SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the Fiscal Year Ended December 31, 1999
Commission File Number 1-8754
SWIFT ENERGY COMPANY
(Exact Name of Registrant as Specified in Its Charter)
Texas 74-2073055
(State of Incorporation) (I.R.S. Employer Identification No.)
16825 Northchase Dr., Suite 400
Houston, Texas 77060
(281) 874-2700
(Address and telephone number of principal executive offices)
Securities registered pursuant to Section
12(b) of the Act:
Title of Class: Exchanges on Which Registered:
Common Stock, par value $.01 per share New York Stock Exchange
Pacific Stock Exchange
Convertible Subordinated Notes Due 2006 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
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 and (2) has been subject to such filing requirements for
the past 90 days. Yes x No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the voting stock held by non-affiliates at March
15, 2000 was approximately $234,483,000.
The number of shares of common stock outstanding as of December 31, 1999 was
20,823,729 shares of common stock, $.01 par value.
Documents Incorporated by Reference
Document Incorporated as to
Notice and Proxy Statement for the Annual Part III, Items 10, 11, 12,
Meeting of Shareholders to be held May 9, 2000 and 13
<PAGE>
Form 10-K
Swift Energy Company and Subsidiaries
10-K Part and Item No. Page
<TABLE>
<CAPTION>
<S> <C> <C>
Part I
Item 1. Business 3
Item 2. Properties 3
Item 3. Legal Proceedings 15
Item 4. Submission of Matters to a Vote of
Security Holders 15
Part II
Item 5. Market for the Registrant's Common
Equity and Related Stockholder Matters 15
Item 6. Selected Financial Data 16
Item 7. Management's Discussion and
Analysis of Financial Condition
and Results of Operations 18
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 23
Item 8. Financial Statements and Supple-
mentary Data 25
Item 9. Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure 47
Part III
Item 10. Directors and Executive Officers of
the Registrant (1) 47
Item 11. Executive Compensation (1) 47
Item 12. Security Ownership of Certain Bene-
ficial Owners and Management (1) 47
Item 13. Certain Relationships and Related
Transactions (1) 47
Part IV
Item 14. Exhibits, Financial Statement
Schedules and Reports on Form 8-K 48
</TABLE>
(1) Incorporated by reference from Notice and Proxy Statement for the
Annual Meeting of Shareholders to be held May 9, 2000.
2
<PAGE>
PART I
Items 1 and 2. Business and Properties
See pages 13 and 14 for explanations of abbreviations and terms used
herein.
General
Swift Energy Company, a Texas corporation formed in October 1979, engages
in the development, exploration, acquisition, and operation of oil and gas
properties with a primary focus on U.S. onshore natural gas reserves located in
Texas and Louisiana. As of December 31, 1999, we had interests in 1,557 wells
located in eight states. We operated 769 of these wells representing 93% our
proved reserves. At year-end 1999, we had estimated proved reserves of 454.8
Bcfe, of which approximately 73% was natural gas and 49% was proved developed.
Our proved reserves are concentrated 69% in Texas and 28% in Louisiana.
We currently focus primarily on development and exploration in four core
areas:
<TABLE>
<CAPTION>
% of Year-End % of 1999
Area Location 1999 Proved Reserves Production
-------------------- --------------------- --------------------------- ----------------
<S> <C> <C> <C>
AWP Olmos South Texas 46% 30%
Brookeland East Texas 16% 13%
Giddings South-Central Texas 6% 9%
Masters Creek West Louisiana 27% 41%
--------------------------- ---------------
% of Total 95% 93%
</TABLE>
The AWP Olmos area is characterized by long-lived reserves that we expect
to be steadily produced over a long period of time. The Brookeland, Giddings,
and Masters Creek areas are characterized by shorter-lived reserves with high
initial rates of production that decline rapidly. We believe these shorter-lived
reserves complement our long-lived reserves in the AWP Olmos area. Based on 1999
year-end proved reserves and 1999 production, our average reserve life was 10.6
years.
We purchased interests in the Brookeland and Masters Creek areas from Sonat
Exploration Company in the third quarter of 1998 for approximately $85.8 million
in cash. Of this purchase price, $55.5 million was spent for producing
properties, $15.0 million for 20% interests in two natural gas processing
plants, and $15.3 million for leasehold properties. This acquisition extended
our holdings in the Austin Chalk formation. Additionally, in late December 1999,
we purchased additional working interests in the Masters Creek area from
Dominion Reserves, Inc., for approximately $14.0 million and from Union Pacific
we purchased additional working interests in the S. Burr Ferry portion of the
Masters Creek area for approximately $1.9 million. The interests acquired from
Dominion have year-end 1999 proved reserves of 17.1 Bcfe, while the interests
acquired from Union Pacific have 7.4 Bcfe. We expect to use our operating
expertise in this geological trend to continue to successfully develop and
exploit these properties.
In addition to our continuing production, development, and exploration in
the AWP Olmos, Brookeland, Giddings, and Masters Creek areas, we are currently
pursuing development and exploration activities in the Gulf Coast Basin and New
Zealand.
Our strategy is to increase our reserves and production through both
drilling and acquisitions, shifting the balance between the two activities in
response to market conditions. In addition, we seek to enhance the results of
our drilling and production efforts through the implementation of advanced
technologies. During 1997, our growth resulted primarily from the acquisition of
additional acreage and increased drilling activities in the AWP Olmos and
Giddings areas. Capital expenditures for development and exploration drilling,
primarily in those two areas, were $101.0 million in 1997, while capital
expenditures for acquisitions were $8.4 million. As a result of lower oil and
gas prices during 1998, we reduced capital expenditures for drilling and
redirected a portion of those expenditures to the acquisition of producing
properties, primarily the Brookeland and Masters Creek areas. In 1998,
development and exploration drilling expenditures for the year, concentrated in
the first half of the year, totaled $67.4 million. We spent $59.5 million for
the acquisition of producing properties in 1998, almost all in the third quarter
of 1998.
3
<PAGE>
For 1999, in response to lower oil and gas prices in 1998 that continued in
the first half of 1999, we decreased our capital expenditures budget to $54.2
million, of which $36.0 million was targeted for drilling, $31.3 million for
development drilling, and $4.7 million for exploratory drilling. The remaining
$18.2 million was targeted principally for leasehold, seismic, and geological
costs of prospects. After oil and gas prices rebounded in the second half of the
year, we increased our capital expenditures during the fourth quarter. We funded
the $78.1 million of capital expenditures spent in 1999 primarily through our
internally generated cash flows of $73.6 million, while the remainder was funded
with net proceeds from our third quarter 1999 public offerings of common stock
and senior notes that remained after paying off our bank debt.
We have increased our proved reserves from 103.6 Bcfe at year-end 1994 to
454.8 Bcfe at year-end 1999, which has resulted in the replacement of 364% of
our production during the same five-year period. In 1999, we increased our
proved reserves by 4%, which replaced 144% of our 1999 production. Our five-year
average reserves replacement costs were $0.92 per Mcfe. As a result of both
acquisition and drilling activity, 1999 production increased 10% over 1998
production. We have increased our production from 9.6 Bcfe at year-end 1994 to
42.9 Bcfe at year-end 1999. Primarily due to increased production, this has
resulted in average annual growth in net cash provided by operating activities
of 48% per year from year-end 1994 to year-end 1999.
Properties
AWP Olmos Area. Our largest contiguous operation is in the AWP Olmos area
in south Texas. As of December 31, 1999, we owned approximately 33,530 net acres
here. We have extensive expertise in this area and a long history of experience
with low-permeability, tight-sand formations typical of this area, having
acquired our first acreage here in 1988. These reserves are approximately 93%
gas. At year-end 1999, we owned interests in and were the operator of 460 wells
in this area producing gas from the Olmos Sand formation at a depth of
approximately 10,000 to 11,500 feet. We, or entities we manage, own nearly 100%
of the working interests in all wells in which we have an interest here.
In 1999, we drilled six development wells in the AWP Olmos area, five of
which were successful. At year-end 1999, we had 141 proved undeveloped
locations. Our planned 2000 capital expenditures of $14.3 million in this area
will focus on drilling 12 wells and on wells currently on production, in which
we will perform fracture extensions and install coiled tubing velocity strings.
Brookeland Area. As of December 31, 1999, we owned drilling and production
rights in 134,400 gross acres, 84,000 net acres, and 15,000 fee mineral acres
containing substantial proved undeveloped reserves. This area was part of the
acquisition from Sonat in 1998. The Brookeland area is located in southeast
Texas near the border of Louisiana in Jasper and Newton counties. This area
primarily contains horizontal wells producing gas from the Austin Chalk
formation. The reserves are approximately 66% gas. In 1999, we drilled or
participated in the drilling of six development wells here, five of which were
successful. At year-end 1999, we had 31 proved undeveloped locations. We plan to
drill or participate in 10 development wells in 2000, five to be operated by us.
Our planned 2000 capital expenditures in this area are $10.3 million.
Giddings Area. As of December 31, 1999, we owned drilling and production
rights in 102,665 net acres in the Giddings area. This area is located in
Washington, Colorado, Fayette, and Austin counties in southeast Texas, where we
continue to selectively acquire acreage. Since 1992, we have participated in 82
horizontal wells in this area with an 87% success rate. The reserves are
approximately 83% gas. In 1999, two development wells were drilled, both
successfully. Also two exploratory wells were drilled, with one success. We
attribute our success in this area, which primarily produces from the Austin
Chalk formation, to our ability to identify hydrocarbon-bearing fractures
through our expertise in geological and geophysical analyses and to our ability
to drill and operate horizontal wells through advanced horizontal drilling
techniques. In addition to the Austin Chalk formation, we have targeted
exploration projects in the Edwards Lime formation. At year-end 1999, we had
eight proved undeveloped locations. The drilling of two additional development
wells and four exploratory wells are planned for 2000. Our planned 2000 capital
expenditures in this area are $6.7 million.
We have established a number of joint ventures with industry partners to
further develop and explore this area, including:
Chevron USA Production Company. This joint venture encompasses a
development area of 144,000 gross acres in Fayette, Colorado, and Austin
counties, with 77,000 net acres currently under lease. Swift and Chevron each
own a 50% working interest, we serve as operator, and any additional leased
acreage will be shared and operated on the same basis. To date, we have drilled
two exploratory wells, one of which was successful, and one successful
development well.
4
<PAGE>
Union Pacific Resources.
o We have a 25% working interest in a joint development area
covering approximately 17,000 gross acres in Washington County,
Texas. Union Pacific acts as the operator in this venture.
o We own a 50% working interest in another joint development area,
also in Washington County, covering approximately 6,300 gross
acres. Union Pacific or we act as the operator in this venture,
dependent upon the formation targeted.
o We own a 75% working interest and serve as operator for a joint
venture covering approximately 8,100 gross acres in Washington and
Austin counties.
Masters Creek Area. As of December 31, 1999, we owned drilling and
production rights in 195,000 gross acres, 148,000 net acres, and 141,000 fee
mineral acres in this area containing substantial proved undeveloped reserves.
This area was also part of the acquisition from Sonat in 1998. It is located
near the Texas-Louisiana border in the two parishes of Vernon and Rapides in
Louisiana. The Masters Creek area contains horizontal wells producing both oil
and gas from the Austin Chalk formation. The reserves are approximately 42% gas.
In 1999, we drilled or participated in the drilling of five development wells,
all of which were successful. At year-end 1999, we had 21 proved undeveloped
locations. We plan to drill or participate in 12 development wells in 2000, with
six to be operated by us. Two of these development wells to be drilled by us are
in the S. Burr Ferry portion of this area. We also plan to drill one exploratory
well to test the Saratoga formation. Our planned 2000 capital expenditures in
this area are $23.7 million.
Exploration and Development Drilling Activities
We pursue a "controlled risk" approach to exploratory and development
drilling, focusing our activities on specific U.S. regions in which our
technical staff has considerable experience and which are located close to known
producing horizons. We seek to minimize our exploration risk by investing in
multiple prospects, farming out interests to third parties, using advanced
technologies, and drilling in diverse types of geological formations, often in
areas with multiple objectives. We use basin studies to analyze targeted
formations based on their potential size, risk profile, and economic
characteristics.
In 1991, we began an intensive effort to develop an inventory of
exploration and development drilling prospects, identifying drilling locations
through integrated geological and geophysical studies of our undeveloped acreage
and other prospects. As a result, we added 120 Bcfe of proved reserves through
drilling in 1997, 73.9 Bcfe in 1998, and 64.9 Bcfe in 1999. In the second half
of 1998, in response to lower oil and gas prices, we deferred drilling projects
scheduled for the second half of the year and continued into 1999 with a
conservative drilling budget. Accordingly, reserves added by drilling were lower
in 1998 and 1999 compared to 1997, when market conditions were more favorable to
drilling. The 1999 additions were a result of our development success rate of
86%, as 19 of 22 development wells drilled were successful, and one of five
exploratory wells was successful. An additional well, our New Zealand Rimu-A1
well, was classified as "under evaluation," as we were not able to estimate
proved reserves at year-end. Therefore, the 64.9 Bcfe of reserves added through
drilling in 1999 does not include any reserves added from the Rimu-A1 well in
New Zealand. We believe that this discovery will result in proved reserves, and
we will estimate reserves on this well after we feel we have sufficient
sustained production testing data and other such analysis that we deem necessary
in order to make a reasonable reserves estimate.
Our development strategy is designed to maximize the value and productivity
of our existing properties through development drilling and recovery methods,
enhancing production results through improved field production techniques,
lowering production costs, and applying our technical expertise and resources to
exploit producing properties efficiently. The Company utilizes various recovery
techniques, which include employing water flooding and acid treatments,
fracturing reservoir rock through the injection of high-pressure fluid, and
inserting coiled tubing velocity strings to enhance and maintain gas flow. We
believe that the application of fracturing technology and coiled tubing has
resulted in significant increases in production and decreases in completion and
operating costs, particularly in our AWP Olmos Field.
Our exploration and development activities are conducted by our staff of
professionals, including reservoir engineers, geologists, geophysicists,
petrophysicists, landmen, and drilling and production engineers. We believe that
one of the keys to our success has been our team approach, which integrates
multiple disciplines to maximize efficient utilization of information leading to
drillable projects.
We have increasingly used advanced seismic technology to enhance the
results of our drilling and production efforts, including 2-D and 3-D seismic
analysis, amplitude versus offset studies, and detailed formation depletion
studies. We have a number of computer workstations from which seismic data is
analyzed and enhanced with advanced software programs, including Landmark,
Geographix, and SMT workstations. As a result, we have maintained internal
seismic expertise and have compiled an extensive database.
5
<PAGE>
During 1997, we completed our first international seismic acquisition
program in two key areas of our holdings in New Zealand. In the Rimu prospect,
we acquired a 30-kilometer cross-swath, as well as 2-D seismic data in the Tawa
prospect, complementing existing 2-D and 3-D data. We also acquired 21 miles of
2-D data in the AWP Olmos area in south Texas and 51 miles of data in the
Fayette County portion of the Giddings area. Two more prospects in the North
Louisiana Salt Basin were shot in the form of 2-D swaths of approximately 16
miles each. During 1998, we performed two additional 2-D acquisitions in Fayette
County, Texas.
We are currently designing a New Zealand seismic acquisition project to
develop the Rimu-A1 well discovery and a prospect target to the southeast of an
adjacent offshore feature. This seismic program will straddle the coastline to
acquire transition zone seismic data extending into the offshore area in order
to tie into existing marine and onshore seismic data. This should enable us to
answer a multitude of exploration and development questions. This project is
scheduled for completion in the second quarter of 2000.
In addition to development and exploration activities in the AWP Olmos,
Brookeland, Giddings, and Masters Creek areas, we are currently pursuing
development and exploration activities in the Gulf Coast Basin and in New
Zealand.
Gulf Coast Basin. This area includes all the Texas counties and Louisiana
parishes along the Gulf Coast and extending into Mississippi and Alabama. In
1999, we drilled two successful development wells out of three and one
unsuccessful exploratory well in this area. In 2000, four exploratory wells are
scheduled for drilling in the Gulf Coast Basin, all in Texas. Our planned 2000
capital expenditures in this area are $3.6 million.
New Zealand. After several years of preparation, including the acquisition
and analyses of seismic data, an exploratory well commenced drilling in July
1999 and drilled to its total depth. The Rimu-A1 well was completed and a
ten-day production draw-down/build-up test was performed. Also, on October 18,
1999, we expanded this permit to include approximately 12,800 adjacent offshore
acres. This expanded permit now contains approximately 100,700 acres. We have
committed to perform additional seismic acquisition and analysis on the permit
area, are evaluating longer-term sustained testing of this well, and are
analyzing further delineation activities on the Rimu block.
The following table sets forth the results of our drilling activities
during the three years ended December 31, 1999:
<TABLE>
<CAPTION>
Gross Wells Net Wells
------------------------------------------ -----------------------------------------
Under Under
Year Type of Well Total Producing Dry Evaluation(1) Total Producing Dry Evaluation(1)
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1997 Exploratory 15 7 8 -- 7.2 2.7 4.5 --
Development 167 159 8 -- 127.5 123.6 3.9 --
1998 Exploratory 14 5 9 -- 8.7 2.7 6.0 --
Development 61 53 8 -- 37.7 32.8 4.9 --
1999 Exploratory 5 1 3 1 2.4 0.3 1.2 0.9
Development 22 19 3 -- 10.7 9.4 1.3 --
</TABLE>
(1) Our New Zealand Rimu-A1 well is classified as "under evaluation" as we
were not able to estimate proved reserves at year-end. We believe that this
discovery will result in proved reserves, and we will estimate reserves on this
well after we feel we have sufficient sustained production testing data and
other such analysis that we deem necessary in order to make a reasonable
reserves estimate.
6
<PAGE>
Operations
We generally seek to be named as operator in wells in which we have
significant economic interest. As operator, we design and manage the development
of a well and supervise operation and maintenance activities on a day-to-day
basis. We do not own drilling rigs or other oil field services equipment used
for drilling or maintaining wells on properties we operate. Independent
contractors supervised by us provide all the equipment and personnel. We employ
drilling, production and reservoir engineers, geologists, and other specialists
who work to improve production rates, increase reserves, and lower the cost of
operating our oil and gas properties.
Oil and gas properties are customarily operated under the terms of a joint
operating agreement. These agreements usually provide for reimbursement of the
operator's direct expenses and for payment of monthly per-well supervision fees.
Supervision fees vary widely depending on the geographic location and depth of
the well and whether the well produces oil or gas. The fees for these activities
paid to us in 1999 ranged from $200 to $2,101 per well per month and totaled
$6.0 million.
Marketing of Production
We typically sell our oil and gas production at market prices near the
wellhead, although in some cases it must be gathered by us or other operators
and delivered to a central point. Gas production is sold in the spot market on a
monthly contract basis, while we sell our oil production at prevailing market
prices at the time of sale. We do not refine any oil we produce. For the year
ended December 31, 1999, one purchaser accounted for approximately 19% of our
total revenues. Two oil or gas purchasers accounted for 10% or more of our total
revenues during the year ended December 31, 1998, with those purchasers
accounting for approximately 26% of revenues in the aggregate. However, due to
the availability of other purchasers, we do not believe that the loss of any
single oil or gas purchaser or contract would materially affect our revenues.
In 1998, we entered into gas processing and gas transportation agreements
for our gas production in the AWP Olmos area with PG&E Hydrocarbon, LP, and PG&E
Industrial, LP, both affiliates of Pacific Gas & Electric Corporation for up to
75,000 Mcf per day, which provided for a ten-year term with automatic one-year
extensions unless earlier terminated. We believe that these arrangements
adequately provide for our gas transportation and processing needs in the AWP
Olmos area for the foreseeable future. Additionally, the gas processed and
transported under these agreements may be sold to PG&E based upon current
natural gas prices.
Much of our Giddings area production from Fayette and Washington counties,
Texas, is currently dedicated under long-term gas purchase and gas processing
contracts with Aquila Southwest Pipeline Corporation ("Aquila"). We believe that
these contracts adequately provide for the gas purchase and processing needs of
our Giddings area production, subject to practical limitations inherent in gas
field operations. The prices received are redetermined monthly to reflect the
current natural gas price.
Our oil production from the Brookeland and Masters Creek areas is sold to
credit-worthy purchasers at prevailing market prices. Our gas production from
these areas is processed under long-term gas processing contracts with Duke
Energy Field Services, Inc. The processed liquids and residue gas production are
sold in the spot market.
The following table summarizes sales volumes, sales prices, and production
cost information for our net oil and gas production for the three-year period
ended December 31, 1999. "Net" production is production that is owned by us
either directly or indirectly through partnerships or joint venture interests
and is produced to our interest after deducting royalty, limited partner, and
other similar interests.
7
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------------
1999 1998 1997
------------------- ---------------------- ------------------
<S> <C> <C> <C>
Net Sales Volume:
Oil (Bbls) 2,564,924 1,800,676 672,385
Gas (Mcf)(1) 27,484,759 28,225,974 21,359,434
Gas equivalents (Mcfe) 42,874,303 39,030,030 25,393,744
Average Sales Price:
Oil (Per Bbl) $ 16.75 $ 11.86 $ 17.59
Gas (Per Mcf) $ 2.40 $ 2.08 $ 2.68
Average Production Cost (per Mcfe) $ 0.46 $ 0.34 $ 0.35
</TABLE>
(1) Natural gas production for 1999, 1998, and 1997 includes 728,235,
866,232, and 1,015,226 Mcf, respectively, delivered under the volumetric
production payment agreement pursuant to which we are obligated to deliver
certain monthly quantities of natural gas (see Note 1 to the Consolidated
Financial Statements).
Under the volumetric production payment entered into in 1992, as of
December 31, 1999, we have a remaining commitment to deliver approximately 0.4
Bcf of gas meeting certain heating equivalent and quality standards through
October 2000, when such agreement expires. Since entering into this agreement,
these properties have produced in excess of the required monthly delivery
requirements.
Acquisition Activities
We use a disciplined, market-driven approach to acquisitions. Generally we
seek to acquire properties with the potential for additional reserves and
production through development and exploration efforts. In 136 transactions
since 1979, we have acquired approximately $556 million of producing oil and gas
properties on behalf of ourselves and our co-investors. We acquired, for our own
account, approximately $199.5 million of producing properties, with original
proved reserves estimated at 300.0 Bcfe. Our producing property acquisition
expenditures in the past three years were $18.5 million in 1999, $59.5 million
in 1998, and $8.4 million in 1997. Our acquisition costs have averaged $0.57 per
Mcfe over this three-year period.
