6,171 2,723 - (8,894) -
Depreciation, depletion, amortization and
impairment........................... 10,185 326 96 8 10,615
Segment profit (loss)................. 3,081 471 1,492 (1,239) 3,805
Equity earnings (losses) of affiliates.. (97) (97)
Interest expense........................ (11,211) (11,211)
Other income............................ 288 288
--------------------------
Loss before income taxes................ $ (7,215)
Benefit for deferred income tax ........ -
Minority interest....................... (87) (87)
--------------------------
Net loss................................ $ (7,302)
--------------------------
Capital expenditures (net of asset sales $ 40,708 $ 30 $ 132 $ - $ 40,870
</TABLE>
17
<PAGE>
MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
June 30, 1999
(Unaudited)
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
Gas Gathering,
Exploration & Marketing & Oil Field
Six Months Ended June 30, 1998: Production Processing Services All Other Elimination Consolidated
------------------------------- ---------- ---------- --------- --------- ----------- ------------
Revenue from external customers........ $ 22,064 $ 3,496 $ 454 $ - $ - $ 26,014
Intersegment revenues.................. - 6,198 2,183 - (8,381) -
Depreciation, depletion, amortization and
impairment........................... 8,406 327 75 8 8,816
Segment profit (loss)................. 2,577 287 433 (742) 2,555
Equity earnings (losses) of affiliates.. (45) (45)
Interest expense........................ (8,751) (8,751)
Other income............................ 383 383
----------------------
Loss before income taxes................ $ (5,858)
Benefit for deferred income tax ........ 2,209 2,209
Minority interest....................... (13) (13)
----------------------
Net loss................................ $ (3,662)
----------------------
Capital expenditures (net of asset sales) $ 27,192 $ 29 $ 150 $ - $ 27,371
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
Gas Gathering,
Exploration & Marketing & Oil Field
As of June 30, 1999: Production Processing Services All Other Elimination Consolidated
-------------------- ---------- ---------- --------- --------- ----------- ------------
Segment assets.......................... $ 267,482 $ 13,507 $ 5,607 $ 10,216 $ 296,812
Equity subsidiary investments........... 4,169 4,169
As of June 30, 1998:
Segment assets.......................... $ 232,862 $ 14,622 $ 4,969 $ 14,301 $ 266,754
Equity subsidiary investments........... 4,350 4,350
</TABLE>
18
<PAGE>
PART II -- OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
Number Description of Exhibit
3.1 & 4.1 Articles of Incorporation (Incorporated by reference to
Registration Statement on Form S-18, File No. 33-30298-D)
3.2 & 4.2 Articles of Amendment to Articles of Incorporation (Incorporated
by reference to Form 10-K for the year ended December 31, 1990)
3.3 & 4.3 Articles of Amendment to Articles of Incorporation (Incorporated
by reference to Registration Statement on Form SB-2,
File No. 33-66190)
3.4 & 4.4 Articles of Amendment to Articles of Incorporation (Incorporated
by reference to Registration Statement on Form S-3,
File No. 333-30453)
3.5 & 4.5 By-Laws, as Amended (Incorporated by reference to Registration
Statement on Form SB-2, File No. 33-66190)
3.6 & 4.6 Certificate of Designation of 1996 Series A Preferred Stock
(Incorporated by reference to Form 8-K dated December 26, 1996,
filed January 3, 1997)
3.7 & 4.7 Amendment to Certificate of Designations for 1996 Series A
Convertible Preferred Stock (Incorporated by reference to
Registration Statement on Form S-3, File No. 333-30453)
3.8 & 4.8 Certificate of Designation for 1999 Series A 8% Convertible
Preferred Stock (Incorporated by reference to Form 8-K, dated
February 3, 1999, filed February 11, 1999)
4.9 Indenture dated May 29, 1997 between Magnum Hunter Resources, the
subsidiary guarantors named therein and First Union National Bank
of North Carolina, as Trustee (Incorporated by reference to
Registration Statement on Form S-4, File No. 333-2290)
4.10 Supplemental Indenture dated January 27, 1999 between Magnum
Hunter Resources, the subsidiary guarantors named therein and
First Union National Bank of North Carolina, as Trustee
(Incorporated by reference to Form 10-K for the year ended
December 31, 1998)
4.11 Form of 10% Senior Note due 2007 (Incorporated by reference to
Registration Statement on Form S-4, File No. 333-2290)
4.12 Form of Warrant Agreement by and between Magnum Hunter
Resources, Inc. and Securities Transfer Corporation as warrants
agent (including form of warrant certificate)(Incorporated by