Foreign Activities
New Zealand. Since October 1995, the New Zealand Minister of Energy has
issued to Swift two petroleum exploration permits. The first permit covered
approximately 65,000 acres in the Onshore Taranaki Basin of New Zealand's North
Island, and the second covered approximately 69,300 adjacent acres. A wholly
owned subsidiary, Swift Energy New Zealand Limited, formed in late 1997,
conducts our New Zealand activities and owns the interest in the permits. We
conducted a 2-D seismic swath on our permit areas in 1997 that complemented
approximately 120 kilometers of existing 2-D seismic data. Based on analysis of
all of this data, in March 1998 we surrendered approximately 46,400 acres
covered in the first permit, and the remaining acreage has been included as an
extension of the area covered in the second permit, leaving us with only one
expanded permit. On October 18, 1999, this expanded permit was again extended to
include approximately 12,800 adjacent offshore acres. This permit now contains
approximately 100,700 acres. Under the terms of the expanded permit, we were
required to commence drilling one exploratory well prior to August 12, 1999.
That exploratory well commenced drilling in July 1999 and has been drilled
to its total depth. The Rimu-A1 well was completed and a ten-day production
draw-down/build-up test was performed. Our portion of the drilling, completion,
and testing costs incurred at December 31, 1999, were approximately $6.9
million. We have committed to perform additional seismic acquisition and
analysis on the permit area, are evaluating longer-term sustained testing of
this well, and are analyzing further delineation activities on the Rimu block.
While this further work is necessary in order for us to make a meaningful
reserves estimate, we feel confident that the reserves are sufficient to recover
our costs. All other obligations under the permit have been fulfilled.
On October 23, 1998, we entered into separate agreements with Marabella
Enterprises Ltd., a subsidiary of Bligh Oil & Minerals N.L., an Australian
company, under which we obtained from Marabella a 25% working interest in
another New Zealand petroleum exploration permit and under which Marabella
became a 5% participant in our permit. During the fourth quarter of 1998,
Marabella drilled an unsuccessful exploration well on its permit. Accordingly,
we charged $400,000 against earnings, representing our costs for the well.
Additionally, Swift obtained a 7.5% working interest in another New Zealand
permit from Antrim Oil and Gas Limited, a Canadian company, and Antrim became a
5% participant in our permit. An exploratory well was drilled and temporarily
abandoned on Antrim's permit during the second quarter of 1999, and we charged
our $290,000 portion of the costs on this well against earnings in that quarter.
8
<PAGE>
As of December 31, 1999, our investment in New Zealand totaled
approximately $12.5 million. Approximately $0.7 million of these costs have been
impaired while the remaining $11.8 million is included in the unproved
properties portion of oil and gas properties.
Russia. On September 3, 1993, we signed a Participation Agreement with
Senega, a Russian Federation joint stock company (in which we have an indirect
interest of less than 1%), to assist in the development and production of
reserves from two fields in Western Siberia, providing us with a minimum 5% net
profits interest from the sale of hydrocarbon products from the fields.
Additionally, we purchased a 1% net profits interest from Senega for $0.3
million. Senega is charged with the management and control of the field
development. Our investment in Russia, prior to its impairment in the third
quarter of 1998, was approximately $10.8 million and was previously included in
the unproved properties portion of oil and gas properties. However, the economic
and political uncertainty and currency concerns that arose during the third
quarter of 1998 in Russia, combined with the price volatility and severe
tightening of international capital markets, caused us to re-evaluate the timing
of the recovery of our capitalized costs in that country. See Note 1 to the
Consolidated Financial Statements for a more detailed discussion of the
impairment.
Venezuela. We formed a wholly owned subsidiary, Swift Energy de Venezuela,
C. A., for the purpose of submitting a bid on August 5, 1993, under the
Venezuelan Marginal Oil Field Reactivation Program. We have entered into an
agreement with Tecnoconsult, S. A., and Corporation EDC, S.A.C.A., Venezuelan
companies, to jointly formulate and submit a proposal to Petroleos de Venezuela,
S. A., for the construction and operation of a methane pipeline. Currently, the
technical and economic feasibility of the project is under study. Our investment
in Venezuela, prior to its impairment in the third quarter of 1998, was
approximately $2.8 million and was previously included in the unproved
properties portion of oil and gas properties. However, the economic uncertainty
and currency concerns in Venezuela, combined with the price volatility and
severe tightening of international capital markets, caused us to re-evaluate our
prospects of participating in further Venezuelan exploration activities in the
near-term and the prospects for recovery of our capitalized costs in that
country. See Note 1 to the Consolidated Financial Statements for a more detailed
discussion of the impairment.
Oil and Gas Reserves
The following table presents information regarding proved reserves of oil
and gas attributable to our interests in producing properties as of December 31,
1999, 1998, and 1997. The information set forth in the table is based on proved
reserves reports prepared by us and audited by H. J. Gruy and Associates, Inc.,
Houston, Texas, independent petroleum engineers. Gruy's audit was based upon
review of production histories and other geological, economic, ownership, and
engineering data provided by us. In accordance with Securities and Exchange
Commission guidelines, our estimates of future net revenues from our proved
reserves and the PV-10 Value are made using oil and gas sales prices in effect
as of the dates of such estimates and are held constant throughout the life of
the properties, except where such guidelines permit alternate treatment,
including, in the case of gas contracts, the use of fixed and determinable
contractual price escalations. Proved reserves as of December 31, 1999, were
estimated based upon prices in effect at year-end. The weighted averages of such
year-end prices were $2.58 per Mcf of natural gas and $23.69 per barrel of oil,
compared to $2.23 and $11.23 in 1998 and $2.78 and $15.76 in 1997. We have
interests in certain tracts that are estimated to have additional hydrocarbon
reserves that cannot be classified as proved and are not reflected in the
following table. The proved reserves presented for all periods also exclude any
reserves attributable to the volumetric production payment.
The table sets forth estimates of future net revenues presented on the
basis of unescalated prices and costs in accordance with criteria prescribed by
the Securities and Exchange Commission and their PV-10 Value. Operating costs,
development costs, and certain production-related taxes were deducted in
arriving at the estimated future net revenues. No provision was made for income
taxes. The estimates of future net revenues and their present value differ in
this respect from the standardized measure of discounted future net cash flows
set forth in Supplemental Information to our Consolidated Financial Statements,
which is calculated after provision for future income taxes. In cases where
producing properties are subject to gas purchase contracts and the amount of gas
purchased thereunder was reduced during 1999, gas projections used to estimate
future net revenues were based on the reduced gas purchases for the affected
producing properties. The assumption was made that purchases in 2000 and
thereafter will be made at an unrestricted level.
9
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------
1999 1998 1997
---------------- ----------------- ------------------
<S> <C> <C> <C>
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed 174,046,096 197,105,963 191,108,214
Proved undeveloped 155,913,654 155,294,872 123,197,455
---------------- ----------------- ------------------
Total 329,959,750 352,400,835 314,305,669
================ ================= ==================
Net oil reserves (Bbl):
Proved developed 8,437,299 7,142,566 4,288,696
Proved undeveloped 12,368,964 6,815,359 3,570,222
---------------- ----------------- ------------------
Total 20,806,263 13,957,925 7,858,918
================ ================= ==================
Estimated Present Value of Proved Reserves
Estimated present value of future net
cash flows from proved reserves discounted
at 10% per annum:
Proved developed $ 301,199,660 $ 243,124,194 $ 244,365,044
Proved undeveloped 262,854,849 97,660,811 105,979,738
---------------- ----------------- ------------------
Total $ 564,054,509 $ 340,785,005 $ 350,344,782
================ ================= ==================
</TABLE>
At year-end 1999, 51% of the proved reserves were undeveloped reserves.
This reflects the increased emphasis on development and exploration activities.
In 1998, 45% of proved reserves were undeveloped and 55% were proved developed.
Changes in quantity estimates and the estimated present value of proved
reserves are affected by the change in crude oil and natural gas prices at the
end of each year. While our total proved reserves quantities, on an equivalent
Bcfe basis, at year-end 1999 increased by 4% over reserves quantities a year
earlier, the PV-10 Value of those reserves increased 66% from the PV-10 Value at
year-end 1997. This increase was due almost entirely to pricing increases at
year-end 1999 as compared to year-end 1998. Product prices for natural gas
increased 16% during 1999, from $2.23 per Mcf at December 31, 1998, to $2.58 per
Mcf at year-end 1999, while oil prices increased 111% between the two dates,
from $11.23 to $23.69 per barrel. Conversely, while our total proved reserves
quantities at year-end 1998 increased by 21% over reserves quantities a year
earlier, the PV-10 Value of those reserves decreased 3% from the PV-10 Value at
year-end 1997. This decrease was due almost entirely to pricing declines at
year-end 1998 as compared to year-end 1997, which more than offset the 21% Bcfe
increase in reserves quantities. Product prices for natural gas declined 20%
during 1998, from $2.78 per Mcf at December 31, 1997, to $2.23 per Mcf at
year-end 1998, matched by a 29% decrease in the price of oil between the two
dates, from $15.76 to $11.23 per barrel.
Proved reserves are estimates of hydrocarbons to be recovered in the
future. Reservoir engineering is a subjective process of estimating the sizes of
underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserves estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserves reports of other engineers might differ from the reports contained
herein. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimate. Future prices received for
the sale of oil and gas may be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, reserves estimates are often different
from the quantities of oil and gas that are ultimately recovered. There can be
no assurance that these estimates are accurate predictions of the present value
of future net cash flows from oil and gas reserves.
A portion of our proved reserves have been accumulated through our
interests in the limited partnerships for which we serve as general partner. The
estimates of future net cash flows and their present values, based on period end
prices, assume that some of the limited partnerships in which we own interests
will achieve payout status in the future. At December 31, 1999, 22 of the
limited partnerships managed by us had achieved payout status.
No other reports on our reserves have been filed with any federal agency.
10
<PAGE>
Oil and Gas Wells
The following table sets forth the gross and net wells in which we owned an
interest at the following dates:
<TABLE>
<CAPTION>
Total
Oil Wells Gas Wells Wells(1)
---------- ----------- -----------
<S> <C> <C> <C>
December 31, 1999
Gross 577 947 1,524
Net 105.5 449.2 554.7
December 31, 1998
Gross 657 1,060 1,717
Net 89.4 494.5 583.9
December 31, 1997
Gross 625 926 1,551
Net 48.1 381.7 429.8
</TABLE>
(1) Excludes 33 service wells in 1999, 36 service wells in 1998, and 16 service
wells in 1997.
Oil and Gas Acreage
As is customary in the industry, we generally acquire oil and gas acreage
without any warranty of title except as to claims made by, through, or under the
transferor. Although we have title to developed acreage examined prior to
acquisition in those cases in which the economic significance of the acreage
justifies the cost, there can be no assurance that losses will not result from
title defects or from defects in the assignment of leasehold rights. In many
instances, title opinions may not be obtained if in our judgment it would be
uneconomical or impractical to do so.
The following table sets forth the developed and undeveloped domestic
leasehold acreage held by us at December 31, 1999:
<TABLE>
<CAPTION>
Developed (1) Undeveloped (1)
--------------------------- -----------------------------
Gross Net Gross Net
------------ ------------ ------------- -------------
<S> <C> <C> <C> <C>
Alabama 4,495.38 616.70 292.00 72.90
Arkansas 1,242.35 699.71 6,420.87 2,418.89
Kansas --- --- 4,520.00 1,908.80
Louisiana 99,799.02 57,987.62 127,795.19 100,145.95
Mississippi 2,395.39 1,527.99 2,807.42 744.78
Oklahoma 29,925.90 13,600.59 2,589.04 590.21
Texas 232,571.92 142,625.49 247,041.48 124,600.34
Wyoming 2,338.15 1,233.04 116,881.90 79,721.63
All other states --- --- 5,928.45 981.43
------------ ------------ ------------- -------------
Total 372,768.11 218,291.14 514,276.35 311,184.93
============ ============ ============= =============
</TABLE>
(1) Fee minerals acquired in the Brookeland and Master Creek areas
acquisition are not included in the above leasehold acreage table. We acquired
25,430 developed fee mineral acres and 115,570 undeveloped fee mineral acres for
a total of 141,000 fee mineral acres.
In New Zealand, petroleum exploration permits that we own or participate in
contain 188,836 gross undeveloped acres and 101,052 net undeveloped acres.
Partnerships
For many years, we relied on limited partnerships as our principal vehicle
to fund our operations. We have formed 109 limited partnerships that raised a
total of approximately $509.5 million. However, as we have increasingly shifted
our emphasis to development and exploration activities and our reserves base has
grown, we have significantly reduced our reliance on limited partnership
financing.
Between 1984 and 1995, we formed 88 limited partnerships for the purpose of
acquiring interests in producing oil and gas properties and, since 1993, 13
partnerships engaged in drilling for oil and gas reserves.
11
<PAGE>
We serve as managing general partner of these entities. We acquired producing
oil and gas properties for the production purchase partnerships and transferred
those properties to the partnership entities that invested in producing oil and
gas properties. Various producing property partnerships have been in existence
for periods ranging from four to thirteen years. Most of these partnerships have
produced a majority of their reserves and, having been in existence for long
periods of time, have entered the stage where consideration of liquidation
proposals is appropriate.
During 1997 and 1998, 21 of these partnerships were liquidated following a
vote of the limited partners in each of those partnerships to do so. Ten of
these 21 partnerships were the earliest public income partnerships formed by
Swift. As of early March 2000, an additional 10 partnerships voted to sell
substantially all of their assets and liquidate, and the efforts to sell their
assets have just commenced. Also in February and early March 2000, proxy
statements were sent to the investors in 55 of the 57 remaining production
purchase partnerships soliciting their votes upon proposals to sell their assets
and liquidate. The proxy statements for the remaining two partnerships will be
mailed shortly. If these proposals are approved, it is anticipated that these
liquidations will be substantially completed during 2000 and, if necessary,
2001.
Commencing in September 1993, we began offering, on a private placement
basis, general and limited partnership interests in limited partnerships to be
formed to drill for oil and gas. As managing general partner, we pay a
percentage of the continuing costs and we paid for all front-end costs incurred
in connection with these offerings, for which we received an interest in the
partnerships. Through December 31, 1999, approximately $66.1 million had been
raised in thirteen partnerships, one each formed in 1993 and 1994; three each in
1995, 1996, and 1997; and two in 1998. During 1997, eight private drilling
partnerships formed between 1979 and 1985 were liquidated following limited
partner votes to do so.
Risk Management
Our operations are subject to all of the risks normally incident to the
exploration for and the production of oil and gas, including blowouts,
cratering, pipe failure, casing collapse, oil spills, and fires, each of which
could result in severe damage to or destruction of oil and gas wells, production
facilities or other property, or individual injuries. The oil and gas
exploration business is also subject to environmental hazards, such as oil
spills, gas leaks, and ruptures and discharges of toxic substances or gases that
could expose us to substantial liability due to pollution and other
environmental damage. Additionally, as managing general partner of limited
partnerships, we are solely responsible for the day-to-day conduct of the
limited partnerships' affairs and accordingly have liability for expenses and
liabilities of the limited partnerships. We maintain comprehensive insurance
coverage, including general liability insurance in an amount not less than $35.0
million, as well as general partner liability insurance. We believe that our
insurance is adequate and customary for companies of a similar size engaged in
comparable operations, but losses could occur for uninsurable or uninsured risks
or in amounts in excess of existing insurance coverage.
Competition
The oil and gas industry is highly competitive in all its phases. We
encounter strong competition from many other oil and gas producers, including
many that possess substantial financial resources, in acquiring economically
desirable producing properties and exploratory drilling prospects, and in
obtaining equipment and labor to operate and maintain our properties.
Regulations
Environmental Regulations
The federal government and various state and local governments have adopted
laws and regulations regarding the protection of human health and the
environment. These laws and regulations may require the acquisition of a permit
by operators before drilling commences, prohibit drilling activities on certain
lands lying within wilderness areas, wetlands, or where pollution might cause
serious harm, and impose substantial liabilities for pollution resulting from
drilling operations, particularly with respect to operations in onshore and
offshore waters or on submerged lands. These laws and regulations may increase
the costs of drilling and operating wells. Because these laws and regulations
change frequently, the costs of compliance with existing and future
environmental regulations cannot be predicted with certainty.
Federal and State Regulation of Oil and Natural Gas
The transportation and certain sales of natural gas in interstate commerce
are heavily regulated by agencies of the federal government. Production of any
oil and gas by us will be affected to some degree by state regulations. Many
states in which we operate have statutory provisions regulating the production
and sale
12
<PAGE>
of oil and gas, including provisions regarding deliverability. Such statutes,
and the regulations promulgated in connection therewith, are generally intended
to prevent waste of oil and gas and to protect correlative rights to produce oil
and gas between owners of a common reservoir. Certain state regulatory
authorities also regulate the amount of oil and gas produced by assigning
allowable rates of production to each well or proration unit.
Federal Leases
Some of our properties are located on federal oil and gas leases
administered by various federal agencies, including the Bureau of Land
Management. Various regulations and orders affect the terms of leases,
exploration and development plans, methods of operation, and related matters.
Employees
At December 31, 1999, we employed 173 persons. None of our employees are
represented by a union. Relations with employees are considered to be good.
Facilities
We occupy approximately 75,000 square feet of office space at 16825
Northchase Drive, Houston, Texas, under a ten year lease expiring in 2005. The
lease requires payments of approximately $96,000 per month. We have field
offices in various locations from which our employees supervise local oil and
gas operations.
Glossary of Abbreviations and Terms
The following abbreviations and terms have the indicated meanings when used in
this report:
Bbl -- Barrel or barrels of oil.
Bcf -- Billion cubic feet of natural gas.
Bcfe -- Billion cubic feet of natural gas equivalent (see Mcfe).
Development Well -- A well drilled within the presently proved productive area
of an oil or natural gas reservoir, as indicated by reasonable interpretation
of available data, with the objective of completing in that reservoir.
Discovery Cost -- With respect to proved reserves, a three-year average (unless
otherwise indicated) calculated by dividing total incurred exploration and
development costs (exclusive of future development costs) by net reserves
added during the period through extensions, discoveries, and other additions.
Dry Well -- An exploratory or development well that is not a producing well.
Exploratory Well -- A well drilled either in search of a new, as yet
undiscovered oil or natural gas reservoir or to greatly extend the known
limits of a previously discovered reservoir.
Gross Acre -- An acre in which a working interest is owned. The number of gross
acres is the total number of acres in which a working interest is owned.
Gross Well -- A well in which a working interest is owned. The number of gross
wells is the total number of wells in which a working interest is owned.
MBbl -- Thousand barrels of oil.
Mcf -- Thousand cubic feet of natural gas.
Mcfe -- Thousand cubic feet of natural gas equivalent, which is determined using
the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of
natural gas.
MMBbl -- Million barrels of oil.
MMBtu -- Million British thermal units, which is a heating equivalent measure
for natural gas and is an alternate measure of natural gas reserves, as
opposed to Mcf, which is strictly a measure of natural gas
13
<PAGE>
volumes. Typically, prices quoted for natural gas are designated as price per
MMBtu, the same basis on which natural gas is contracted for sale.
MMcf -- Million cubic feet of natural gas.
MMcfe -- Million cubic feet of natural gas equivalent (see Mcfe).
Net Acre -- A net acre is deemed to exist when the sum of fractional ownership
working interests in gross acres equals one. The number of net acres is the
sum of fractional working interests owned in gross acres expressed as whole
numbers and fractions thereof.
Net Well -- A net well is deemed to exist when the sum of fractional ownership
working interests in gross wells equals one. The number of net wells is the
sum of fractional working interests owned in gross wells expressed as whole
numbers and fractions thereof.
Producing Well -- An exploratory or development well found to be capable of
producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.
Proved Developed Oil and Gas Reserves -- Reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
Proved Oil and Gas Reserves -- The estimated quantities of crude oil, natural
gas, and natural gas liquids that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, that is, prices
and costs as of the date the estimate is made.
Proved Undeveloped Oil and Gas Reserves -- Reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
PV-10 Value -- The estimated future net revenue to be generated from the
production of proved reserves discounted to present value using an annual
discount rate of 10%. These amounts are calculated net of estimated production
costs and future development costs, using prices and costs in effect as of a
certain date, without escalation and without giving effect to non-property
related expenses, such as general and administrative expenses, debt service,
future income tax expense, or depreciation, depletion, and amortization.
Reserves Replacement Cost -- With respect to proved reserves, a three-year
average (unless otherwise indicated) calculated by dividing total incurred
acquisition, exploration, and development costs (exclusive of future
development costs) by net reserves added during the period.
Volumetric Production Payment -- The 1992 agreement pursuant to which we
financed the purchase of certain oil and natural gas interests and committed to
deliver certain monthly quantities of natural gas.
14
<PAGE>
Item 3. Legal Proceedings
Litigation arises from time to time in the ordinary course of Swift's
business. Since early 1997, a case has been pending between Swift and the Lower
Colorado River Authority in the 155th Judicial District Court of Fayette County,
Texas, over the interpretation of a farmout agreement covering land in that
county and the entitlement of the parties to the farmout to production revenues
from wells on those lands. This case was settled in the latter half of 1999,
partially through the negotiated purchase by Swift of certain interests of the
Lower Colorado River Authority in these properties.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted during the fourth quarter of 1999 to a vote of
security holders.
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters
COMMON STOCK, 1998 AND 1999
Our common stock is traded on the New York Stock Exchange and the Pacific
Exchange, Inc., under the symbol "SFY." The high and low quarterly sales prices
for the common stock for 1998 and 1999 are as follows:
<TABLE>
<CAPTION>
1998 1999
------------------------------------- -------------------------------------
First Second Third Fourth First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
------------------------------------- -------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Low $15.88 $15.00 $8.81 $6.94 $5.69 $8.25 $10.25 $10.31
High $21.00 $20.75 $16.75 $11.19 $8.63 $13.13 $13.13 $13.31
</TABLE>
Since inception, no cash dividends have been declared on our common stock.
Cash dividends are restricted under the terms of our credit agreements, as
discussed in Note 4 to the Consolidated Financial Statements, and we presently
intend to continue a policy of using retained earnings for expansion of our
business.
We had approximately 488 stockholders of record as of December 31, 1999.
15
<PAGE>
Item 6. Selected Financial Data
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995
Revenues
<S> <C> <C> <C> <C> <C>
Oil and Gas Sales $108,898,696 $80,067,837 $69,015,189 $52,770,672 $22,527,892
Fees and Earned Interests(2) $229,749 $333,940 $745,856 $937,238 $590,441
Interest Income $833,204 $107,374 $2,395,406 $433,352 $212,329
Other, Net $709,358 $1,960,070 $2,555,729 $2,156,764 $1,761,568
Total Revenues $110,671,007 $82,469,221 $74,712,180 $56,298,026 $25,092,230
Operating Income (Loss) $29,736,151 ($73,391,581) $33,129,606 $28,785,783 $6,894,537
Net Income (Loss) $19,286,574 ($48,225,204) $22,310,189 $19,025,450 $4,912,512
Net Cash Provided by Operating Activities $73,603,426 $54,249,017 $55,255,965 $37,102,578 $14,376,463
Per Share Data
Weighted Shares Outstanding(3) 18,050,106 16,436,972 16,492,856 15,000,901 10,035,143
Earnings (Loss) per Share--Basic(3) $1.07 ($2.93) $1.35 $1.27 $0.49
Earnings (Loss) per Share--Diluted(3) $1.07 ($2.93) $1.26 $1.25 $0.49
Shares Outstanding at Year-End 20,823,729 16,291,242 16,459,156 15,176,417 12,509,700
Book Value per Share $8.18 $6.71 $9.69 $9.41 $7.46
Market Price(3)
High $13.31 $21.00 $34.20 $28.86 $11.48
Low $5.69 $6.94 $16.93 $9.89 $7.05
Year-End Close $11.50 $7.38 $21.06 $27.16 $10.91
Pro forma amounts assuming 1994 change in
accounting principle is applied retroactively(2)
Net Income (Loss) $19,286,574 ($48,225,204) $22,310,189 $19,025,450 $4,912,512
Earnings (Loss) per Share--Basic (3) $1.07 ($2.93) $1.35 $1.27 $0.49
Earnings (Loss) per Share--Diluted (3) $1.07 ($2.93) $1.26 $1.25 $0.49
Assets
Current Assets $50,605,488 $35,246,431 $29,981,786 $101,619,478 $43,380,454
Oil and Gas Properties, Net of Accumulated
Depreciation, Depletion, and Amortization $392,986,589 $356,711,711 $301,312,847 $200,010,375 $125,217,872
Total Assets $454,299,414 $403,645,267 $339,115,390 $310,375,264 $175,252,707
Liabilities
Current Liabilities $34,070,085 $31,415,054 $28,517,664 $32,915,616 $40,133,269
Long-Term Debt $239,068,423 $261,200,000 $122,915,000 $115,000,000 $28,750,000
Total Liabilities $283,895,297 $294,282,628 $179,714,470 $167,613,654 $81,906,742
Stockholders' Equity $170,404,117 $109,362,639 $159,400,920 $142,761,610 $93,345,965
Number of Employees 173 203 194 191 176
Producing Wells
Swift Operated 769 836 650 842 767
Outside Operated 788 917 917 986 3,316
Total Producing Wells 1,557 1,753 1,567 1,828 4,083
Wells Drilled (Gross) 27 75 182 153 76
Proved Reserves
Natural Gas (Mcf) 329,959,749 352,400,835 314,305,669 225,758,201 143,567,520
Oil & Condensate (barrels) 20,806,263 13,957,925 7,858,918 5,484,309 5,421,981
Total Proved Reserves (Mcf equivalent) 454,797,327 436,148,385 361,459,177 258,664,055 176,099,406
Production (Mcf equivalent)(4) 42,874,303 39,030,030 25,393,744 19,437,114 11,186,573
Average Sales Price
Natural Gas (per Mcf) $2.40 $2.08 $2.68 $2.57 $1.77
Oil (per barrel) $16.75 $11.86 $17.59 $19.82 $15.66
</TABLE>
(1)Additional 1994 Data: Income Before Cumulative Effect of Change in Accounting
Principle-$3,725,671; Cumulative Effect of Change in Accounting
Principle-$(16,772,698); Per Share Amounts-Basic-Income Before Cumulative Effect
of Change in Accounting Principle-$0.51, Cumulative Effect of Change in
Accounting Principle-$(2.29); Per Share Amounts-Diluted-Income Before Cumulative
Effect of Change in Accounting Principle-$0.51, Cumulative Effect of Change in
Accounting Principle-$(2.29).
(2)As of January 1, 1994, we changed our revenue recognition policy for earned
interests. Accordingly, in 1994 to 1999, "Fees and Earned Interests" does not
include earned interests revenues.
(3)Amounts have been retroactively restated in all periods presented to give
recognition to: (a) an equivalent change in capital structure as a result of two
10% stock dividends, one in September 1994, the other in October 1997 (see Note
2 to the Consolidated Financial Statements); and (b) the adoption of Statement
of Financial Accounting Standards No. 128, "Earnings per Share" (see Note 2 to
the Consolidated Financial Statements).
(4)Natural gas production for 1992, 1993, 1994, 1995, 1996, 1997, 1998 and 1999
includes 1,148,862, 1,581,206, 1,358,375, 1,211,255, 1,156,361, 1,015,226,
866,232 and 728,235 Mcf, respectively, delivered under our volumetric production
payment agreement (see Note 1 to the Consolidated Financial Statements).
16
<PAGE>
<TABLE>
<CAPTION>
1994 (1) 1993 1992 1991 1990 1989
<S> <C> <C> <C> <C> <C>
$19,802,188 $15,535,671 $12,420,222 $8,361,771 $7,328,190 $3,984,835
$701,528 $4,071,970 $2,716,277 $2,231,729 $9,882,953 $8,802,816
$47,980 $201,584 $113,387 $192,694 $705,786 $260,286
$1,072,535 $604,599 $515,931 $541,502 $323,981 $232,261
$21,624,231 $20,413,824 $15,765,817 $11,327,696 $18,240,910 $13,280,198
$4,837,829 $6,628,608 $4,687,519 $3,748,741 $10,811,044 $8,716,673
($13,047,027) $4,896,253 $4,084,760 $2,512,815 $7,170,642 $5,709,098
$10,394,514 $7,238,340 $6,349,080 $5,911,588 $4,813,435 $2,751,381
7,308,673 7,246,884 6,748,548 5,899,629 5,806,436 5,129,654
($1.79) $0.68 $0.61 $0.43 $1.23 $1.11
($1.79) $0.64 $0.61 $0.43 $1.23 $1.11
6,685,137 6,001,075 5,968,579 4,955,134 4,848,315 4,764,862
$6.30 $9.08 $8.26 $7.80 $7.36 $5.84
$10.35 $11.57 $7.85 $9.09 $10.65 $11.15
$7.75 $7.14 $4.65 $4.34 $6.93 $5.78
$8.86 $7.85 $7.55 $4.95 $8.57 $9.50
$3,725,671 $4,322,478 $3,729,851 $2,950,245 $3,107,451 $2,185,276
$0.51 $0.60 $0.55 $0.50 $0.54 $0.43
$0.51 $0.57 $0.55 $0.50 $0.54 $0.43
$39,208,418 $65,307,120 $30,830,173 $47,859,278 $72,537,521 $54,818,404
$88,415,612 $89,656,577 $64,301,509 $47,655,917 $41,952,212 $27,935,170
$135,672,743 $160,892,917 $100,243,469 $101,421,573 $118,227,480 $85,007,293
$52,345,859 $55,565,437 $27,876,687 $50,851,447 $71,514,938 $49,354,128
$28,750,000 $28,750,000 $0 $0 $0 $0
$93,545,612 $106,427,203 $50,962,183 $62,761,217 $82,559,406 $57,198,476
$42,127,131 $54,465,714 $49,281,286 $38,660,356 $35,668,074 $27,808,817
209 188 178 171 164 131
750 795 688 674 691 579
3,422 3,407 1,978 2,331 2,228 1,537
4,172 4,202 2,666 3,005 2,919 2,116
44 34 40 27 23 21
76,263,964 64,462,805 41,638,100 36,685,881 30,731,741 14,945,348
4,553,237 4,271,069 2,901,621 1,950,209 1,690,520 1,422,815
103,583,566 90,089,219 59,047,824 48,387,138 40,874,862 23,482,236
9,600,867 7,368,757 5,678,772 3,980,460 3,303,750 1,900,302
$1.93 $1.96 $1.90 $1.58 $1.72 $1.73
$14.35 $15.10 $17.19 $18.26 $22.70 $17.93
</TABLE>
17
<PAGE>
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations
The following discussion should be read in conjunction with our
Consolidated Financial Statements and Notes thereto.
General
Over the last several years, we have emphasized adding reserves through
drilling activity. We also add reserves through strategic purchases of producing
properties when oil and gas prices are at lower levels and other market
conditions are appropriate, as we did in the third quarter of 1998 with the
purchase of the Brookeland and Masters Creek areas. During the past three years,
we have used this flexible strategy of employing both drilling and acquisitions
to add more reserves than we depleted through production. Virtually all of our
revenues are from oil and gas sales attributable to our production.
Proved Oil and Gas Reserves. At year-end 1999, our total proved reserves
were 454.8 Bcfe with a PV-10 Value of $564.1 million. In 1999, our proved
natural gas reserves decreased 22.4 Bcf, or 6%, while our proved oil reserves
increased 6.8 MMBbl, or 49%, for a total equivalent increase of 18.6 Bcfe, or
4%. From 1997 to 1998, we increased our proved natural gas reserves by 38.1 Bcf,
or 12%, and our proved oil reserves by 6.1 MMBbl, or 78%, for a total equivalent
increase of 74.7 Bcfe, or 21%. We added reserves from 1998 to 1999 through our
drilling activity and through purchases of minerals in place, primarily in the
Masters Creek area. Through drilling we added 64.9 Bcfe of proved reserves in
1999, 73.9 Bcfe in 1998, and 120.2 Bcfe in 1997. Through acquisitions we added
20.1 Bcfe of proved reserves in 1999, 97.6 Bcfe in 1998, and 33.8 Bcfe in 1997.
A substantial portion of these reserves are proved undeveloped. At year-end
1999, 51% of our total proved reserves were proved undeveloped, compared with
45% at year-end 1998, and 40% at year-end 1997.
While our total proved reserves quantities at year-end 1999 increased by 4%
over those at year-end 1998, the PV-10 Value of those reserves increased 66%,
almost entirely due to increased prices between year-end 1998 and year-end 1999.
Between those two dates, there was a 16% increase in natural gas prices and a
111% increase in oil prices. Gas prices were $2.58 per Mcf at year-end 1999
compared to $2.23 per Mcf at year-end 1998. Oil prices were $23.69 per Bbl at
year-end 1999 compared to $11.23 a year earlier.
Under SEC guidelines, estimates of proved reserves are made using year-end
oil and gas sales prices and are held constant throughout the life of the
properties. The prices used to calculate the PV-10 Value may not be indicative
of future sales prices ultimately received.
Liquidity and Capital Resources
During 1999, we primarily relied upon internally generated cash flows of
$73.6 million to fund capital expenditures of $78.1 million. Capital
expenditures were also partially funded with the remaining net proceeds, after
repayment of our bank borrowings, from our third quarter issuance of senior
subordinated notes and common stock. During 1998, we used $138.3 million
borrowed under our credit facilities, along with internally generated cash
flows, to fund capital expenditures and property acquisitions totaling $183.8
million.
Net Cash Provided by Operating Activities. In 1999, net cash provided by
our operating activities increased by 36% to $73.6 million, as compared to $54.2
million in 1998 and $55.3 million in 1997. The 1999 increase of $19.4 million
was primarily due to $28.8 million of additional oil and gas sales, partially
offset by $12.2 million of increases in oil and gas production costs and
interest expense. The slight decrease of $1.1 million in net cash provided in
1998 was primarily due to the offset of our 54% increase in production volumes
by:
o the 25% decrease in average commodity prices received;
o the associated 50% increase in oil and gas production costs; and
o a decrease in interest income and an increase in interest expense due
to our use in 1997 of the net proceeds of our 1996 sale of convertible
notes, resulting in increased bank borrowings during 1998.
18
<PAGE>
Existing Credit Facilities. At December 31, 1999, we had no outstanding
borrowings under our credit facility. Our credit facility consists of a $250.0
million revolving line of credit with a $100.0 million borrowing base at
December 31, 1999. The borrowing base is redetermined at least every six months.
Our $250.0 million revolving credit facility includes, among other restrictions,
requirements as to maintenance of certain minimum financial ratios (principally
pertaining to working capital, debt, and equity ratios) and limitations on
incurring other debt. We are currently in compliance with the provisions of this
agreement. The credit facility extends until August 2002. At December 31, 1998,
we had outstanding borrowings of $146.2 million under that facility.
Working Capital. Our working capital has increased from $3.8 million at
December 31, 1998, to $16.5 million at December 31, 1999, primarily due to the
remaining proceeds from our third quarter 1999 public offerings of senior notes
and common stock.
Common Stock Repurchase Program. In March 1997, we commenced a common stock
repurchase program which terminated pursuant to its terms as of June 30, 1999.
We spent approximately $13.3 million to acquire 927,774 shares at an average
cost of $14.34 per share. In March 1999, we used 68,318 shares of common stock
held as treasury stock to fund our employer contribution in the 401(k) program
for our employees.
Capital Expenditures. In 1999, we spent approximately $78.1 million to fund
capital expenditures, including:
o $34.0 million, or 44%, spent on developmental drilling;
o $20.6 million, or 26%, spent on producing properties acquisitions,
almost all of which was for the purchase of additional working
interests in the Masters Creek area;
o $10.4 million, or 13%, spent on prospect costs, principally leasehold,
seismic, and geological costs of unproven prospects for our account;
o $10.0 million, or 13%, spent on exploratory drilling, $5.9 million of
which was in New Zealand;
o $1.6 million, or 2%, spent on two gas processing plants in the
Brookeland and Masters Creek areas;
o $1.3 million, or 2%, on fixed assets; and
o $0.2 million, or less than 1%, spent on field compression facilities.
In 1999, we participated in drilling 22 development wells and five
exploratory wells, of which 19 development wells and one exploratory well were
successes, while another exploratory well is still under evaluation. Two of the
exploratory wells were drilled in New Zealand. The first well in which we had a
10% working interest was unsuccessful and was drilled by another operator. The
second well, which Swift drilled with a 90% working interest, has been completed
and a ten-day production test has been performed. We believe that this discovery
will result in proved reserves upon further evaluation and analysis. Our $57.7
million of unproved property costs not being amortized is indicative of our
inventory of developmental and exploratory acreage to sustain drilling activity
for future growth.
Capital expenditures for 2000 are estimated to be approximately $114.8
million. Approximately $59.6 million of the 2000 budget is allocated to
development and exploration drilling, primarily in our four core areas: AWP
Olmos, Brookeland, Giddings, and Masters Creek. We anticipate drilling 36
development wells and 11 exploratory wells in 2000. Approximately $35.6 million
is targeted towards the acquisition of producing properties. The remaining $19.6
million will be used primarily for leasehold, seismic, and geological costs,
including approximately $2.7 million of such costs in New Zealand.
The Company believes that 2000's anticipated internally generated cash
flows, together with bank borrowings under our credit facility, will be
sufficient to finance the costs associated with our currently budgeted 2000
capital expenditures.
Our capital expenditures were approximately $183.8 million for 1998 and
$132.0 million for 1997. During 1997, we relied upon net proceeds from the sale
in 1996 of $115.0 million of convertible notes due 2006 and on internally
generated cash flows, along with $7.9 million of bank borrowings, to fund
capital expenditures. During 1998, we used $138.3 million of bank borrowings,
along with internal cash flows of $54.2 million, to fund capital expenditures.
Capital expenditures in 1998 included:
o $59.5 million, or 32%, spent on producing properties acquisitions,
almost all of which was used to acquire the Brookeland and Masters
Creek areas;
o $54.8 million, or 30%, spent on developmental drilling, primarily in
the AWP Olmos and Giddings areas;
19
<PAGE>
o $34.7 million, or 19%, spent on domestic prospect costs, principally
leasehold, seismic, and geological costs of unproven prospects,
including $15.2 million for leaseholds in the Brookeland and Masters
Creek areas acquisition;
o $15.0 million, or 8%, spent for the purchase of a 20% interest in two
gas processing plants as part of the Brookeland and Masters Creek areas
acquisition;
o $12.6 million, or 7%, spent on exploratory drilling;
o $3.9 million, or 2%, invested in foreign business opportunities,
consisting of $2.9 million in New Zealand, $0.4 million in Venezuela,
and $0.6 million in Russia, as described in Note 8 to the Consolidated
Financial Statements;
o $2.2 million, or 1%, spent on field compression facilities; and
o $1.0 million, or 1%, spent on fixed assets.
In 1998, we participated in drilling 61 development wells and 14
exploratory wells, of which 53 development wells and five exploratory wells were
successes.
Results of Operations
Revenues. Our revenues in 1999 increased by 34% over revenues in 1998 and
by 10% in 1998 over 1997 revenues, principally due to increases in oil and gas
sales.
Oil and gas sales revenues in 1999 increased by 36%, or $28.8 million, over
those revenues for 1998. In 1998, oil and gas sales revenues increased by 16%,
or $11.1 million, over those revenues in 1997. Our net sales volumes in 1999,
including the volumetric production payment associated with each year's
production, increased by 10%, or 3.8 Bcfe, over net sales volumes in 1998. In
1998, net sales volumes increased by 54%, or 13.6 Bcfe, over net sales volumes
in 1997. Average prices for oil decreased from $17.59 per Bbl in 1997 to $11.86
per Bbl in 1998, and then increased to $16.75 per Bbl in 1999. Average gas
prices decreased from $2.68 per Mcf in 1997 to $2.08 per Mcf in 1998, and then
increased to $2.40 per Mcf in 1999.
In 1999, our $28.8 million increase in oil and gas sales resulted from:
o Volume variances that added $7.5 million of sales, with $9.0
million of increases coming from the 0.8 MMBbl increase in oil
sales volumes, partially offset by a decline of $1.5 million from
the 0.7 Bcf decrease in gas sales volumes; and
o Price variances that had a $21.3 million favorable impact on
sales, $12.6 million of which was attributable to the 41% increase
in average oil prices received, and $8.7 million of which was
attributable to the 15% increase in average gas prices received.
In 1998, our $11.1 million increase in oil and gas sales resulted from:
o Volume increases that added $38.3 million of sales, with $19.9
million of the increase coming from the 1.1 MMBbl increase in oil
sales volumes and $18.4 million of the increase coming from the
6.9 Bcf increase in gas sales volumes; and
o Offsetting price variances that had a $27.2 million unfavorable
impact on sales, $16.9 million of which was attributable to the
22% decrease in average gas prices received, and $10.3 million of
which was attributable to the 33% decrease in average oil prices
received.
The following table provides additional information regarding the changes
in the sources of our oil and gas sales and volumes from our four core areas in
1999 and 1998:
<TABLE>
<CAPTION>
Revenues Net Sales Volume
(In millions) (Bcfe)
------------------------ --------------------------
Area 1999 1998 1999 1998
----------------------- ------- ------- --------- ----------
<S> <C> <C> <C> <C>
AWP Olmos $31.5 $33.5 13.1 15.5
Brookeland $14.6 $ 6.8 5.6 3.5
Giddings $ 8.7 $14.6 3.8 7.0
Masters Creek $48.5 $17.5 17.6 8.2
</TABLE>
Even though we scaled back our 1999 capital expenditures budget from
budgeted amounts in prior years, oil and gas sales volumes increased in 1999
when compared to 1998, primarily due to the full year of production from the
Brookeland and Masters Creek areas, as the 1998 amounts from these two areas
included production only from the second half of 1998. However, due to the
decrease in the 1999 capital expenditures budget and the resulting curtailment
of drilling, 27 gross wells in 1999 as compared to 75 and 182 gross wells
20
<PAGE>
in 1998 and 1997, respectively, the natural production declines in the Giddings
and the AWP Olmos areas were not offset by newly developed production. This
scaled-back 1999 budget was in response to the low oil and gas prices
experienced in 1998 and the first half of 1999. However, due to the improvement
in oil and gas prices in the second half of 1999, our 2000 capital expenditures
budget has increased to a planned $114.8 million, which should translate into
increased sequential quarterly production volumes in 2000 when compared to the
fourth quarter of 1999.
The following table provides additional information regarding our oil and
gas sales:
<TABLE>
<CAPTION>
Net Sales Volume Average Sales Price
--------------------------------- ----------------------
Oil Gas Combined Oil Gas
(MBbl) (Bcf) (Bcfe) (Bbl) (Mcf)
--------- ------- ----------- --------- --------
<S> <C> <C> <C> <C> <C>
1997:
First Qtr. 166 4.9 5.9 $20.13 $3.06
Second Qtr. 160 5.1 6.1 $17.08 $2.20
Third Qtr. 164 5.6 6.5 $16.50 $2.47
Fourth Qtr. 182 5.8 6.9 $16.69 $2.98
--------- ------- -----------
1997 672 21.4 25.4 $17.59 $2.68
1998:
First Qtr. 195 5.8 7.0 $12.61 $2.28
Second Qtr. 190 6.2 7.3 $11.20 $2.20
Third Qtr. 696 8.1 12.2 $11.94 $1.93
Fourth Qtr. 720 8.1 12.5 $11.74 $2.00
--------- ------- -----------
1998 1,801 28.2 39.0 $11.86 $2.08
1999:
First Qtr. 728 7.2 11.6 $10.87 $1.82
Second Qtr. 644 6.7 10.6 $15.25 $2.05
Third Qtr. 612 6.9 10.5 $18.46 $2.84
Fourth Qtr. 581 6.7 10.2 $23.99 $2.91
--------- ------- -----------
1999 2,565 27.5 42.9 $16.75 $2.40
</TABLE>
Revenues from our oil and gas sales comprised 98% of total revenues for
1999, 97% of total revenues for 1998, and 92% of total revenues for 1997. Our
acquisition of interests in the second half of 1998 in the Brookeland and
Masters Creek areas, which have a higher percentage of production from oil, has
decreased the predominance of gas in our production volume mix to 64% in 1999
from 72% in 1998 and 84% in 1997.
Costs and Expenses. Our general and administrative expenses in 1999
increased $0.6 million, or 17%, from the level of such expenses in 1998, while
1998 general and administrative expenses increased $0.3 million, or 9%, over
1997 levels. The variances in these costs over the three-year period reflect the
increase in our corporate activities, while our partnership management
activities are decreasing. However, our general and administrative expenses per
Mcfe produced have decreased from $0.14 per Mcfe in 1997 to $0.10 per Mcfe in
both 1998 and 1999. The portion of supervision fees netted from general and
administrative expenses were $3.2 million for 1999, $2.7 million for 1998, and
$2.6 million for 1997.