reference to Registration Statement on Form S-3,
File No. 333-79139)
4.13 Form of warrant certificate (Incorporated by reference to
Registration Statement on Form S-3, File No. 333-79139)
10.1 Amended and Restated Credit Agreement, dated April 30, 1997,
between Magnum Hunter Resources, Inc. and Bankers Trust Company,
et al. (Incorporated by reference to Registration Statement on
Form S-4, File No. 333-2290)
10.2 First Amendment to Amended and Restated Credit Agreement, dated
April 30, 1997, between Magnum Hunter Resources, Inc. and Bankers
Trust Company, et al. (Incorporated by reference to Registration
Statement on Form S-4, File No. 333-2290)
10.3 Second Amendment to Amended and Restated Credit Agreement, dated
April 30, 1997, between Magnum Hunter Resources, Inc. and Bankers
Trust Company, et al. (Incorporated by reference to Form 10-K for
the year ended December 31, 1998)
10.4 Third Amendment to Amended and Restated Credit Agreement, dated
April 30, 1997, between Magnum Hunter Resources, Inc. and Bankers
Trust Company, et al. (Incorporated by reference to Form 10-K for
the year ended December 31, 1998)
10.5 Employment Agreement for Gary C. Evans (Incorporated by reference
to Registration Statement on Form S-4, File No. 333-2290)
10.6 Employment Agreement for Matthew C. Lutz (Incorporated by
reference to Registration Statement on Form S-4,File No. 333-2290)
19
<PAGE>
10.7 Stock Purchase Agreement among Magnum Hunter Resources, Inc. and
Trust Company of the West and TCW Asset Management Company, in the
capacities described herein, TCW Debt and Royalty Fund IVB and TCW
Debt and Royalty Fund IVC, dated as of December 6, 1996
(Incorporated by reference to Form 8-K dated December 26, 1996,
filed January 3, 1997)
10.8 Registration Rights Agreement, dated May 29, 1997, between Magnum
Hunter Resources, Inc. and Bankers Trust Company, et al.
(Incorporated by reference to Registration Statement on Form S-4,
File No. 333-2290)
10.9 Purchase and Sale Agreement, dated May 17, 1996 between Meridian
Oil, Inc. and ConMag Energy Corporation (Incorporated by reference
to Form 8-K, dated June 28, 1996, filed July 12, 1996)
10.10 Purchase and Sale Agreement, dated February 27, 1997 among
Burlington Resources Oil and Gas Company, Glacier Park Company and
Magnum Hunter Production, Inc. (Incorporated by reference to Form
8-K, dated April 30, 1997, filed May 12, 1997)
10.11 Purchase and Sale Agreement between Magnum Hunter Resources, Inc.
, NGTS, et al., dated December 17, 1997 (Incorporated by reference
to Form 8-K, dated December 17, 1997, filed December 29, 1997)
10.12 Purchase and Sale Agreement dated November 25, 1998 between Magnum
Hunter Production, Inc. and Unocal Oil Company of California
(Incorporated by reference to Form 10-K for the year ended
December 31, 1998)
10.13 Stock Purchase Agreement dated February 3, 1999 between ONEOK
Resources Company and Magnum Hunter Resources, Inc. (Incorporated
by reference to Form 8-K, dated February 3, 1999, filed February
11, 1999)
27* Financial Data Schedule
* Filed herewith.
(B) Form 8-K's - None.
20
<PAGE>
SIGNATURE
In accordance with the requirements of the Exchange Act, the Registrant has
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
MAGNUM HUNTER RESOURCES, INC.
By /s/ Gary C. Evans August 3, 1999
------------------------------------------------------
Gary C. Evans
President and Chief Executive Officer
By /s/ Chris Tong August 3, 1999
------------------------------------------------------
Sr. Vice President and
Chief Financial Officer
By /s/ David S. Krueger August 3, 1999
----------------------------------------------------
David S. Krueger
Vice President and
Chief Accounting Officer
By /s/ Morgan F. Johnston August 3, 1999
-----------------------------------------------------
Morgan F. Johnston
Vice President, General Counsel and
Secretary
21
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-Mos
<FISCAL-YEAR-END> Dec-31-1999
<PERIOD-START> Jan-01-1999
<PERIOD-END> Jun-30-1999
<CASH> 2,143
<SECURITIES> 0
<RECEIVABLES> 9,026
<ALLOWANCES> (166)
<INVENTORY> 0
<CURRENT-ASSETS> 12,839
<PP&E> 349,755
<DEPRECIATION> (91,064)
<TOTAL-ASSETS> 296,812
<CURRENT-LIABILITIES> 10,090
<BONDS> 230,572
0
1
<COMMON> 43
<OTHER-SE> 55,921
<TOTAL-LIABILITY-AND-EQUITY>296,812
<SALES> 28,165
<TOTAL-REVENUES> 28,464
<CGS> 12,576
<TOTAL-COSTS> 24,659
<OTHER-EXPENSES> (191)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 11,211
<INCOME-PRETAX> (7,215)
<INCOME-TAX> 0
<INCOME-CONTINUING> (7,302)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (7,302)
<EPS-BASIC> (0.46)
<EPS-DILUTED> (0.46)
</TABLE>