Depreciation, depletion, and amortization of our assets, or DD&A, increased
$3.0 million, or 8%, in 1999 from 1998, while 1998 DD&A increased $15.1 million,
or 62%, over 1997 levels. This was primarily due to additions in our reserves
and associated costs and to the related 10% increase in production in 1999 over
1998 and the 54% increase in production in 1998 over 1997. Our DD&A rate per
Mcfe of production was $0.99 in 1999, $1.01 in 1998, and $0.95 in 1997,
reflecting variations in the per unit cost of reserves additions.
Our production costs in 1999 increased $6.5 million, or 50%, over such
expenses in 1998, while those expenses in 1998 increased $4.4 million, or 50%,
over 1997 costs. The increases relate to the 10% increase in production volumes
in 1999 and the 54% increase in 1998. The higher percentage increase in costs,
in relation to the increase in production in 1999, was due to planned increases
in remedial well work, increased severance taxes, and increased ad valorem
taxes. While the planned remedial well work is expected to increase production
on those wells in the future, these costs were expensed as incurred. The
increase in severance taxes was partially due to the increase in oil and gas
prices received in 1999 when compared to 1998. Also, severance taxes increased
due to certain wells in the Masters Creek area losing the gas severance tax
exemption they received from Louisiana once they had been in production for more
than two years or once payout of the well occurs, whichever event occurs first.
The ad valorem tax increase resulted from wells we
21
<PAGE>
drilled in the first half of 1998 and wells drilled in 1998 that we acquired in
the Brookeland and Masters Creek areas acquisition being subject to ad valorem
taxes for the first time at the beginning of 1999. Our production costs per Mcfe
produced were $0.46 in 1999, $0.34 in 1998, and $0.35 in 1997. The portion of
supervision fees netted from production costs were $3.2 million for 1999, $2.7
million for 1998, and $2.6 million for 1997.
Interest expense on our senior notes due 2009, issued in July 1999,
including amortization of debt issuance costs, totaled $5.3 million in 1999.
Interest expense on our convertible notes due 2006, including amortization of
debt issuance costs, totaled $7.5 million in each of the years 1999, 1998, and
1997. Interest expense on the credit facility, including commitment fees and
amortization of debt issuance costs, totaled $6.1 million in 1999, $5.6 million
in 1998, and $0.1 million in 1997. In total, 1999's interest expense was $18.9
million, of which $4.5 million was capitalized. The 1998 total interest expense
was $13.1 million, of which $4.4 million was capitalized. The 1997 total
interest expense was $7.6 million, of which $2.6 million was capitalized. We
capitalize that portion of interest related to our exploration, partnership, and
foreign business development activities. The increase in interest expense in
1999 was attributable to the increase in amounts outstanding to fund our 1998
capital expenditures, which included the Brookeland and Masters Creek areas
acquisition in the third quarter of 1998, and to the higher interest rate on our
new senior notes when compared to our credit facility. The increase in interest
expense in 1998 was attributable to the increase in amounts outstanding under
our credit facilities.
In the third quarter of 1998, we took a non-cash write-down of oil and gas
properties, as discussed in Note 1 to the Consolidated Financial Statements.
Lower prices for both oil and natural gas at September 30, 1998, necessitated a
pre-tax domestic full-cost ceiling write-down of $77.2 million, or $50.9 million
after tax. Also, in the third quarter of 1998, we re-evaluated the capitalized
unproved properties costs in Russia of $10.8 million and in Venezuela of $2.8
million, which resulted in a separate non-cash pre-tax charge to earnings of
$13.6 million, or $9.0 million after tax. The combination of the non-cash
full-cost domestic ceiling write-down and the non-cash foreign impairment
charges resulted in a combined non-cash charge to earnings of $90.8 million
pre-tax, or $59.9 million after tax.
At December 31, 1999, our full-cost ceiling cushion was approximately
$138.0 million, compared to our full-cost ceiling cushion at December 31, 1998,
of approximately $25.0 million.
Net Income. Our net income in 1999 of $19.3 million was 65% higher and
Basic earnings per share ("Basic EPS") of $1.07 were 51% higher than 1998 income
before the non-cash write-down of oil and gas properties of $11.7 million and
Basic EPS of $0.71. These increases primarily reflected the effect of the 10%
increase in production volumes and the 41% increase in oil prices and 15%
increase in gas prices. Oil and gas prices have risen rapidly since the second
quarter of 1999, which is reflected by third- and fourth-quarter net income
combining to represent 77% of net income for the year. The lower percentage
increase in Basic EPS reflects a 10% increase in weighted average shares
outstanding in 1999, primarily due to our third-quarter public sale of 4.6
million shares of common stock.
Before the non-cash write-down of oil and gas properties in 1998, our net
income of $11.7 million was 48% lower and Basic EPS of $0.71 was 47% lower than
net income of $22.3 million and Basic EPS of $1.35 in 1997. These decreases
primarily reflected the effect of a 33% decrease in oil prices and 22% decrease
in gas prices, while costs and expenses increased in general proportion to the
54% increase in production.
Year 2000. The Year 2000 issue arose because many computer programs used
only the last two digits to refer to a year. Therefore, those programs could not
distinguish between the years 1900 and 2000, potentially causing systems
failures, miscalculations, and the disruption of normal business activities. We
formed a task force to prepare our business systems for the Year 2000, which
included testing our in-house business systems and field operations systems,
reviewing Year 2000 compliance certifications and reports issued by third
parties, upgrading or replacing noncompliance systems, and preparing a
contingency plan for unforeseen difficulties. We implemented this plan before
2000 began.
Our in-house business systems are almost entirely comprised of
off-the-shelf software. These systems were either tested, certified as compliant
by the licensor of the software, or categorized as not date specific. We
upgraded or replaced the software that experienced difficulties addressing the
Year 2000.
In our core business function, oil and gas exploration, the systems and
equipment are primarily non-information technology systems that are not date
specific. Our most reasonably likely worst case scenario would have been a
prolonged disruption of external power sources upon which our core field
operations equipment relies, resulting in a substantial decrease in our oil and
gas production activities. We did not maintain on-site secondary power supplies,
such as generators, as it was not economically feasible. A prolonged
interruption could have materially affected our operations.
22
<PAGE>
In our business, we also depend on third parties such as pipeline operators
who transport natural gas, customers, and suppliers, any one of whom could have
been prone to Year 2000 problems that we could not assess or detect. We have
experienced no problems with these third parties.
The costs incurred to address the Year 2000 issue did not have a material
effect on our results of operations or our liquidity and financial condition. We
estimate our total cost to address the Year 2000 issue to have been less than
$150,000, most of which was spent during the testing phase on equipment and
software upgrades. We used both internal and external resources to complete our
Year 2000 program and to perform tasks necessary to address the Year 2000
problem.
As of the filing of this report, we are not aware of any Year 2000 problems
experienced either by us or by parties with which we do business, and we do not
expect to experience such problems in the future. We will continue to assess any
potential problems that might occur.
Forward Looking Statements
The statements contained in this report that are not historical facts are
forward-looking statements as that term is defined in Section 21E of the
Securities and Exchange Act of 1934, as amended, and therefore involve a number
of risks and uncertainties. Such forward-looking statements concern, among other
things, capital expenditures, drilling activity, development activities, cost
savings, production efforts and volumes, hydrocarbon reserves and potential
reserves, hydrocarbon prices, liquidity, regulatory matters, and competition.
Such forward-looking statements generally are accompanied by words such as
"plan," "estimate," "expect," "budgeted," "predict," "anticipate," "projected,"
"should," "believe," or other words that convey the uncertainty of future events
or outcomes. Such forward-looking information is based upon management's current
plans, expectations, estimates, and assumptions and is subject to a number of
risks and uncertainties. As a consequence, actual results may differ materially
from expectations, estimates, or assumptions expressed in or implied by any
forward-looking statements made by or on behalf of us, including those regarding
our financial results, levels of oil and gas production or revenues, capital
expenditures, and capital resources. Among the factors that could cause actual
results to differ materially are: fluctuations of the prices received or demand
for oil and natural gas internationally or in the United States; the uncertainty
of drilling results and reserve estimates; operating hazards; requirements for
capital; general economic conditions; competition and government regulations; as
well as the risks and uncertainties discussed herein, including, without
limitation, the portions referenced above and the uncertainties set forth from
time to time in our other public reports, filings, and public statements. Also,
because of the volatility in oil and gas prices and other factors, interim
results are not necessarily indicative of those for a full year.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. Our major market risk exposure is the commodity pricing
applicable to our oil and natural gas production. Realized commodity prices
received for such production are primarily driven by the prevailing worldwide
price for crude oil and spot prices applicable to natural gas. The effects of
such pricing volatility are discussed above, and such volatility is expected to
continue.
Our price risk program permits the utilization of agreements and financial
instruments (such as futures, forward and options contracts, and swaps) to
mitigate price risk associated with fluctuations in oil and natural gas prices
as they relate to our and the managed limited partnerships' oil and gas
production. Below is a description of the financial instruments we have utilized
to hedge our exposure to price risk.
o Price Floors - Costs and any benefits derived from price floors are
accordingly recorded as a reduction or increase, as applicable, in oil
and gas sales revenue. The costs to purchase put options are amortized
over the option period. Below is a summary of the utilization of price
floors for the years ending December 31, 1999, 1998, and 1997.
o The costs related to 1999 hedging activities totaled
approximately $909,000, with benefits of approximately
$348,000 being received, resulting in a net cash outlay of
approximately $561,000, or $0.013 per Mcfe. The costs
related to the open contracts as of December 31, 1999,
totaled approximately $98,000 and had a fair market value of
$112,500.
o The costs related to 1998 hedging activities totaled
approximately $377,000, with benefits of approximately
$101,000 being received, resulting in a net cash outlay of
approximately $276,000, or $0.007 per Mcfe.
o The costs related to 1997 hedging activities totaled
approximately $1,052,000, with benefits of approximately
$439,000 being received, resulting in a net cash outlay of
approximately $613,000, or $0.014 per Mcfe.
23
<PAGE>
o Participating Collars - During the fourth quarter of 1999, we entered
into participating collars to hedge oil production through June 2000.
Below is a summary of the collar arrangements for 2000. The
participating collars are designated as hedges, and realized gains or
losses are recognized in oil and gas revenues when the associated
production occurs.
o We hedged 100,000 Bbls of oil per month for the months
January through June 2000 with a floor price of $19.00 per
Bbl and a ceiling price of $23.60 per Bbl, whereby we
participate in 75% of any amount above the $23.60 ceiling
price. At December 31, 1999, the participating collars had
an approximate value, as quoted by the dealers, of $95,000.
The January 2000 collar has expired at a loss of $62,550.
The gains or losses of the remaining months are determined
from an average of the closing price of the contracts.
Interest Rate Risk. All of our long-term debt obligations at December 31,
1999, have fixed interest rates, and we have no current plans to redeem
long-term debt obligations before their stated maturity. Consequently we are not
exposed to cash flow or fair value risk from market interest rate changes on our
long-term debt portfolio. In 2000, we anticipate borrowing under our credit
facility and accordingly will be exposed to fluctuations in interest rates.
Financial Instruments & Debt Maturities. Our financial instruments consist
of cash and cash equivalents, accounts receivable, accounts payable, bank
borrowings, convertible notes, and senior notes. The carrying amounts of cash
and cash equivalents, accounts receivable, and accounts payable approximate fair
value due to the highly liquid nature of these short-term instruments. The fair
values of the bank borrowings approximate the carrying amounts as of December
31, 1998, and were determined based upon interest rates currently available to
us for borrowings with similar terms. Based on quoted markets prices as of the
respective dates, the fair values of our convertible notes were $89.7 million
and $81.4 million at December 31, 1999 and 1998, respectively, and the fair
value of our senior notes was $117.9 million at December 31, 1999. Our credit
facility with the banks expires August 18, 2002. Our $115.0 million convertible
notes mature on November 15, 2006. Our $125.0 million senior notes mature on
August 1, 2009.
24
<PAGE>
Item 8. Financial Statements and Supplementary Data
Report of Independent Public Accountants.................................26
Consolidated Balance Sheets..............................................27
Consolidated Statements of Income........................................28
Consolidated Statements of Stockholders' Equity..........................29
Consolidated Statements of Cash Flows....................................30
Notes to Consolidated Financial Statements...............................31
1. Summary of Significant Accounting Policies.........................31
2. Earnings Per Share.................................................34
3. Provision for Income Taxes.........................................35
4. Long-Term Debt ....................................................36
5. Commitments and Contingencies......................................37
6. Stockholders' Equity...............................................37
7. Related-Party Transactions.........................................40
8. Foreign Activities.................................................40
9. Acquisition of Properties..........................................41
Supplemental Information (Unaudited).....................................42
25
<PAGE>
Report of Independent Public Accountants
To the Stockholders and Board of Directors of Swift Energy Company:
We have audited the accompanying consolidated balance sheets of Swift Energy
Company (a Texas corporation) and subsidiaries as of December 31, 1999 and 1998,
and the related consolidated statements of income, stockholders' equity, and
cash flows for each of the three years in the period ended December 31, 1999.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Swift Energy Company and
subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
February 9, 2000
26
<PAGE>
Consolidated Balance Sheets
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
December 31,
1999 1998
---------------- ----------------
ASSETS
Current Assets:
<S> <C> <C>
Cash and cash equivalents $ 22,685,648 $ 1,630,649
Accounts receivable-
Oil and gas sales 15,634,019 12,764,568
Associated limited partnerships and joint ventures 5,359,596 10,058,239
Joint interest owners 5,550,048 9,767,940
Other current assets 1,376,177 1,025,035
---------------- ----------------
Total Current Assets 50,605,488 35,246,431
---------------- ----------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties being amortized 573,360,199 497,296,068
Unproved properties not being amortized 57,662,739 56,041,886
---------------- ----------------
631,022,938 553,337,954
Furniture, fixtures, and other equipment 7,778,571 7,098,305
---------------- ----------------
638,801,509 560,436,259
Less - Accumulated depreciation, depletion, and amortization (242,966,019) (200,713,621)
----------------- -----------------
395,835,490 359,722,638
---------------- ----------------
Other Assets:
Receivables from associated limited partnerships, net of current
portion 628,228 3,170,067
Limited partnership formation and marketing costs --- 917,189
Deferred income taxes --- 254,984
Deferred charges 7,230,208 4,333,958
---------------- ----------------
7,858,436 8,676,198
---------------- ----------------
$ 454,299,414 $ 403,645,267
================ ================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 25,674,143 $ 18,639,649
Payable to associated limited partnerships 609,967 380,692
Undistributed oil and gas revenues 7,785,975 12,394,713
---------------- ----------------
Total Current Liabilities 34,070,085 31,415,054
---------------- ----------------
Long-Term Debt 239,068,423 261,200,000
Deferred Revenues 576,658 1,667,574
Deferred Income Taxes 10,180,131 ---
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized,
none outstanding --- ---
Common stock, $.01 par value, 35,000,000 shares authorized,
21,683,185 and 16,972,517 shares issued, and 20,823,729
and 16,291,242 shares outstanding, respectively 216,832 169,725
Additional paid-in capital 191,092,851 148,901,270
Treasury stock held, at cost, 859,456 and 681,275 shares,
respectively (12,325,668) (11,841,884)
Retained earnings (deficit) (8,579,898) (27,866,472)
----------------- ----------------
170,404,117 109,362,639
---------------- ----------------
$ 454,299,414 $ 403,645,267
================ ================
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
27
<PAGE>
Consolidated Statements of Income
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31,
1999 1998 1997
---------------------------------------------------------
<S> <C> <C> <C>
Revenues:
Oil and gas sales $ 108,898,696 $ 80,067,837 $ 69,015,189
Fees from limited partnerships and joint
ventures 229,749 333,940 745,856
Interest income 833,204 107,374 2,395,406
Other, net 709,358 1,960,070 2,555,729
---------------- ----------------- ---------------
110,671,007 82,469,221 74,712,180
---------------- ----------------- ---------------
Costs and Expenses:
General and administrative, net of
reimbursement 4,497,400 3,853,812 3,523,604
Depreciation, depletion, and amortization 42,348,901 39,343,187 24,247,142
Oil and gas production 19,645,740 13,138,980 8,778,876
Interest expense, net 14,442,815 8,752,195 5,032,952
Write-down of oil and gas properties --- 90,772,628 ---
---------------- ----------------- ---------------
80,934,856 155,860,802 41,582,574
---------------- ----------------- ---------------
Income (Loss) Before Income Taxes 29,736,151 (73,391,581) 33,129,606
Provision (Benefit) for Income Taxes 10,449,577 (25,166,377) 10,819,417
----------------- ------------------ ---------------
Net Income (Loss) $ 19,286,574 $ (48,225,204) $ 22,310,189
================ ================= ===============
Per Share Amounts-
Basic $ 1.07 $ (2.93) $ 1.35
================ ================= ===============
Diluted $ 1.07 $ (2.93) $ 1.26
================ ================= ===============
Weighted Average Shares Outstanding 18,050,106 16,436,972 16,492,856
================ ================= ===============
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
28
<PAGE>
Consolidated Statements of Stockholders' Equity
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
Unearned
Additional ESOP Retained
Common Paid-in Treasury Compen- Earnings
Stock (1) Capital Stock sation (Deficit) Total
----------- --------------- ------------- ------------- -------------- --------------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1996 $ 151,764 $ 102,018,861 $ - $ (521,354) $ 41,112,339 $ 142,761,610
Stock issued for benefit
plans (12,227 shares) 122 371,359 - - - 371,481
Stock options exercised
(137,155 shares) 1,372 1,613,071 - - - 1,614,443
Employee stock purchase plan
(26,551 shares) 266 403,145 - - - 403,411
10% stock dividend
(1,494,606 shares) 14,946 43,048,389 - - (43,063,335) -
Allocation of ESOP shares - 88,152 - 371,299 - 459,451
Purchase of 387,800 shares
as treasury stock - - (8,519,665) - - (8,519,665)
Net income - - - - 22,310,189 22,310,189
----------- --------------- ------------- ------------- -------------- --------------
Balance, December 31, 1997 $ 168,470 $ 147,542,977 $ (8,519,665) $ (150,055) $ 20,359,193 $ 159,400,920
Stock issued for benefit
plans (20,032 shares) 200 367,058 - - - 367,258
Stock options exercised
(84,757 shares) 847 735,746 - - - 736,593
Employee stock purchase
plan (20,756 shares) 208 317,340 - - - 317,548
Stock dividend adjustment
(16 shares) - 461 - - (461) -
Allocation of ESOP shares - (62,312) - 150,055 - 87,743
Purchase of 293,475 shares
as treasury stock - - (3,322,219) - - (3,322,219)
Net loss - - - - (48,225,204) (48,225,204)
----------- --------------- ------------- ------------- -------------- --------------
Balance, December 31, 1998 $ 169,725 $ 148,901,270 $ (11,841,884) $ - $ (27,866,472) $ 109,362,639
Stock issued for benefit
plans (90,738 shares) 224 (366,408) 978,956 - - 612,772
Stock options exercised
(65,477 shares) 655 461,102 - - - 461,757
Employee stock purchase
plan (22,771 shares) 228 181,577 - - - 181,805
Public stock offering
(4,600,000 shares) 46,000 41,915,310 - - - 41,961,310
Purchase of 246,500 shares
as treasury stock - - (1,462,740) - - (1,462,740)
Net income - - - - 19,286,574 19,286,574
----------- -------------- ------------- ------------- -------------- --------------
Balance, December 31, 1999 $ 216,832 $ 191,092,851 $ (12,325,668) $ - (8,579,898) $ 170,404,117
=========== ============== ============= ============= ============== ==============
(1)$.01 par value.
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
29
<PAGE>
Consolidated Statements of Cash Flows
Swift Energy Company and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------
1999 1998 1997
----------------- ----------------- ---------------
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net income (loss) $ 19,286,574 $ (48,225,204) $ 22,310,189
Adjustments to reconcile net income to net cash provided
by operating activities-
Depreciation, depletion, and amortization 42,348,901 39,343,187 24,247,142
Write-down of oil and gas properties --- 90,772,628 --
Deferred income taxes 10,435,115 (25,609,134) 10,060,193
Deferred revenue amortization related to production
payment (1,056,284) (1,248,800) (1,449,808)
Other 628,614 478,470 786,917
Change in assets and liabilities-
Increase in accounts receivable (2,889,530) (2,129,360) (204,475)
Increase (decrease) in accounts payable
and accrued liabilities, excluding income
taxes payable 4,850,036 689,347 (564,323)
Increase in income taxes payable --- 177,883 70,130
----------------- ----------------- ---------------
Net Cash Provided by Operating Activities 73,603,426 54,249,017 55,255,965
----------------- ----------------- ---------------
Cash Flows from Investing Activities:
Additions to property and equipment (78,112,550) (183,815,927) (131,967,444)
Proceeds from the sale of property and equipment 4,531,935 1,533,112 3,369,982
Net cash received (distributed) as operator of oil and gas
properties 5,995,842 (5,933,171) (1,829,008)
Net cash distributed as operator of partnerships and
joint ventures (433,114) (1,559,537) (2,102,553)
Limited partnership formation and marketing costs --- (619,970) --
Other (131,135) (113,716) (259,255)
----------------- ----------------- ---------------
Net Cash Used in Investing Activities (68,149,022) (190,509,209) (132,788,278)
----------------- ----------------- ---------------
Cash Flows from Financing Activities:
Proceeds from senior subordinated notes 124,045,000 -- --
Net proceeds from (payments of) bank borrowings (146,200,000) 138,285,000 7,915,000
Net proceeds from issuances of common stock 42,719,776 1,421,399 2,389,336
Purchase of treasury stock (1,462,740) (3,322,219) (8,519,665)
Payments of debt issuance costs (3,501,441) (540,671) --
----------------- ----------------- ---------------
Net Cash Provided by Financing Activities 15,600,595 135,843,509 1,784,671
----------------- ----------------- ---------------
Net Increase (Decrease) in Cash and Cash Equivalents $ 21,054,999 $ (416,683) $ (75,747,642)
Cash and Cash Equivalents at Beginning of Year 1,630,649 2,047,332 77,794,974
----------------- ----------------- ---------------
Cash and Cash Equivalents at End of Year $ 22,685,648 $ 1,630,649 $ 2,047,332
================= ================= ===============
Supplemental Disclosures of Cash Flows Information:
Cash paid during year for interest, net of amounts capitalized $ 8,618,020 $ 8,343,445 $ 4,638,308
Cash paid during year for income taxes $ --- $ 36,286 $ 381,514
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
30
<PAGE>
Notes to Consolidated Financial Statements
Swift Energy Company and Subsidiaries
1. Summary of Significant Accounting Policies
Principles of Consolidation. The accompanying consolidated financial
statements include the accounts of Swift Energy Company (Swift) and our wholly
owned subsidiaries, which are engaged in the exploration, development,
acquisition, and operation of oil and natural gas properties, with particular
emphasis on U.S. onshore natural gas reserves. We also have oil and gas
activities in New Zealand, and to a lesser extent in Venezuela and Russia. Our
investments in associated oil and gas partnerships and joint ventures are
accounted for using the proportionate consolidation method, whereby our
proportionate share of each entity's assets, liabilities, revenues, and expenses
are included in the appropriate classifications in the consolidated financial
statements. Intercompany balances and transactions have been eliminated in
preparing the consolidated statements. In the second quarter of 1998, we began
netting supervision fees against general and administrative expenses and oil and
gas production costs. This reclassification has been made for all periods
presented. Certain other reclassifications have been made to prior year amounts
to conform to the current year presentation.
Use of Estimates. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from estimates.
Property and Equipment. We follow the "full-cost" method of accounting for
oil and gas property and equipment costs. Under this method of accounting, all
productive and nonproductive costs incurred in the acquisition, exploration, and
development of oil and gas reserves are capitalized. Under the full-cost method
of accounting, such costs may be incurred both prior to or after the acquisition
of a property and include lease acquisitions, geological and geophysical
services, drilling, completion, equipment, and certain general and
administrative costs directly associated with acquisition, exploration, and
development activities. Interest costs related to unproved properties are also
capitalized to unproved oil and gas properties. General and administrative costs
related to production and general overhead are expensed as incurred.
No gains or losses are recognized upon the sale or disposition of oil and
gas properties, except in transactions involving a significant amount of
reserves. The proceeds from the sale of oil and gas properties are generally
treated as a reduction of oil and gas property costs. Fees from associated oil
and gas exploration and development limited partnerships are credited to oil and
gas property costs to the extent they do not represent reimbursement of general
and administrative expenses currently charged to expense.
Future development, site restoration, and dismantlement and abandonment
costs, net of salvage values, are estimated on a property-by-property basis,
based on current economic conditions, and are amortized to expense as our
capitalized oil and gas property costs are amortized. Our properties are all
onshore, and historically the salvage value of the tangible equipment offsets
our site restoration and dismantlement and abandonment costs. We expect that
this relationship will continue in the future.
We compute the provision for depreciation, depletion, and amortization of
oil and gas properties on the unit-of-production method. Under this method, we
compute the provision by multiplying the total unamortized costs of oil and gas
properties--including future development, site restoration, and dismantlement
and abandonment costs, but excluding costs of unproved properties--by an overall
rate determined by dividing the physical units of oil and gas produced during
the period by the total estimated units of proved oil and gas reserves. This
calculation is done on a country-by-country basis for those countries with oil
and gas production. We currently have production in the United States only. All
other equipment is depreciated by the straight-line method at rates based on the
estimated useful lives of the property. Repairs and maintenance are charged to
expense as incurred. Renewals and betterments are capitalized.
The cost of unproved properties not being amortized is assessed quarterly,
on a country-by-country basis, to determine whether such properties have been
impaired. Domestically, any impairment assessed is added to the cost of proved
properties being amortized. In determining whether such costs should be
impaired, our management evaluates, among other factors, current oil and gas
industry conditions, international economic conditions, capital availability,
foreign currency exchange rates, the political stability in the countries in
which we have an investment, and available geological and geophysical
information. To the extent costs accumulated in our international initiatives
are determined by management to be costs that will not result in the addition of
proved reserves, any impairment is charged to income.
31
<PAGE>
Domestic Properties. At the end of each quarterly reporting period, the
unamortized cost of oil and gas properties, net of related deferred income
taxes, is limited to the sum of the estimated future net revenues from proved
properties using period-end prices, discounted at 10%, and the lower of cost or
fair value of unproved properties, adjusted for related income tax effects
("Ceiling Test"). This calculation is done on a country-by-country basis for
those countries with proved reserves. Currently, we have proved reserves in the
United States only.
The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves. There are
numerous uncertainties inherent in estimating quantities of proved reserves and
in projecting the future rates of production, timing, and plan of development.
The accuracy of any reserves estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify revision of such estimate. Accordingly, reserves estimates are often
different from the quantities of oil and gas that are ultimately recovered.
In 1998, as a result of low oil and gas prices at September 30, 1998, we
reported a non-cash write-down on a before-tax basis of $77.2 million ($50.9
million after tax) on our domestic properties.
Foreign Properties. During the third quarter of 1998, as we do every
reporting period, we evaluated all of our foreign unevaluated properties (a
detailed description of which is included in Note 8 to the Consolidated
Financial Statements), especially in light of the then increased volatility in
the oil and gas markets, international uncertainty, and turmoil in the world
capital markets.
The increased volatility in the oil and gas markets affected our cash flows
available for further exploration and forced us to scale back our capital
expenditures budget. All of this was further accentuated in Venezuela by the
economic crisis there, the results of which were to diminish the availability of
financing in international markets for Venezuelan projects and to worsen
Venezuelan currency problems. Petroleos de Venezuela, S.A., layoffs, threatened
oil worker strikes, reduced OPEC production allocations, and other third-quarter
1998 events highlighted the problems that the oil and gas industry was
encountering in Venezuela. As a result of these and other factors, in the third
quarter of 1998 we decided to impair all $2.8 million of costs related to our
Venezuelan oil and gas exploration activities.
In addition, in the third quarter of 1998, we impaired all $10.8 million of
costs relating to our Russian activities. This impairment was attributed not
only to the volatility in the oil and gas markets and the severe tightening of
international credit markets discussed above, but also to the increased
political instability in Russia and the August 1998 collapse of the Russian
currency. We believed that the economic and political situation would result in
the lack of capital to develop the reserves underlying our net profits interest
in the near term. Although we continue to believe that our net profits interest
is legally enforceable under international law, for all these reasons we did not
believe that realistically we would be able to recover our investment in Russia
in the foreseeable future. Because of this, we determined that we no longer had
a reasonable basis to continue capitalization of the costs in our Russia cost
center.
The combination of the third-quarter domestic full-cost ceiling write-down
and foreign activities impairment charges reduced before-tax earnings by $90.8
million ($59.9 million after tax).
During the fourth quarter of 1998 and the second quarter of 1999, we
charged to income as additional depreciation, depletion, and amortization costs
our portion of drilling costs associated with an unsuccessful exploratory well
in each quarter drilled by other operators in New Zealand. These costs were
$400,000 in 1998 and $300,000 in 1999.
Oil and Gas Revenues. Gas revenues are reported using the entitlement
method in which we recognize our ownership interest in natural gas production as
revenue. If our sales exceed our ownership share of production, the differences
are reported as deferred revenue. Natural gas balancing receivables are reported
when our ownership share of production exceeds sales. As of December 31, 1999,
we did not have any material natural gas imbalances.
Deferred Charges. Legal and accounting fees, underwriting fees, printing
costs, and other direct expenses associated with the public offering in November
1996 of our 6.25% Convertible Subordinated Notes (the "Convertible Notes") and
with the public offering in August 1999 of our 10.25% Senior Subordinated Notes
(the "Senior Notes") have been capitalized and are being amortized over the life
of each of the respective note offerings. The Convertible Notes mature on
November 15, 2006, and the balance of their issuance costs at December 31, 1999,
was $3,445,003, net of accumulated amortization of $1,104,997. The Senior Notes
mature on August 1, 2009 and the balance of their issuance costs at December 31,
1999, was $3,417,779, net of
32
<PAGE>
accumulated amortization of $83,662. The issuance costs associated with our
revolving credit facility, which closed in August 1998, have been capitalized
and are being amortized over the life of the facility, which will extend until
August 2002. The balance of these issuance costs at December 31, 1999, was
$367,426, net of accumulated amortization of $191,268.
Limited Partnerships and Joint Ventures. Between 1984 and 1995, we formed
88 limited partnerships for the purpose of acquiring interests in producing oil
and gas properties and, since 1993, 13 partnerships engaged in drilling for oil
and gas reserves. We serve as managing general partner of these entities. We
acquired producing oil and gas properties for the production purchase
partnerships and transferred those properties to the partnership entities that
invested in producing oil and gas properties. Producing property partnerships
have been in existence for periods ranging from four to thirteen years. Most of
these partnerships have produced a majority of their reserves and, having been
in existence for long periods of time, have entered the stage where
consideration of liquidation proposals is appropriate.
During 1997 and 1998, 21 of these partnerships were liquidated following a
vote of the limited partners in each of those partnerships to do so. Ten of
these 21 partnerships were the earliest public income partnerships formed by
Swift. As of early March 2000, an additional 10 partnerships voted to sell
substantially all of their assets and liquidate, and the efforts to sell their
assets have just commenced. Also in February and early March 2000, proxy
statements were sent to the investors in 55 of the 57 remaining production
purchase partnerships soliciting their votes upon proposals to sell their assets
and liquidate. The proxy statements for the remaining two partnerships will be
mailed shortly. If these proposals are approved, it is anticipated that these
liquidations will be substantially completed during 2000 and, if necessary,
2001.
Commencing in September 1993 on a private placement basis, we began
offering general and limited partnership interests in limited partnerships to be
formed to drill for oil and gas. As managing general partner, we paid for all
front-end costs incurred in connection with these offerings, for which we
received an interest in the partnerships. Through December 31, 1999,
approximately $66.1 million had been raised in thirteen partnerships, one each
formed in 1993 and 1994; three each in 1995, 1996, and 1997; and two in 1998.
During 1997, eight private drilling partnerships formed between 1979 and 1985
were liquidated following limited partner votes to do so.liquidated following
limited partner votes to do so.
Hedging Activities. Our revenues are primarily the result of sales of our
oil and natural gas production. Market prices of oil and natural gas may
fluctuate and adversely affect operating results. To mitigate some of this risk,
we engage periodically in certain hedging activities, which includes buying
protection price floors and entering into participation collars for portions of
our and the managed limited partnerships' oil and natural gas production. These
derivative financial instruments are placed with major financial institutions
that we believe present minimum credit risk. Costs and any benefits derived from
the price floors are recorded as a reduction or an increase, as applicable, in
oil and gas sales revenue. The costs to purchase put options are amortized over
the option period. The participating collars are designated as hedges and
realized gains or losses are recognized in oil and gas revenues when the
associated production occurs. The costs related to 1999 hedging activities,
consisting only of price floors, totaled approximately $909,000, with benefits
of approximately $348,000 being received, resulting in a net cash outlay of
approximately $561,000, or $0.013 per Mcfe. Regarding the price floors, the
costs related to the open contracts as of December 31, 1999, totaled
approximately $98,000 and had a fair market value of $112,500. At December 31,
1999, the participating collars had an approximate value, as quoted by the
dealers, of $95,000. The January 2000 collar has expired at a loss of $62,550.
The gains or losses of the remaining months are determined from an average of
the closing price of the contracts.
Income Taxes. We account for income taxes using the liability method.
Deferred taxes are determined based on the estimated future tax effects of
differences between the financial statement and tax bases of assets and
liabilities, given the provisions of the enacted tax laws.
Deferred Revenues. In May 1992, we purchased interests in certain wells
using funds provided by our sale of a volumetric production payment in these
properties to Enron. Under the production payment agreement, we are required to
deliver to Enron approximately 9.5 Bcf over an eight-year period, or for such
longer period as is necessary to deliver a specified heating equivalent quantity
at an average price of $1.115 per MMBtu. We receive all proceeds from sale of
excess gas at current market prices plus the proceeds from sale of oil or
condensate. Volumes remaining to be delivered through October 2000 under the
volumetric production payment were approximately 0.4 Bcf at December 31, 1999,
and were not included in our proved reserves. Net proceeds from the sale of the
production payment were recorded as deferred revenues. Deliveries under the
production payment agreement are recorded as oil and gas sales revenues and a
corresponding reduction of deferred revenues.
33
<PAGE>
Cash and Cash Equivalents. We consider all highly liquid debt instruments
with an initial maturity of three months or less to be cash equivalents.
Credit Risk Due to Certain Concentrations. We extend credit, primarily in
the form of monthly oil and gas sales and joint interest owners receivables, to
various companies in the oil and gas industry, which results in a concentration
of credit risk. The concentration of credit risk may be affected by changes in
economic or other conditions and may accordingly impact our overall credit risk.
However, we believe that the risk of these unsecured receivables are mitigated
by the size, reputation, and nature of the companies to which we extend credit.
During 1999, oil and gas sales to subsidiaries of Eastex Crude Company were
$21.7 million, or 19.4% of our oil and gas sales. During 1998, oil and gas sales
to subsidiaries of PG&E Energy Trading Corporation were $13.0 million, or 16.2%
of oil and gas sales, and to Aquila Southwest Pipeline Corporation were $8.0
million, or 10.0% of sales. In 1997, oil and gas sales to PG&E Energy Trading
Corporation were $13.5 million, or 19.5% of oil and gas sales; to Aquila
Southwest Pipeline Corporation were $8.1 million, or 11.7% of sales, and to Koch
Oil Company were $7.1 million, or 10.3% of sales.
Fair Value of Financial Instruments. Our financial instruments consist of
cash and cash equivalents, accounts receivable, accounts payable, bank
borrowings, and convertible notes. The carrying amounts of cash and cash
equivalents, accounts receivable, and accounts payable approximate fair value
due to the highly liquid nature of these short-term instruments. The fair values
of the bank borrowings approximate the carrying amounts as of December 31, 1999
and 1998, and were determined based upon interest rates currently available to
us for borrowings with similar terms. Based on quoted market prices as of the
respective dates, the fair values of our Convertible Notes were $89.7 million
and $81.4 million at December 31, 1999 and 1998, respectively, and the fair
value of our Senior Notes was $117.9 million at December 31, 1999. The carrying
value of our Convertible Notes was $115.0 million at December 31, 1999 and 1998,
and the carrying value of our Senior Notes was $124.1 million at December 31,
1999.
New Accounting Pronouncements. In June 1998, the Financial Accounting
Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities." The statement establishes accounting and reporting
standards requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded in the balance
sheet as either an asset or liability measured at its fair value. SFAS No. 133
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Special accounting
for qualifying hedges allows the gains and losses on derivatives to offset
related results on the hedged item in the income statements and requires that a
company must formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting. SFAS No. 133, as amended by SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133," is effective for fiscal years
beginning after June 15, 2000. We are currently evaluating the new standard, but
have not yet determined the impact it will have on our financial position and
results of operations.
2. Earnings Per Share
Basic earnings per share ("Basic EPS") has been computed using the weighted
average number of common shares outstanding during the respective periods. Basic
EPS has been retroactively restated in all periods presented to give recognition
to the 10% stock dividend declared in October 1997 that resulted in an
additional 1,494,622 shares being issued.
The calculation of diluted earnings per share ("Diluted EPS") assumes
conversion of our convertible notes as of the beginning of the respective
periods and the elimination of the related after-tax interest expense and
assumes, as of the beginning of the period, exercise of stock options and
warrants using the treasury stock method. The assumed conversion of our
convertible notes has been excluded from the calculation of Diluted EPS for the
1999 and 1998 periods, as they would have been antidilutive. Certain of our
stock options that would potentially dilute Basic EPS in the future have been
antidilutive for the 1999 and 1998 periods. Diluted EPS has also been
retroactively restated for all periods presented to give effect to the 10% stock
dividend. The original conversion price of the convertible notes of $34.6875 was
revised to $31.534 to reflect the October 1997 stock dividend declared.
34
<PAGE>
The following is a reconciliation of the numerators and denominators used
in the calculation of Basic and Diluted EPS for the years ended December 31,
1999, 1998, and 1997:
<TABLE>
<CAPTION>
1999 1998 1997
--------------------------------- ---------------------------------- ----------------------------------
Per Per Per
Net Share Net Share Net Share
Income Shares Amount Loss Shares Amount Income Shares Amount
----------- ----------- ------ ------------- ---------- -------- ------------ ----------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Basic EPS:
Net Income (Loss)
and Share Amounts $19,286,574 18,050,106 $ 1.07 $ (48,225,204) 16,436,972 $ (2.93) $ 22,310,189 16,492,856 $ 1.35
Dilutive Securities:
6.25% Convertible
Notes -- -- -- -- 3,525,808 3,646,847
Stock Options -- 42,365 -- -- -- 428,036
----------- ----------- ------------- ---------- ------------ -----------
Diluted EPS:
Net Income (Loss)and
Assumed Share
Conversions $19,286,574 18,092,471 $ 1.07 $ (48,225,204) 16,436,972 $ (2.93) $ 25,835,997 20,567,739 $ 1.26
----------- ----------- ------------- ---------- ------------ -----------
</TABLE>
3. Provision for Income Taxes
The following is an analysis of the consolidated income tax provision
(benefit):
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------
1999 1998 1997
--------------- -------------- --------------
<S> <C> <C> <C>
Current $ (11,819) $ 214,169 $ 77,402
Deferred 10,461,396 (25,380,546) 10,742,015
--------------- --------------- --------------
Total $ 10,449,577 $ (25,166,377) $ 10,819,417
=============== ============== ==============
</TABLE>
There are differences between income taxes computed using the statutory
rate (35% for 1999, 1998, and 1997) and our effective income tax rates (35.1%,
34.3%, and 32.7% for 1999, 1998, and 1997, respectively), primarily as the
result of certain tax credits available to us. Reconciliations of income taxes
computed using the statutory rate to the effective income tax rates are as
follows:
<TABLE>
<CAPTION>
1999 1998 1997
--------------- ------------- --------------
<S> <C> <C> <C>
Income taxes computed at federal statutory rate $ 10,407,653 $ (25,687,053) $ 11,595,362
State tax provisions, net of federal benefits (7,801) 23,949 48,058
Nonconventional fuel source credit --- (287,000) (294,000)
Depletion deductions in excess of basis --- (42,500) (51,000)
Other, net 49,725 826,227 (479,003)
--------------- ------------- -------------
Provision (benefit) for income taxes $ 10,449,577 $ (25,166,377) $ 10,819,417
=============== ============= =============
</TABLE>
35
<PAGE>
The tax effects of temporary differences representing the net deferred tax
liability (asset) at December 31, 1999 and 1998, were as follows:
<TABLE>
<CAPTION>
1999 1998
------------------ --------------
<S> <C> <C>
Deferred tax assets:
Alternative minimum tax credits $ (1,979,399) $ (1,979,399)
Other (237,587) (237,587)
------------------ --------------
Total deferred tax assets $ (2,216,986) $ (2,216,986)
Deferred tax liabilities:
Oil and gas properties $ 11,960,417 $ 1,531,651
Other 436,700 430,351
------------------ --------------
Total deferred tax liabilities $ 12,397,117 $ 1,962,002
------------------ --------------
Net deferred tax liability (asset) $ 10,180,131 $ (254,984)
================== ==============
</TABLE>
We did not record any valuation allowances against deferred tax assets at
December 31, 1999 and 1998.
At December 31, 1999, we had alternative minimum tax credits of $1,979,399
that carry forward indefinitely and are available to reduce future regular tax
liability to the extent they exceed the related tentative minimum tax otherwise
due.
4. Long-Term Debt
Our long-term debt as of December 31, 1999 and 1998, is as follows (in
thousands):
<TABLE>
<CAPTION>
1999 1998
------------ -----------
<S> <C> <C>
Bank Borrowings $ -- $ 146,200
Convertible Notes 115,000 115,000
Senior Notes 124,068 --
------------ -----------
Long-Term Debt $ 239,068 $ 261,200
============ ===========
</TABLE>
Bank Borrowings. At December 31, 1999, we had no borrowings under our
credit facility. At December 31, 1998, we had outstanding borrowings of $146.2
million under our $250.0 million credit facility, which we closed in August 1998
with a syndicate of ten banks. The interest rate was either (a) the lead bank's
prime rate (7.75% at December 31, 1998) or (b) the adjusted London Interbank
Offered Rate ("LIBOR") plus the applicable margin depending on the level of
outstanding debt. The applicable margin is based on our ratio of outstanding
balance on the credit facility to the last calculated borrowing base. Of the
$146.2 million borrowed at December 31, 1998, $145.0 million was borrowed at the
LIBOR rate (a weighted average of 6.34% at December 31, 1998).
This credit facility was restated in March 2000, effective November 1,
1999, and now consists of a $250.0 million revolving line of credit with a
$100.0 million borrowing base with a syndicate of nine banks. The interest rate
is either (a) the lead bank's prime rate (8.5% at December 31, 1999) or (b) the
adjusted London Interbank Offered Rate ("LIBOR") plus the applicable margin
depending on the level of outstanding debt. The applicable margin is based on
our ratio of outstanding balance on the credit facility to the last calculated
borrowing base.
The terms of our credit facility include, among other restrictions, a
limitation on the level of cash dividends (not to exceed $2.0 million in any
fiscal year), requirements as to maintenance of certain minimum financial ratios
(principally pertaining to working capital, debt, and equity ratios), and
limitations on incurring other debt. Since inception, no cash dividends have
been declared on our common stock. We are currently in compliance with the
provisions of this agreement. The credit facility extends until August 2002.
Interest expense on the credit facility, including commitment fees and
amortization of debt issuance costs, totaled $6,107,270 in 1999 and $5,575,505
in 1998.
36
<PAGE>
Convertible Notes. Our Convertible Notes at December 31, 1999 and 1998,
consist of $115,000,000 of 6.25% Convertible Subordinated Notes due 2006. The
Convertible Notes were issued on November 25, 1996, and will mature on November
15, 2006. The Convertible Notes are unsecured and convertible into common stock
of Swift at the option of the holders at any time prior to maturity at an
adjusted conversion price of $31.534 per share, subject to adjustment upon the
occurrence of certain events. The original conversion price of $34.6875 was
adjusted downward to reflect the October 1997 10% stock dividend. Interest on
the notes is payable semiannually, on May 15 and November 15, and commenced with
the first payment on May 15, 1997. On or after November 15, 1999, the
Convertible Notes are redeemable for cash at the option of Swift, with certain
restrictions, at 104.375% of principal, declining to 100.625% in 2005. Upon
certain changes in control of Swift, if the price of our common stock is not
above certain levels, each holder of Convertible Notes will have the right to
require us to repurchase the Convertible Notes at 101% of the principal amount
thereof, together with accrued and unpaid interest to the date of repurchase,
but after the repayment of any Senior Indebtedness, as defined.
Interest expense on the Convertible Notes, including amortization of debt
issuance costs, totaled $7,569,361 in 1999 and $7,544,650 in 1998.
Senior Notes. Our Senior Notes at December 31, 1999, consist of
$125,000,000 of 10.25% Senior Subordinated Notes due 2009. The Senior Notes were
issued at 99.236% of the principal amount on August 4, 1999, and will mature on
August 1, 2009. The Senior Notes are unsecured senior subordinated obligations
and are subordinated in right of payment to all our existing and future senior
debt, including our bank debt. Interest on the Senior Notes is payable
semiannually, on February 1 and August 1, and commenced with the first payment
on February 1, 2000. On or after August 1, 2004, the Senior Notes are redeemable
for cash at the option of Swift, with certain restrictions, at 105.125% of
principal, declining to 100% in 2007. In addition, prior to August 1, 2002, we
may redeem up to 33.33% of the Senior Notes with the proceeds of qualified
offerings of our equity at 110.25% of the principal amount of the Senior Notes,
together with accrued and unpaid interest. Upon certain changes in control of
Swift, each holder of Senior Notes will have the right to require us to
repurchase the Senior Notes at a purchase price in cash equal to 101% of the
principal amount, plus accrued and unpaid interest to the date of purchase.
Interest expense on the Senior Notes, including amortization of debt
issuance costs and discount, totaled $5,303,266 in 1999.
5. Commitments and Contingencies
Total rental and lease expenses were $1,272,497 in 1999, $1,117,351 in
1998, and $1,039,210 in 1997. Our remaining minimum annual obligations under
non-cancelable operating lease commitments are $1,151,249 for 2000, $1,151,249
for 2001, $1,273,007 for 2002, $1,358,238 for 2003, and $1,370,414 for 2004.
As of December 31, 1999, we are the managing general partner of 80 limited
partnerships. Because we serve as the general partner of these entities, under
state partnership law we are contingently liable for the liabilities of these
partnerships, which liabilities are not material for any of the periods
presented in relation to the partnerships' respective assets.
In the ordinary course of business, we have been party to various legal
actions, which arise primarily from our activities as operator of oil and gas
wells. In management's opinion, the outcome of any such currently pending legal
actions will not have a material adverse effect on the financial position or
results of operations of Swift.
6. Stockholders' Equity
Common Stock. During the third quarter of 1999, we issued 4.6 million
shares of common stock at a price of $9.75 per share. Gross proceeds from this
offering were $44,850,000 with issuance costs of $2,888,690.
In October 1997, we declared a 10% stock dividend to stockholders of
record. The transaction was valued based on the closing price ($28.8125) of our
common stock on the New York Stock Exchange on October 1, 1997. As a result of
the issuance of 1,494,622 shares of our common stock as a dividend, retained
earnings were reduced by $43,063,796, with the common stock and additional
paid-in capital accounts increased by the same amount. Basic and Diluted EPS
were restated for all periods presented to reflect the effect of the stock
dividend.
Stock-Based Compensation Plans. We have two stock option plans, the 1990
stock compensation plan and the 1990 non-qualified plan, as well as an employee
stock purchase plan.
37
<PAGE>
Under the 1990 stock compensation plan, incentive stock options and other
options and awards may be granted to employees to purchase shares of common
stock. Under the 1990 non-qualified plan, non-employee members of our Board of
Directors may be granted options to purchase shares of common stock. Both plans
provide that the exercise prices equal 100% of the fair value of the common
stock on the date of grant. Options become exercisable for 20% of the shares on
the first anniversary of the grant of the option and are exercisable for an
additional 20% per year thereafter. Options granted expire 10 years after the
date of grant or earlier in the event of the optionee's separation from
employment. At the time the stock options are exercised, the option price is
credited to common stock and additional paid-in capital.
On December 9, 1998, we canceled certain previously issued options under
the 1990 stock compensation plan and reissued them at an option price that
reflected current market value of our common stock as of that date. No
compensation expense was recognized in 1998 as a result of this transaction.
The employee stock purchase plan provides eligible employees the
opportunity to acquire shares of Swift common stock at a discount through
payroll deductions. The plan year is from June 1 to the following May 31. The
first year of the plan commenced June 1, 1993. To date, employees have been
allowed to authorize payroll deductions of up to 10% of their base salary during
the plan year by making an election to participate prior to the start of a plan
year. The purchase price for stock acquired under the plan will be 85% of the
lower of the closing price of our common stock as quoted on the New York Stock
Exchange at the beginning or end of the plan year or a date during the year
chosen by the participant. Under this plan, we have issued 22,771 shares at a
price range of $5.21 to $11.00 in 1999, 20,756 shares at a price range of $13.65
to $18.06 in 1998, and 26,551 shares at a price of $15.19 in 1997. The estimated
weighted average fair value of shares issued under this plan was $4.74 in 1999,
$6.86 in 1998, and $4.39 in 1997. As of December 31, 1999, there remained
414,677 shares available for issuance under this plan. There are no charges or
credits to income in connection with this plan.
We account for the two stock option plans under Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees." As all options were
issued at a price equal to market price, no compensation expense has been
recognized. Had compensation expense for these plans been determined based on
the fair value of the options consistent with SFAS No. 123, "Accounting for
Stock-Based Compensation," our net income (loss) and earnings per share would
have been reduced to the following pro forma amounts:
<TABLE>
<CAPTION>
1999 1998 1997
----------- ------------ -----------
<S> <C> <C> <C> <C>
Net Income (Loss): As Reported $19,286,574 $(48,225,204) $22,310,189
Pro Forma $16,869,122 $(49,985,171) $21,362,722
Basic EPS: As Reported $1.07 $(2.93) $1.35
Pro Forma $0.93 $(3.04) $1.30
Diluted EPS: As Reported $1.07 $(2.93) $1.26
Pro Forma $0.93 $(3.04) $1.21
</TABLE>
Pro forma compensation cost reflected above may not be representative of
the cost to be expected in future years.
38
<PAGE>
The following is a summary of our stock options under these plans as of
December 31, 1999, 1998, and 1997:
<TABLE>
<CAPTION>
1999 1998 1997
--------------------- ---------------------- --------------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Exer. Exer. Exer.
Shares Price Shares Price Shares Price
--------------------- ---------------------- --------------------------
<S> <C> <C> <C> <C> <C> <C>
Options outstanding, beginning of period 2,266,146 $ 9.03 1,761,512 $ 14.71 1,399,769 $ 12.09
Options granted 25,000 $ 12.50 1,319,881 $ 9.72 401,390 $ 26.23
Options cancelled (77,158) $ 8.95 (730,490) $ 24.15 (31,404) $ 12.99
Options exercised (65,477) $ 8.55 (84,757) $ 7.54 (137,155) $ 8.54
Options adjusted for 10% stock dividend -- -- 128,912
--------- ----------- -----------
Options outstanding, end of period 2,148,511 $ 9.08 2,266,146 $ 9.03 1,761,512 $ 14.71
========= =========== ===========
Options exercisable, end of period 1,280,156 $ 8.87 888,695 $ 8.64 869,484 $ 9.05
========= =========== ===========
Options available for future grant, end of
period 950,735 915,236 1,501,622
========= =========== ===========
Estimated weighted average fair value per
share of options granted during the year $7.10 $3.82 $13.98
========= =========== ===========
</TABLE>
The fair value of each option grant, as opposed to its exercise price, is
estimated on the date of grant using the Black-Scholes option-pricing model with
the following weighted average assumptions in 1999, 1998, and 1997,
respectively: no dividend yield; expected volatility factors of 44.2%, 42.3%,
and 38.7%; risk-free interest rates of 5.60%, 4.69%, and 6.02%; and expected
lives of 7.5, 7.0, and 7.5 years. The following table summarizes information
about stock options outstanding at December 31, 1999:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
---------------------------------------- -------------------------
Wtd. Avg.
Range of Number Remaining Wtd. Avg. Number Wtd. Avg.
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices at 12/31/99 Life Price at 12/31/99 Price
- -------------------- -------------- ------------ ----------- ------------- -----------
<S> <C> <C> <C> <C> <C>
$ 4.00 to $ 8.99 1,034,790 5.9 $ 7.79 655,595 $ 7.68
$ 9.00 to $17.99 1,053,283 6.6 $ 9.65 600,623 $ 9.63
$18.00 to $27.00 60,438 7.3 $ 21.43 23,938 $ 22.03
-------------- -------------
$ 4.00 to $27.00 2,148,511 6.3 $ 9.08 1,280,156 $ 8.87
============== =============
</TABLE>
Employee Stock Ownership Plan. In 1996, we established an Employee Stock
Ownership Plan ("ESOP") effective January 1, 1996. All employees over the age of
21 with one year of service are participants. This plan has a five-year cliff
vesting, and service is recognized after the ESOP effective date. The ESOP is
designed to enable our employees to accumulate stock ownership. While there will
be no employee contributions, participants will receive an allocation of stock
that has been contributed by Swift. Compensation expense is reported when such
shares are released to employees. The plan may also acquire common stock of
Swift purchased at fair market value. The ESOP can borrow money from Swift to
buy Swift stock. This was done in September 1996 to purchase 25,000 shares
(adjusted to 27,500 shares after the October 1, 1997, 10% stock dividend) from
our chairman. Benefits will be paid in a lump sum or installments, and the
participants generally have the choice of receiving cash or stock. At December
31, 1999 and 1998, all of the ESOP compensation was earned. At December 31,
1997, the unearned portions of the ESOP of $150,055 were recorded as a
contra-equity account entitled "Unearned ESOP Compensation."
Employee Savings Plan. We have a 401(k) savings plan under Section 401(k)
of the Internal Revenue Code. Eligible employees may make voluntary
contributions into the 401(k) savings plan with Swift contributing on behalf of
the eligible employee an amount equal to 100% of the first 2% of compensation
and 75% of the next 4% of compensation based on the contributions made by the
eligible employees. Our contribution to the 401(k) savings plan totaled
$474,000, $498,000, and $438,000 for the years ended December 31, 1999, 1998,
and 1997, respectively. The contributions in 1999 and 1997 were made half in
common stock and half in cash, while the 1998 contribution was made all in
common stock. The shares of common stock contributed to the 401(k) savings plan
totaled 21,810, 68,318, and 11,372 shares for the 1999, 1998, and 1997
contributions,
39
<PAGE>
respectively. The 1999 and 1998 shares contributed were from common stock held
as treasury stock and were contributed in early 2000 and 1999, respectively.
Common Stock Repurchase Program. In March 1997, our Board of Directors
approved a common stock repurchase program that terminated pursuant to its terms
as of June 30,1999. Under this program, we spent approximately $13.3 million to
acquire 927,774 shares in the open market at an average cost of $14.34 per
share. In March 1999, we used 68,318 shares of common stock held as treasury
stock to fund our employer contribution in the 401(k) savings plan. Through
December 31, 1999, 859,456 shares remain with a total cost of $12,325,668 and
are included in "Treasury stock held, at cost" on the balance sheet.
Shareholder Rights Plan. In August 1997, the Board of Directors declared a
dividend of one preferred share purchase right on each outstanding share of
Swift common stock. The rights are not currently exercisable but would become
exercisable if certain events occurred relating to any person or group acquiring
or attempting to acquire 15% or more of our outstanding shares of common stock.
Thereafter, upon certain triggers, each right not owned by an acquirer allows
its holder to purchase Swift securities with a market value of two times the
$150 exercise price.
7. Related-Party Transactions
We are the operator of a substantial number of properties owned by our
affiliated limited partnerships and joint ventures and, accordingly, charge
these entities and third-party joint interest owners operating fees. We are also
reimbursed for direct, administrative, and overhead costs incurred in conducting
the business of the limited partnerships, which totaled approximately
$4,000,000, $5,000,000, and $6,300,000 in 1999, 1998, and 1997, respectively. We
were also reimbursed by the limited partnerships and joint ventures for costs
incurred in the screening, evaluation, and acquisition of producing oil and gas
properties on their behalf. Such costs totaled approximately $490,000 in 1997.
With the acquisitions made in 1997, we have fulfilled our responsibility of
acquiring properties for such partnerships, as those partnerships are fully
invested in properties. In the case where the limited partners voted to sell
their remaining properties and liquidate their limited partnerships, we were
also reimbursed for direct, administrative, and overhead costs incurred in the
disposition of such properties, which costs totaled approximately $850,000,
$580,000, and $675,000 in 1999, 1998, and 1997, respectively.
8. Foreign Activities
New Zealand. Since October 1995, the New Zealand Minister of Energy has
issued to Swift two petroleum exploration permits. The first permit covered
approximately 65,000 acres in the Onshore Taranaki Basin of New Zealand's North
Island, and the second covered approximately 69,300 adjacent acres. A wholly
owned subsidiary, Swift Energy New Zealand Limited, formed in late 1997,
conducts our New Zealand activities and owns the interest in the permits. In
March 1998, we surrendered approximately 46,400 acres covered in the first
permit, and the remaining acreage has been included as an extension of the area
covered in the second permit, leaving us with only one expanded permit. On
October 18, 1999, this expanded permit was again extended to include
approximately 12,800 adjacent offshore acres. This permit now contains
approximately 100,700 acres. Under the terms of the expanded permit, we were
required to commence drilling one exploratory well prior to August 12, 1999.
That exploratory well commenced drilling in July 1999 and has been drilled
to its total depth. The Rimu-A1 well was completed, and a ten-day production
draw-down/build-up test has been performed. Our portion of the drilling,
completion, and testing costs incurred through December 31, 1999, were
approximately $6.9 million. We have committed to perform additional seismic
acquisition and analysis on the permit area, are evaluating longer-term
sustained testing of this well, and are analyzing further delineation activities
on the Rimu block. All other obligations under the permit have been fulfilled.
On October 23, 1998, we entered into separate agreements with Marabella
Enterprises Ltd., a subsidiary of Bligh Oil & Minerals N.L., an Australian
company, under which we obtained from Marabella a 25% working interest in
another New Zealand petroleum exploration permit and under which Marabella
became a 5% participant in our permit. During the fourth quarter of 1998,
Marabella drilled an unsuccessful exploration well on its permit. Accordingly,
we charged $400,000 against earnings, representing our costs of such well. We
also agreed in principle to participate with Marabella in an additional permit
as a 17.5% working interest owner. Additionally Swift obtained a 7.5% working
interest in another New Zealand permit from Antrim Oil and Gas Limited, a
Canadian company, and Antrim became a 5% participant in our permit. An
exploratory well was drilled and temporarily abandoned on Antrim's permit during
the second quarter of 1999, and we charged our $290,000 portion of the costs on
this well against earnings in that quarter.
40
<PAGE>
As of December 31, 1999, our investment in New Zealand totaled
approximately $12.5 million. Approximately $0.7 million of such costs have been
impaired while the remaining $11.8 million is included in the unproved
properties portion of oil and gas properties.
Russia. On September 3, 1993, we signed a Participation Agreement with
Senega, a Russian Federation joint stock company (in which we have an indirect
interest of less than 1%), to assist in the development and production of
reserves from two fields in Western Siberia, providing us with a minimum 5% net
profits interest from the sale of hydrocarbon products from the fields.
Additionally, we purchased a 1% net profits interest from Senega for $0.3
million. Senega is charged with the management and control of the field
development. Our investment in Russia, prior to its impairment in the third
quarter of 1998, was approximately $10.8 million and was previously included in
the unproved properties portion of oil and gas properties. However, the economic
and political uncertainty and currency concerns that arose during the third
quarter of 1998 in Russia, combined with the price volatility and severe
tightening of international capital markets, caused us to re-evaluate the timing
of the recovery of our capitalized costs in that country. See Note 1 to the
Consolidated Financial Statements for a more detailed discussion of the
impairment.
Venezuela. We formed a wholly owned subsidiary, Swift Energy de Venezuela,
C. A., for the purpose of submitting a bid on August 5, 1993, under the
Venezuelan Marginal Oil Field Reactivation Program. We have entered into an
agreement with Tecnoconsult, S. A., and Corporation EDC, S.A.C.A., Venezuelan
companies, to jointly formulate and submit a proposal to Petroleos de Venezuela,
S. A., for the construction and operation of a methane pipeline. Currently, the
technical and economic feasibility of the project is under study. Our investment
in Venezuela, prior to its impairment in the third quarter of 1998, was
approximately $2.8 million and was previously included in the unproved
properties portion of oil and gas properties. However, the economic uncertainty
and currency concerns in Venezuela, combined with the price volatility and
severe tightening of international capital markets, caused us to re-evaluate our
prospects of participating in further Venezuelan exploration activities in the
near-term and the prospects for recovery of our capitalized costs in that
country. See Note 1 to the Consolidated Financial Statements for a more detailed
discussion of the impairment.
9. Acquisition of Properties
We purchased oil and gas interests in the Brookeland and Masters Creek
areas from Sonat Exploration Company in the third quarter of 1998 for
approximately $85.8 million in cash. Of this purchase price, $55.5 million was
allocated to producing properties, $15.0 million to 20% interests in two natural
gas processing plants, and $15.3 million to leasehold properties.
This acquisition was accounted for by the purchase method and was
incorporated into our results of operations in the third quarter of 1998. The
following unaudited pro forma supplemental information presents consolidated
results of operations as if this acquisition had occurred on January 1, 1997:
<TABLE>
<CAPTION>
Year ended December 31,
------------------------------------------
Pro forma: 1998 1997
-------------- --------------
(Thousands, except per share amounts) (Unaudited)
<S> <C> <C>
Revenue $ 115,394 $ 139,584
Net Income Before Non-Cash Charge $ 19,098 $ 38,528
Net Income (Loss) $ (40,812) $ 38,528
Net Income (Loss) Per Share Amounts-
Basic $ (2.48) $ 2.34
Diluted $ (2.48) $ 2.04
</TABLE>
In late December 1999, we purchased additional working interests in the
Masters Creek area from Dominion Reserves, Inc., for approximately $14.0 million
and additional working interests in the S. Burr Ferry portion of Masters Creek
from Union Pacific for approximately $1.9 million. The interests acquired from
Dominion have year-end 1999 proved reserves of 17.1 Bcfe, while the interests
acquired from Union Pacific have 7.4 Bcfe.
41
<PAGE>
Supplemental Information (Unaudited)
Swift Energy Company and Subsidiaries
Capitalized Costs. The following table presents our aggregate capitalized
costs relating to oil and gas producing activities and the related depreciation,
depletion, and amortization:
<TABLE>
<CAPTION>
Year ended December 31,
------------------------------------
1999 1998
--------------- ----------------
Oil and Gas Properties:
<S> <C> <C>
Proved $ 573,360,199 $ 497,296,068
Unproved (not being amortized)--Domestic 45,902,357 51,040,378
Unproved (not being amortized)--Foreign 11,760,382 5,001,508
--------------- ----------------
631,022,938 553,337,954
Accumulated Depreciation, Depletion, and
Amortization (238,036,349) (196,626,243)
--------------- ----------------
$ 392,986,589 $ 356,711,711
=============== ================
</TABLE>
Of the $45,902,357 of domestic unproved property costs (primarily seismic
and lease acquisition costs) at December 31, 1999, excluded from the amortizable
base, $10,367,938 was incurred in 1999, $25,271,433 was incurred in 1998,
$5,540,914 was incurred in 1997, and $4,722,072 was incurred in prior years.
When we are in an active drilling mode, we evaluate the majority of these
unproved costs within a two to three year time frame. In response to past market
conditions, we decreased our 1999 drilling expenditures when compared to recent
years, which when coupled with the $15.3 million of leasehold properties
acquired in the Brookeland and Masters Creek Fields acquisition in 1998, may
extend the evaluation timeframe of such costs.
Of the $11,760,382 of net foreign unproved property costs at December 31,
1999, being excluded from the amortizable base, $6,758,874 was incurred in 1999,
$2,521,761 was incurred in 1998, $1,731,561 was incurred in 1997, and $748,186
was incurred in prior years. All of these costs were incurred in New Zealand, as
the costs incurred in Russia and Venezuela were impaired in the third quarter of
1998 (see Note 1 to the Consolidated Financial Statements). We expect to
complete our evaluation of the New Zealand well drilled during the second half
of 1999 by early 2000. For the remaining New Zealand properties, we expect to
complete our evaluation over the next two to three years.
42
<PAGE>
Costs Incurred. The following table sets forth costs incurred related to
our oil and gas operations:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------
1999 1998 1997
--------------- ---------------- ---------------
<S> <C> <C> <C>
Acquisition of proved properties $ 18,526,939 $ 59,487,524 $ 8,417,318
Lease acquisitions(1),(2) 10,382,672 38,658,047 21,603,732
Exploration(3) 11,019,430 12,578,124 10,705,115
Development 39,891,868 54,821,131 82,885,549
--------------- ---------------- ---------------
Total acquisition, exploration, and development (4) $ 79,820,909 $ 165,544,826 $ 123,611,714
--------------- ---------------- ---------------
Processing plants $ 1,607,559 $ 15,000,000 $ --
Field compression facilities 171,535 2,228,101 7,444,070
--------------- ---------------- ---------------
Total plants and facilities $ 1,779,094 $ 17,228,101 $ 7,444,070
--------------- ---------------- ---------------
Total costs incurred $ 81,600,003 $ 182,772,927 $ 131,055,784
=============== =============== ===============
</TABLE>
(1)Lease acquisitions for 1999, 1998, and 1997 include expenditures of
$1,131,014, $464,274, and $1,731,561, respectively, relating to our initiatives
in New Zealand. Lease acquisitions for 1998 and 1997 include expenditures of
$421,602 and $828,133, respectively, relating to initiatives in Venezuela; and
$592,841 and $658,145, respectively, relating to initiatives in Russia.
(2)These are actual amounts as incurred by year, including both proved and
unproved lease costs. The annual lease acquisition amounts added to proved oil
and gas properties (being amortized) for 1999, 1998, and 1997 were $16,020,693,
$13,853,129 and $7,384,385, respectively.
(3)Exploration for 1999 and 1998 include $5,918,100 and $2,057,487,
respectively, relating to New Zealand.
(4)Includes capitalized general and administrative costs directly
associated with the acquisition, exploration, and development efforts of
approximately $8,500,000, $12,300,000, and $11,700,000 in 1999, 1998, and 1997,
respectively. In addition, total includes $4,142,098, $3,849,665, and $2,326,691
in 1999, 1998, and 1997, respectively, of capitalized interest on unproved
properties.
Results of Operations. The following table sets forth results of our oil
and gas operations:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------
1999 1998 1997
-------------- ---------------- ----------------
<S> <C> <C> <C>
Oil and gas sales $ 108,898,696 $ 80,067,837 $ 69,015,189
Oil and gas production costs (19,645,740) (13,138,980) (8,778,876)
Depreciation and depletion (41,410,106) (38,490,222) (23,443,273)
Write-down of oil and gas properties -- (90,772,628) --
-------------- ---------------- ----------------
47,842,850 (62,333,993) 36,793,040
Provision (benefit) for income taxes 16,792,840 (21,380,560) 12,015,816
-------------- ---------------- ----------------
Results of producing activities $ 31,050,010 $ (40,953,433) $ 24,777,224
============== ================ ================
Amortization per physical unit of production
(equivalent Mcf of gas) $ 0.97 $ 0.99 $ 0.92
============== ================ ================
</TABLE>
43
<PAGE>
Supplemental Reserve Information. The following information presents
estimates of our proved oil and gas reserves, which are all located onshore in
the United States. All of our reserves were determined by us and audited by H.
J. Gruy and Associates, Inc. ("Gruy"), independent petroleum consultants. Gruy's
report dated February 9, 2000, is set forth as an exhibit to the Form 10-K
Report for the year ended December 31, 1999, and should be referred to in
connection with the following information:
Estimates of Proved Reserves
<TABLE>
<CAPTION>
Oil and
Natural Gas Condensate
(Mcf) (Bbls)
------------ --------------
<S> <C> <C>
Proved reserves as of December 31, 1996(1) 225,758,201 5,484,309
Revisions of previous estimates(2) (22,774,899) (427,412)
Purchases of minerals in place 30,342,398 580,278
Sales of minerals in place (1,155,706) (50,909)
Extensions, discoveries, and other additions 102,479,883 2,945,037
Production(3) (20,344,208) (672,385)
------------ --------------
Proved reserves as of December 31, 1997(1) 314,305,669 7,858,918
Revisions of previous estimates(2) (42,958,447) (2,291,223)
Purchases of minerals in place 54,189,901 7,237,298
Sales of minerals in place (1,727,878) (39,932)
Extensions, discoveries, and other additions 55,951,332 2,993,540
Production(3) (27,359,742) (1,800,676)
------------ --------------
Proved reserves as of December 31, 1998(1) 352,400,835 13,957,925
Revisions of previous estimates(2) (31,189,451) 2,058,725
Purchases of minerals in place 9,159,780 1,822,858
Sales of minerals in place (3,762,799) (260,287)
Extensions, discoveries, and other additions 30,107,908 5,791,966
Production(3) (26,756,524) (2,564,924)
------------ --------------
Proved reserves as of December 31, 1999(1) 329,959,749 20,806,263
============ ==============
Proved developed reserves,
December 31, 1996 135,424,880 3,622,480
December 31, 1997 191,108,214 4,288,696
December 31, 1998 197,105,963 7,142,566
December 31, 1999 174,046,096 8,437,299
</TABLE>
(1)Proved reserves exclude quantities subject to our volumetric production
payment agreement.
(2)Revisions of previous estimates are related to upward or downward variations
based on current engineering information for production rates, volumetrics, and
reservoir pressure. Additionally, changes in quantity estimates are affected by
the increase or decrease in crude oil and natural gas prices at each year-end.
Proved reserves, as of December 31, 1999, were based upon prices in effect at
year-end. The weighted average of such year-end prices were $2.58 per Mcf of
natural gas and $23.69 per barrel of oil, compared to $2.23 per Mcf and $11.23
per barrel as of December 31, 1998.
(3)Natural gas production for 1997, 1998, and 1999 excludes 1,015,226, 866,232,
and 728,235 Mcf, respectively, delivered under our volumetric production payment
agreement.
44
<PAGE>
Standardized Measure of Discounted Future Net Cash Flows. The standardized
measure of discounted future net cash flows relating to proved oil and gas
reserves is as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------
1999 1998 1997
---------------- ----------------- -----------------
<S> <C> <C> <C>
Future gross revenues $ 1,371,541,850 $ 972,852,038 $ 994,828,072
Future production costs (353,594,258) (294,307,549) (273,475,056)
Future development costs (156,738,446) (118,420,782) (92,946,811)
---------------- ----------------- ----------------
Future net cash flows before income taxes 861,209,146 560,123,707 628,406,205
Future income taxes (226,725,033) (123,875,660) (135,587,216)
---------------- ----------------- ----------------
Future net cash flows after income taxes 634,484,113 436,248,047 492,818,989
Discount at 10% per annum (195,540,279) (145,974,944) (199,980,649)
---------------- ----------------- ----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 438,943,834 $ 290,273,103 $ 292,838,340
================ ================= ================
</TABLE>
The standardized measure of discounted future net cash flows from
production of proved reserves was developed as follows:
1. Estimates are made of quantities of proved reserves and the future
periods during which they are expected to be produced based on year-end economic
conditions.
2. The estimated future gross revenues of proved reserves are priced on the
basis of year-end prices, exceptin those instances where fixed and determinable
gas price escalations are covered by contracts limited to the price we
reasonably expect to receive.
3. The future gross revenue streams are reduced by estimated future costs
to develop and to produce the proved reserves, as well as certain abandonment
costs based on year-end cost estimates and the estimated effect of future income
taxes.
4. Future income taxes are computed by applying the statutory tax rate to
future net cash flows reduced by the tax basis of the properties, the estimated
permanent differences applicable to future oil and gas producing activities, and
tax carry forwards.
The estimates of cash flows and reserves quantities shown above are based
on year-end oil and gas prices for each period. Under Securities and Exchange
Commission rules, companies that follow the full-cost accounting method are
required to make quarterly Ceiling Test calculations, using prices in effect as
of the period end date presented (see Note 1 to the Consolidated Financial
Statements). Application of these rules during periods of relatively low oil and
gas prices, even if of short-term seasonal duration, may result in write-downs.
The standardized measure of discounted future net cash flows is not
intended to present the fair market value of our oil and gas property reserves.
An estimate of fair value would also take into account, among other things, the
recovery of reserves in excess of proved reserves, anticipated future changes in
prices and costs, an allowance for return on investment, and the risks inherent
in reserve estimates.
45
<PAGE>
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------
1999 1998 1997
------------------ ----------------- ----------------
<S> <C> <C> <C>
Beginning balance $ 290,273,103 $ 292,838,340 $ 367,232,302
------------------ ----------------- --------------
Revisions to reserves proved in prior years--
Net changes in prices, production costs, and
future development costs 123,447,890 (107,301,930) (237,149,170)
Net changes due to revisions in quantity
estimates (23,746,974) (47,924,995) (27,188,512)
Accretion of discount 34,078,501 35,034,478 47,068,172
Other 2,032,696 (34,966,058) (37,336,420)
------------------ ----------------- --------------
Total revisions 135,812,113 (155,158,505) (254,605,930)
New field discoveries and extensions, net of future
production and development costs 102,582,467 73,956,430 110,396,029
Purchases of minerals in place 39,282,292 87,628,829 29,290,334
Sales of minerals in place (5,360,428) (1,928,900) (2,373,547)
Sales of oil and gas produced, net of production
costs (88,196,672) (65,680,050) (58,786,505)
Previously estimated development costs incurred 39,149,732 51,622,419 55,742,684
Net change in income taxes (74,598,773) 6,994,540 45,942,973
------------------ ----------------- --------------
Net change in standardized measure of discounted
future net cash flows 148,670,731 (2,565,237) (74,393,962)
------------------ ----------------- --------------
Ending balance $ 438,943,834 $ 290,273,103 $ 292,838,340
================== ================= ==============
</TABLE>
Quarterly Results. The following table presents summarized quarterly
financial information for the years ended December 31, 1998 and 1999:
<TABLE>
<CAPTION>
Income (Loss) Basic Earnings Diluted Earnings
Before Income Net Income (Loss) (Loss)
Revenues Taxes (Loss) Per Share Per Share
--------------- ---------------- ----------------- -------------- -----------------
1998
<S> <C> <C> <C> <C> <C>
First Quarter $ 16,475,229 $ 4,835,502 $ 3,229,615 $ 0.20 $ 0.20
Second Quarter 16,340,730 4,270,153 2,896,470 0.18 0.18
Third Quarter(1) 24,557,553 (87,052,299) (57,431,015) (3.50) (3.50)
Fourth Quarter 25,095,709 4,555,063 3,079,726 0.19 0.19
--------------- ----------------- ----------------
Total $ 82,469,221 $ (73,391,581) $ (48,225,204) $ (2.93) $ (2.93)
=============== ================= ================
1999
First Quarter $ 21,488,087 $ 1,905,419 $ 1,281,755 $ 0.08 $ 0.08
Second Quarter 23,928,734 4,786,405 3,152,027 0.20 0.20
Third Quarter 31,279,295 10,934,826 7,107,637 0.37 0.36
Fourth Quarter 33,974,891 12,109,501 7,745,155 0.37 0.36
--------------- ---------------- ----------------
Total $ 110,671,007 $ 29,736,151 $ 19,286,574 $ 1.07 $ 1.07
=============== ================ ================
</TABLE>
(1)The loss in the third quarter of 1998 was the result of a pre-tax write-down
of oil and gas properties of $90.8 million ($59.9 million after tax). See Note 1
to the Consolidated Financial Statements.
46
<PAGE>
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
The information required under Item 10 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 9, 2000, annual shareholders' meeting
is incorporated herein by reference.
Item 11. Executive Compensation
The information required under Item 11 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 9, 2000, annual shareholders' meeting
is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required under Item 12 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 9, 2000, annual shareholders' meeting
is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions
The information required under Item 13 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 9, 2000, annual shareholders' meeting
is incorporated herein by reference.
47
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. The following consolidated financial statements of Swift Energy Company
together with the report thereon of Arthur Andersen LLP dated February 9,
2000, and the data contained therein are included in Item 8 hereof:
<TABLE>
<S> <C> <C>
Report of Independent Public Accountants...............................26
Consolidated Balance Sheets............................................27
Consolidated Statements of Income......................................28
Consolidated Statements of Stockholders' Equity........................29
Consolidated Statements of Cash Flows..................................30
Notes to Consolidated Financial Statements.............................31
</TABLE>
2. Financial Statement Schedules
None
3. Exhibits
<TABLE>
<S> <C>
3(a).1(1) Articles of Incorporation, as amended through June 3, 1988.
3(a).2(2) Articles of Amendment to Articles of Incorporation filed on June 4, 1990.
3(b)(3) By-Laws, as amended through August 14, 1995.
4(a)(8) Indenture dated as of November 25, 1996, between Swift Energy Company and
Bank One, Columbus, N.A. as Trustee.
4(a).1(18) Indenture dated as of July 29, 1999, between Swift Energy Company and Bank
One, N.A., as Trustee.
4(a).2(17) First Supplemental Indenture dated as of August 4, 1999, between Swift
Energy Company and Bank One, N.A., including the form of 10.25% Senior
Subordinated Notes due 2009.
10.1(1)+ Indemnity Agreement dated July 8, 1988, between Swift Energy Company and A.
Earl Swift (plus schedule of other persons with whom Indemnity Agreements
have been entered into).
10.2(4)+ Swift Energy Company 1990 Nonqualified Stock Option Plan.
10.3(12) Credit Agreement among Swift Energy Company and Bank
One, Texas, National Association as administrative
agent, Bank of Montreal as syndication agent, and
Nationsbank, N.A. as documentation agent and the
lenders signatory hereto dated August 18, 1998.
10.4(14) First and Second Amendments to Credit Agreement among Swift Energy Company
and Bank One, Texas, National Association as administrative agent, Bank of
Montreal as syndication agent, and Nationsbank, N.A. as documentation agent
and the lenders signatory hereto dated September 30, 1998, and December 31,
1998.
10.5(13)+ Amended and Restated Swift Energy Company 1990 Stock Compensation Plan, as
of May 1997.
</TABLE>
48
<PAGE>
<TABLE>
<S> <C>
10.6(3) + Employment Agreement dated as of November 1, 1995, by and between Swift
Energy Company and Terry E. Swift.
10.7(3) + Employment Agreement dated as of November 1, 1995, by and between Swift
Energy Company and John R. Alden.
10.8(3) + Employment Agreement dated as of November 1, 1995, by and between Swift
Energy Company and James M. Kitterman.
10.9(3) + Employment Agreement dated as of November 1, 1995, by and between Swift
Energy Company and Bruce H. Vincent.
10.10(3)+ Employment Agreement dated as of November 1, 1995, by and between Swift
Energy Company and A. Earl Swift.
10.11(6)+ Agreement and Release between Swift Energy Company and Virgil Neil Swift
effective June 1, 1994.
10.12(7)+ First Amendment to Agreement and Release dated as of 12/1/95, by and
between Swift Energy Company and Virgil Neil Swift.
10.13(7)+ Second Amendment to Agreement and Release dated as of 2/2/96, by and
between Swift Energy Company and Virgil Neil Swift, effective January 1,
1996.
10.14(7)+ Second [sic] Amendment to Agreement and Release dated as of 1/14/97, by and
between Swift Energy Company and Virgil Neil Swift, effective December 1,
1996.
10.15(10)+ Employment Agreement dated as of February 1, 1998, by and between Swift
Energy Company and Joseph A. D'Amico.
10.16(9) Rights Agreement dated as of August 1, 1997, between Swift Energy Company
and American Stock Transfer & Trust Company.
10.17(11) Purchase and Sale Agreement dated as of June 1, 1998, between Swift Energy
Company and Sonat Inc.
10.18(14)+ Amendment to Employment Agreement dated as of November 1, 1995, by and
between Swift Energy Company and A. Earl Swift.
10.19(15) Amended and Restated Rights Agreement between Swift Energy Company and
American Stock Transfer & Trust Company, dated March 31, 1999.
10.20(16)+ Third Amendment to Agreement and Release, by and between Swift Energy
Company and Virgil Neil Swift, dated February 15, 1999.
10.21(16)+ Employment Agreement between Swift Energy Company and Alton D. Heckaman,
Jr., dated May 11, 1999.
10.22(17) Third Amendment to Credit Agreement among Swift Energy Company, Bank One,
Texas, National Association, Bank of Montreal and Nationsbank, N.A.,
effective July 19, 1999.
10.23(17) Letter Agreement among Swift Energy Company, Bank One, Texas, N.A. and
other Lenders party to the Credit Agreement, dated August 18, 1999.
10.24* Amended and Restated Credit Agreement among Swift Energy Company and Bank
One, Texas, National Association as administrative agent, ABN-AMRO Bank
N.V. as syndication agent, and CIBC Inc. as documentation agent and the
lenders signatory hereto dated March 10, 2000.
12* Swift Energy Company Ratio of Earnings to Fixed Charges.
18(5) Letter from Arthur Andersen LLP dated February 17, 1995, regarding change
in accounting principle.
</TABLE>
49
<PAGE>
<TABLE>
<S> <C>
21(6) List of Subsidiaries of Swift Energy Company.
23(a)* The consent of H. J. Gruy and Associates, Inc.
23(b)* The consent of Arthur Andersen LLP as to incorporation
by reference regarding Forms S-8 and S-3 Registration
Statements.
27* Financial Data Schedule (included in electronic filing only).
99* The H. J. Gruy and Associates, Inc. report, dated February 9, 2000.
</TABLE>
(b) No reports on Form 8-K were filed during the fourth quarter of 1999.
(1)Incorporated by reference from Swift Energy Company Annual Report on Form
10-K for the fiscal year ended December 31, 1988, File No. 1-8754.
(2)Incorporated by reference from Swift Energy Company Annual Report on Form
10-K for the fiscal year ended December 31, 1992.
(3)Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q filed for the quarterly period ended September 30, 1995.
(4)Incorporated by reference from Registration Statement No. 33-36310 on Form
S-8 filed on August 10, 1990.
(5)Incorporated by reference from Swift Energy Company Annual Report on Form
10-K for the fiscal year ended December 31, 1994.
(6)Incorporated by reference from Registration Statement No. 33-60469 on Form
S-2 filed on June 22, 1995.
(7)Incorporated by reference from Swift Energy Company Annual Report on Form
10-K from the fiscal year ended December 31, 1996.
(8)Incorporated by reference from Registration Statement No. 33-14785 on Form
S-3 filed on October 24, 1996.
(9)Incorporated by reference from Swift Energy Company Report on Form 8-K dated
August 1, 1997.
(10)Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q filed for the quarterly period ended June 30, 1998.
(11)Incorporated by reference from Swift Energy Company Report on Form 8-K dated
July 2, 1998.
(12)Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q filed for the quarterly period ended September 30, 1998.
(13)Incorporated by reference from Swift Energy Company definitive proxy
statement for annual shareholders meeting filed April 14, 1997.
(14)Incorporated by reference from Swift Energy Company Annual Report on Form
10-K from the fiscal year ended December 31, 1998.
(15)Incorporated by reference from Swift Energy Company Amendment No. 1 to Form
8-A, filed April 7, 1999.
(16)Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q for the quarterly period ended June 30, 1999.
(17)Incorporated by reference from Swift Energy Company Report on Form 8-K dated
August 4, 1999.
(18)Incorporated by reference from Exhibit 4.2 to Pre-Effective Amendment No. 1
to Form S-3 Registration Statement No. 33-81651 of Swift Energy Company,
filed July 9, 1999, which Exhibit 4.2 is the form of such Indenture.
*Filed herewith.
+Management contract or compensatory plan or arrangement.
50
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant, Swift Energy Company, has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.
SWIFT ENERGY COMPANY
By /S/ A. Earl Swift
------------------------------
A. Earl Swift
Chairman of the Board,
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant, Swift Energy Company, and in the capacities and on the dates
indicated:
<TABLE>
<CAPTION>
Signatures Title Date
----------- ------ -----
<S> <C> <C>
/S/ A. Earl Swift Chairman of the Board
- ---------------------------------- Chief Executive Officer March 27, 2000
A. Earl Swift
/S/ John R. Alden Senior Vice President--Finance
- ---------------------------------- Principal Financial Officer March 27, 2000
John R. Alden
/S/ Alton D. Heckaman, Jr. Vice President & Controller
- ---------------------------------- Principal Accounting Officer March 27, 2000
Alton D. Heckaman, Jr.
/S/ Virgil N. Swift
- ---------------------------------- Director March 27, 2000
Virgil N. Swift
/S/ G. Robert Evans
- ---------------------------------- Director March 27, 2000
G. Robert Evans
51
<PAGE>
/S/ Raymond O. Loen
- ---------------------------------- Director March 27, 2000
Raymond O. Loen
/S/ Henry C. Montgomery
- ---------------------------------- Director March 27, 2000
Henry C. Montgomery
/S/ Clyde W. Smith, Jr.
- ---------------------------------- Director March 27, 2000
Clyde W. Smith, Jr.
/S/ Harold J. Withrow
- ---------------------------------- Director March 27, 2000
Harold J. Withrow
</TABLE>
52
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
EXHIBITS
TO
FORM 10-K REPORT
FOR THE
YEAR ENDED DECEMBER 31, 1999
SWIFT ENERGY COMPANY
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060
53
<PAGE>
EXHIBITS
10.24 Amended and Restated Credit Agreement among Swift Energy Company and
Bank One, Texas, National Association as administrative agent, ABN-AMRO
Bank N.V. as syndication agent, and CIBC Inc. as documentation agent
and the lenders signatory hereto dated March 10, 2000.
12 Swift Energy Company Ratio of Earnings to Fixed Charges.
23 (a) The consent of H.J. Gruy and Associates, Inc.
23 (b) The consent of Arthur Andersen LLP as to incorporation by reference of
its report into Forms S-8 and S-3 Registration Statements.
99 The H.J. Gruy and Associates, Inc. report, dated February 9, 2000.
54
<PAGE>
Exhibit 10.24
55
<PAGE>
AMENDED AND RESTATED CREDIT AGREEMENT
AMONG
SWIFT ENERGY COMPANY,
AS BORROWER,
BANK ONE, TEXAS, NATIONAL ASSOCIATION
AS ADMINISTRATIVE AGENT
AND
ABN-AMRO BANK N.V.
AS SYNDICATION AGENT
AND
CIBC INC.
AS DOCUMENTATION AGENT
AND
CREDIT LYONNAIS
AND
WELLS FARGO BANK (TEXAS), NATIONAL ASSOCIATION
AS CO-AGENTS
AND
THE LENDERS SIGNATORY HERETO
March 10, 2000
Revolving Line of Credit
of up to $250,000,000
with Letter of Credit Subfacility
56
<PAGE>
TABLE OF CONTENTS
Page
ARTICLE 1 DEFINITIONS 1
1.1 Terms Defined Above 1
1.2 Additional Defined Terms 1
1.3 Undefined Financial Accounting Terms 15
1.4 References 16
1.5 Articles and Sections 16
1.6 Number and Gender 16
1.7 Incorporation of Exhibits 16
ARTICLE 2 TERMS OF THE FACILITY 16
2.1 Revolving Line of Credit 16
2.2 Letter of Credit Facility 17
2.3 Limitations on Interest Periods 18
2.4 Limitation on Types of Loans 19
2.5 Use of Loan Proceeds and Letters of Credit 19
2.6 Interest 19
2.7 Repayment of Loans and Interest 20
2.8 General Terms 20
2.9 Time, Place, and Method of Payment 21
2.10 Pro Rata Treatment; Adjustments 21
2.11 Borrowing Base Determinations 22
2.12 Mandatory Prepayments 23
2.13 Voluntary Prepayments and Conversions of Loans 23
2.14 Commitment Fee 23
2.15 Letter of Credit Fee 24
2.16 Loans to Satisfy Obligations of Borrower 24
2.17 Security Interest in Accounts; Right of Offset 24
2.18 General Provisions Relating to Interest 24
2.19 Obligations Absolute 25
2.20 Yield Protection 26
2.21 Illegality 28
2.22 Taxes 28
2.23 Replacement Lenders 29
2.24 Regulatory Change 30
ARTICLE 3 CONDITIONS 31
3.1 Conditions Precedent to Initial Loan and Letter of Credit 31
3.2 Conditions Precedent to Each Loan 33
3.3 Conditions Precedent to Issuance of Letters of Credit 33
ARTICLE 4 REPRESENTATIONS AND WARRANTIES 34
4.1 Existence of Borrower and Subsidiaries 34
4.2 Existence of Partnerships 34
4.3 Due Authorization 34
i
57
<PAGE>
4.4 Valid and Binding Obligations of Borrower 35
4.5 Security Instruments 35
4.6 Scope and Accuracy of Financial Statements 35
4.7 Liabilities, Litigation and Restrictions 35
4.8 Title to Properties 35
4.9 Compliance with Federal Reserve Regulations. 35
4.10 Authorizations and Consents 36
4.11 Compliance with Laws, Rules, Regulations and Orders 36
4.12 Proper Filing of Tax Returns and Payment of Taxes Due 36
4.13 ERISA Compliance 36
4.14 Take-or-Pay; Gas Imbalances 36
4.15 Refunds 37
4.16 Casualties or Taking of Property 37
4.17 Locations of Business and Offices 37
4.18 Environmental Compliance 37
4.19 Investment Company Act Compliance 38
4.20 Public Utility Holding Company Act Compliance 38
4.21 No Material Misstatements 38
4.22 Subsidiaries 38
4.23 Defaults 38
4.24 Maintenance of Properties 38
ARTICLE 5 AFFIRMATIVE COVENANTS 39
5.1 Maintenance and Access to Records 39
5.2 Quarterly Financial Statements 39
5.3 Annual Financial Statements 39
5.4 Compliance Certificates 39
5.5 Oil and Gas Reserve Reports 39
5.6 SEC and Other Reports 40
5.7 Notices 40
5.8 Letters in Lieu of Transfer Orders; Division Orders 41
5.9 Additional Information 42
5.10 Payment of Assessments and Charges 42
5.11 Compliance with Laws 42
5.12 ERISA Information and Compliance 42
5.13 Hazardous Substances Indemnification 42
5.14 Further Assurances 43
5.15 Fees and Expenses of Administrative Agent 43
5.16 Indemnification of Lenders and Administrative Agent 44
5.17 Maintenance of Existence and Good Standing 44
5.18 Maintenance of Tangible Property 44
5.19 Maintenance of Insurance 45
5.20 Inspection of Tangible Property 45
5.21 Payment of Notes and Performance of Obligations 45
5.22 Operation of Oil and Gas Properties 45
5.23 Performance of Designated Contracts 45
ARTICLE 6 NEGATIVE COVENANTS 45
6.1 Indebtedness; Contingent Obligations 45
6.2 Loans or Advances 46
6.3 Sales of Properties; Leasebacks 46
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6.4 Dividends and Distributions 46
6.5 Changes in Corporate Structure 46
6.6 Rental or Lease Agreement 47
6.7 Investments 47
6.8 Lines of Business; Subsidiaries 47
6.9 ERISA Compliance 47
6.10 Sale or Discount of Receivables 47
6.11 Transactions With Affiliates 48
6.12 Tangible Net Worth 48
6.13 Current Ratio 48
6.14 Debt Coverage Ratio 48
6.15 Total Liabilities to Tangible Net Worth 48
6.16 Amendment of Partnership Agreements 48
6.17 Subordinated Debt and Senior Subordinated Debt 48
6.18 Negative Pledges 48
6.19 Senior Subordinated Debt 48
ARTICLE 7 EVENTS OF DEFAULT 49
7.1 Enumeration of Events of Default 49
7.2 Rights Upon Default 50
ARTICLE 8 THE ADMINISTRATIVE AGENT 51
8.1 Appointment 51
8.2 Delegation of Duties 51
8.3 Exculpatory Provisions 51
8.4 Reliance by Administrative Agent 52
8.5 Notice of Default 52
8.6 Non-Reliance on Administrative Agent and Other Lenders 52
8.7 Indemnification 53
8.8 Restitution 53
8.9 Administrative Agent in Its Individual Capacity 54
8.10 Successor Administrative Agent 54
8.11 Applicable Parties 54
ARTICLE 9 MISCELLANEOUS 54
9.1 Assignments; Participations 54
9.2 Amendments and Waivers 55
9.3 Survival of Representations, Warranties and Covenants 56
9.4 Notices and Other Communications 56
9.5 Parties in Interest 56
9.6 No Waiver; Rights Cumulative 56
9.7 Survival Upon Unenforceability 57
9.8 Rights of Third Parties 57
9.9 Controlling Agreemen 57
9.10 Integration 57
9.11 Jurisdiction and Venue 57
9.12 Waiver of Rights to Jury Trial 57
9.13 Governing Law 58
9.14 Counterparts 58
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EXHIBITS
Exhibit I Form of Notes
Exhibit II Form of Assignment Agreement
Exhibit III Form of Borrowing Request
Exhibit IV Form of Compliance Certificate
Exhibit V Facility Amounts
Exhibit VI Disclosures
Exhibit VII Form of Opinion of Counsel
Exhibit VIII Subsidiaries and Partnerships
Exhibit IX Description of New Zealand Property
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AMENDED AND RESTATED CREDIT AGREEMENT
THIS AMENDED AND RESTATED CREDIT AGREEMENT (this "Agreement")
is made and entered into as of March 10, 2000, by and among SWIFT ENERGY
COMPANY, a Texas corporation (the "Borrower"), each lender that is a signatory
hereto or becomes a signatory hereto as provided in Section (individually,
together with its successors and assigns, a "Lender" and, collectively, together
with their respective successors and assigns, the "Lenders"), and BANK ONE,
TEXAS, NATIONAL ASSOCIATION, a national banking association, as Administrative
Agent for the Lenders (in such capacity, together with its successors in such
capacity pursuant to the terms hereof, the "Administrative Agent"), ABN-AMRO
BANK N.V. as Syndication Agent, CIBC INC. as Documentation Agent, and CREDIT
LYONNAIS and WELLS FARGO BANK (TEXAS), NATIONAL ASSOCIATION, as Co-Agents.
W I T N E S S E T H:
-------------------
WHEREAS, the Borrower and the Lenders entered into a Credit
Agreement dated August 18, 1998, as amended by First Amendment dated effective
as of September 30, 1998; Second Amendment dated effective as of December 31,
1998; and Third Amendment dated effective as of July 19, 1999;
WHEREAS, the parties thereto deserve to amend and restate such
Credit Agreement as amended;
NOW, THEREFORE, in consideration of the premises and the
mutual covenants and agreements herein contained, the parties hereto agree as
follows:
ARTICLE 1
DEFINITIONS AND INTERPRETATION
1.1 Terms Defined Above. As used in this Agreement, the terms "Administrative
Agent," "Agreement," "Borrower," "Lender," and "Lenders" shall have the meanings
set forth above.
1.2 Additional Defined Terms. As used in this Agreement, the following terms
shall have the following meanings, unless the context otherwise requires:
"Additional Costs" shall mean costs which the Administrative
Agent or any Lender determines are attributable to its obligation to
make or its making or maintaining any LIBO Rate Loan or issuing or
participating in Letters of Credit, or any reduction in any amount
receivable by the Administrative Agent or such Lender in respect of any
such obligation or any LIBO Rate Loan or Letter of Credit, resulting
from any Regulatory Change which (a) changes the basis of taxation of
any amounts payable to the Administrative Agent or such Lender under
this Agreement or any Note in respect of any LIBO Rate Loan or Letter
of Credit (other than taxes imposed on the overall net income of the
Administrative
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Agent or such Lender or its Applicable Lending Office for any such LIBO
Rate Loan by the jurisdiction in which the Administrative Agent or such
Lender has its principal office or Applicable Lending Office), (b)
imposes or modifies any reserve, special deposit, minimum capital,
capital ratio, or similar requirements (other than the Reserve
Requirement utilized in the determination of the Adjusted LIBO Rate for
such Loan) relating to any extensions of credit or other assets of, or
any deposits with or other liabilities of, the Administrative Agent or
such Lender (including LIBO Rate Loans and Dollar deposits in the
London interbank market in connection with LIBO Rate Loans), or any
commitments of the Administrative Agent or such Lender hereunder, or
the London interbank market, or (c) imposes any other condition
affecting this Agreement or any of such extensions of credit,
liabilities, or commitments.
"Adjusted LIBO Rate" shall mean, for any Interest Period for
any LIBO Rate Loan, an interest rate per annum (rounded upwards, if
necessary, to the nearest 1/100 of 1%) determined by the Administrative
Agent to be equal to the quotient of (a) the sum of the LIBO Rate for
such Interest Period for such Loan plus the Applicable Margin for a
LIBO Rate Loan divided by (b) 1 minus the Reserve Requirement for such
Loan for such Interest Period, such rate to be computed on the basis of
a year of 360 days and actual days elapsed (including the first day but
excluding the last day) during the period for which payable, but in no
event shall such rate exceed the Highest Lawful Rate.
"Affiliate" shall mean any Person directly or indirectly
controlling, controlled by, or under common control with the Borrower,
including each Partnership and each affiliate and subsidiary (within
the meaning of the regulations promulgated pursuant to the Securities
Act of 1933, as amended) of the Borrower.
"Agreement" shall mean this Credit Agreement, as amended,
restated or supplemented from time to time.
"Applicable Lending Office" shall mean, for each Lender and
type of Loan, the lending office of such Lender (or an affiliate of
such Lender) designated for such type of Loan on the signature pages
hereof or such other office of such Lender (or an affiliate of such
Lender) as such Lender may from time to time specify to the
Administrative Agent and the Borrower as the office by which its Loans
of such type are to be made and maintained.
"Applicable Margin" shall mean at any time for LIBO Rate Loans
and Floating Rate Loans an incremental rate of interest shall be
determined by the ratio of (i) the sum of the Loan Balance and L/C
Exposure to (ii) the last calculated Borrowing Base as set out below in
basis points:
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<TABLE>
<CAPTION>
Ratio Floating LIBO
----- Rate Margin Margin
----------- -------
<S> <C> <C>
less than 50% 0.00 bps 112.50 bps
equal to or greater than 50% but 0.00 bps 137.50 bps
less than 75%
equal to or greater than 75% but 0.00 bps 162.50 bps
less than 90%
equal to or greater than 90% 0.00 bps 175.00 bps
</TABLE>
"Assignment Agreement" shall mean an Assignment Agreement,
substantially in the form of Exhibit II, with appropriate insertions.
"Available Commitment" shall mean, at any time, an amount
equal to the remainder, if any, of (a) the lesser of the Maximum
Facility Amount or the Borrowing Base in effect at such time minus (b)
the sum of the Loan Balance at such time plus the L/C Exposure at such
time.
"Base Rate" shall mean the interest rate announced or
published by Bank One from time to time as its general reference rate
of interest, which Base Rate shall change upon each change in such
announced or published general reference interest rate and which Base
Rate may not be the lowest interest rate charged by Bank One.
"Benefitted Lender" shall have the meaning assigned to such
term in Section 2.10(c).
"Borrowing Base" shall mean, at any time, an amount equal to
the sum of the Distribution Shares and the Oil and Gas Properties, for
loan purposes, as determined by the Lenders from time to time in
accordance with Section 2.11.
"Borrowing Request" shall mean each written request, in
substantially the form attached hereto as Exhibit III, by the Borrower
to the Administrative Agent for a borrowing or conversion pursuant to
Sections 2.1 or 2.13, each of which shall:
(a) be signed by a Responsible Officer;
(b) specify the amount and type of Loan requested or to be
converted and the date of the borrowing or conversion (which
shall be a Business Day);
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(c) when requesting a Floating Rate Loan, be delivered to the
Administrative Agent no later than 11:00 a.m., Central
Standard or Daylight Savings Time, as the case may be, on the
Business Day of the requested borrowing or conversion; and
(d) when requesting a LIBO Rate Loan, be delivered to the
Administrative Agent no later than 11:00 a.m., Central
Standard or Daylight Savings Time, as the case may be, the
third Business Day preceding the requested borrowing or
conversion and designate the Interest Period requested with
respect to such Loan.
"Business Day" shall mean a day other than a day when
commercial banks are authorized or required to close in the State of
Texas and, with respect to all requests, notices, and determinations in
connection with, and payments of principal and interest on, LIBO Rate
Loans, which is also a day for trading by and between banks in Dollar
deposits in the London interbank market.
"Cash Flow" shall mean, for any period, the sum of (a) the net
income (or loss) of the Borrower and its Subsidiaries on a consolidated
basis for such period, determined in accordance with GAAP, exclusive of
non-cash revenue, plus (b) depreciation, depletion, non-cash
amortization, deferred income taxes, and other non-cash charges to
income, determined on a consolidated basis for the Borrower and its
Subsidiaries.
"Closing Date" shall mean March 10, 2000.
"Collateral" shall mean the Mortgaged Properties and any other
Property now or at any time used or intended as security for the
payment or performance of all or any portion of the Obligations.
"Commitment Period" shall mean the period from and including
the Closing Date to but not including the Commitment Termination Date.
"Commitment Termination Date" shall mean August 18, 2002.
"Commitments" shall mean the several obligations of the
Lenders to make Loans to or for the benefit of the Borrower pursuant to
Section 2.1 and the obligations of the Administrative Agent to issue
and the Lenders to participate in Letters of Credit pursuant to Section
2.2.
"Commonly Controlled Entity" shall mean any Person which is
under common control with the Borrower within the meaning of Section
4001 of ERISA.
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"Compliance Certificate" shall mean each certificate
substantially in the form attached hereto as Exhibit IV, signed by any
Responsible Officer and furnished to the Administrative Agent from time
to time in accordance with the terms hereof.
"Contingent Obligation" shall mean, as to any Person, any
obligation of such Person guaranteeing or in effect guaranteeing any
Indebtedness, leases, dividends, or other obligations of any other
Person (for purposes of this definition, a "primary obligation") in any
manner, whether directly or indirectly, including any obligation of
such Person, regardless of whether such obligation is contingent, (a)
to purchase any primary obligation or any Property constituting direct
or indirect security therefor, (b) to advance or supply funds (i) for
the purchase or payment of any primary obligation, or (ii) to maintain
working or equity capital of any other Person in respect of any primary
obligation, or otherwise to maintain the net worth or solvency of any
other Person, (c) to purchase Property, securities or services
primarily for the purpose of assuring the owner of any primary
obligation of the ability of the Person primarily liable for such
primary obligation to make payment thereof, or (d) otherwise to assure
or hold harmless the owner of any such primary obligation against loss
in respect thereof, with the amount of any Contingent Obligation being
deemed to be equal to the stated or determinable amount of the primary
obligation in respect of which such Contingent Obligation is made or,
if not stated or determinable, the maximum reasonably anticipated
liability in respect thereof as determined by such Person in good
faith.
"Current Assets" shall mean all assets which would, in
accordance with GAAP, be included as current assets on a consolidated
balance sheet of the Borrower and its Subsidiaries as of the date of
calculation, plus unused availability under this Agreement.
"Current Liabilities" shall mean all liabilities which would,
in accordance with GAAP, be included as current liabilities on a
consolidated balance sheet of the Borrower and its Subsidiaries as of
the date of calculation, but excluding current maturities in respect of
the Loans.
"Debt Service" shall mean, at any time, four percent of the
aggregate amount of all Subordinated Debt, Senior Subordinated Debt,
amounts funded under this Agreement, and any other funded debt of the
Borrower and its Subsidiaries on a consolidated basis allowed by the
Lenders.
"Default" shall mean any event or occurrence which with the
lapse of time or the giving of notice or both would become an Event of
Default.
"Default Rate" shall mean a per annum interest rate equal to
the Base Rate from time to time in effect plus two and one-half percent
(2-1/2%), such rate to be
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computed on the basis of a year of 365 or 366 days, as the case may be,
and actual days elapsed (including the first day but excluding the last
day) during the period for which payable, but in no event shall such
rate exceed the Highest Lawful Rate.
"Distributive Share" shall mean, with respect to each
Partnership, the distributive share of the Borrower of profits and
proceeds pursuant to the applicable Partnership Agreement, and in the
event that the amount of such distributive share varies depending on
events or circumstances, the minimum distributive share of the
Borrower.
"Dollars" and "$" shall mean dollars in lawful currency of the
United States of America.
"Environmental Complaint" shall mean any written complaint,
order, directive, claim, citation, notice of investigation or other
notice by any Governmental Authority or any other Person with respect
to (a) air emissions, (b) spills, releases, or discharges to soils or
any improvements located thereon, surface water, groundwater or the
sewer, septic system or waste treatment, storage or disposal systems
servicing any Property of any of the Borrower, its Subsidiaries or the
Partnerships, (c) solid or liquid waste disposal, (d) the use,
generation, storage, transportation or disposal of any Hazardous
Substance, or (e) other environmental, health or safety matters
affecting any Property of any of the Borrower, its Subsidiaries or the
Partnerships or the business conducted thereon.
"Environmental Laws" shall mean (a) the following federal laws
as they may be cited, referenced, and amended from time to time: the
Clean Air Act, the Clean Water Act, the Comprehensive Environmental
Response, Compensation and Liability Act, the Endangered Species Act,
the Hazardous Materials Transportation Act of 1986, the Occupational
Safety and Health Act, the Oil Pollution Act of 1990, the Resource
Conservation and Recovery Act of 1976, the Safe Drinking Water Act, the
Superfund Amendments and Reauthorization Act, and the Toxic Substances
Control Act; (b) any and all equivalent environmental statutes of any
state in which Property of the Borrower is situated, as they may be
cited, referenced and amended from time to time; (c) any rules or
regulations promulgated under or adopted pursuant to the above federal
and state laws; and (d) any other equivalent federal, state, or local
statute or any requirement, rule, regulation, code, ordinance, or order
adopted pursuant thereto, including those relating to the generation,
transportation, treatment, storage, recycling, disposal, handling, or
release of Hazardous Substances.
"ERISA" shall mean the Employee Retirement Income Security Act
of 1974, as amended from time to time, and the regulations thereunder
and interpretations thereof.
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"Event of Default" shall mean any of the events specified in
Section 7.1.
"Facility Amount" shall mean, for each Lender, the amount set
forth opposite the name of such Lender on Exhibit V under the caption
"Facility Amounts," as modified from time to time to reflect
assignments permitted by Section 9.1 or otherwise pursuant to the terms
hereof.
"Federal Funds Rate" shall mean, for any day, the rate per
annum (rounded upwards, if necessary, to the nearest 1/100 of 1%) equal
to the weighted average of the rates on overnight federal funds
transactions with members of the Federal Reserve System arranged by
federal funds brokers on such day, as published by the Federal Reserve
Bank of Dallas, Texas, on the Business Day next succeeding such day,
provided that (a) if the day for which such rate is to be determined is
not a Business Day, the Federal Funds Rate for such day shall be such
rate on such transactions on the next preceding Business Day as so
published on the next succeeding Business Day, and (b) if such rate is
not so published for any day, the Federal Funds Rate for such day shall
be the average rate charged to the Lender serving as the Administrative
Agent on such day on such transactions as determined by the
Administrative Agent.
"Final Maturity" shall mean August 18, 2002.
"Financial Statements" shall mean statements of the financial
condition as at the point in time and for the period indicated and
consisting of at least a balance sheet and related statements of
operations, common stock and other stockholders' or partners' equity,
and cash flows and, when required by applicable provisions of this
Agreement to be audited, accompanied by the unqualified certification
of a nationally-recognized firm of independent certified public
accountants or other independent certified public accountants
acceptable to the Administrative Agent and footnotes to any of the
foregoing, all of which, unless otherwise indicated, shall be prepared
in accordance with GAAP consistently applied and in comparative form
with respect to the corresponding period of the preceding fiscal
period.
"Floating Rate" shall mean, as of any day, an interest rate
per annum equal to the greater of (a) the Base Rate for such day plus
the Applicable Margin or (b) the Federal Funds Rate for such day plus
one percent (1%), such rate to be computed, in either case, on the
basis of a year of 360 days and actual days elapsed (including the
first day but excluding the last day) during the period for which
payable, but in no event shall such rate exceed the Highest Lawful
Rate.
"Floating Rate Loan" shall mean any Loan and any portion of
the Loan Balance which the Borrower has requested, in the initial
Borrowing Request for such Loan or a subsequent Borrowing Request for
such portion of the Loan
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Balance, bear interest at the Floating Rate, or which pursuant to the
terms hereof are otherwise required to bear interest at the Floating
Rate.
"GAAP" shall mean generally accepted accounting principles
established by the Financial Accounting Standards Board or the American
Institute of Certified Public Accountants and in effect in the United
States from time to time.
"Governmental Authority" shall mean any nation, country,
commonwealth, territory, government, state, county, parish,
municipality or other political subdivision and any court, governmental
department or authority, commission, board, bureau, agency, arbitrator
or instrumentality thereof and any other entity exercising executive,
legislative, judicial, regulatory or administrative functions of or
pertaining to government.
"Hazardous Substances" shall mean flammables, explosives,
radioactive materials, hazardous wastes, asbestos or any material
containing asbestos, polychlorinated biphenyls (PCBs), toxic substances
or related materials, or any substances defined as "contaminants,"
"hazardous substances," "hazardous materials," "hazardous wastes" or
"toxic substances" under any Environmental Law now or hereafter enacted
or promulgated by any Governmental Authority.
"Hedging Agreement" shall mean (a) any interest rate or
currency swap, rate cap, rate floor, rate collar, forward agreement, or
other exchange or rate protection agreement or any option with respect
to any such transaction and (b) any swap agreement, cap, floor, collar,
exchange transaction, forward agreement, or other exchange or
protection agreement relating to hydrocarbons or any option with
respect to any such transaction.
"Hedging Obligations" shall mean the Indebtedness and
Obligations, now or hereafter arising, of the Borrower under any
Hedging Agreements with any Lender or any affiliate of any Lender.
"Highest Lawful Rate" shall mean, with respect to each Lender,
the maximum non-usurious interest rate, if any (or, if the context so
requires, an amount calculated at such rate), that at any time or from
time to time may be contracted for, taken, reserved, charged, or
received under laws applicable to such Lender, as such laws are
presently in effect or, to the extent allowed by applicable law, as
such laws may hereafter be in effect and which allow a higher maximum
non-usurious interest rate than such laws now allow.
"Indebtedness" shall mean, as to any Person, without
duplication, (a) all liabilities (excluding reserves for deferred
income taxes, deferred compensation liabilities, and other deferred
liabilities and credits) which in accordance with GAAP would be
included in determining total liabilities as shown on the liability
side of a balance sheet, (b) all obligations of such Person evidenced
by bonds,
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debentures, promissory notes, or similar evidences of indebtedness, (c)
all other indebtedness of such Person for borrowed money, and (d) all
obligations of others, to the extent any such obligation is secured by
a Lien on the assets of such Person (whether or not such Person has
assumed or become liable for the obligation secured by such Lien).
"Insolvency Proceeding" shall mean application (whether
voluntary or instituted by another Person) for or the consent to the
appointment of a receiver, trustee, conservator, custodian, or
liquidator of any Person or of all or a substantial part of the
Property of such Person, or the filing of a petition (whether voluntary
or instituted by another Person) commencing a case under Title 11 of
the United States Code, seeking liquidation, reorganization, or
rearrangement or taking advantage of any bankruptcy, insolvency,
debtor's relief, or other similar law of the United States, the State
of Texas, or any other jurisdiction.
"Interest Period" shall mean, subject to the limitations set
forth in Section , with respect to any LIBO Rate Loan, a period
commencing on the date such Loan is made or converted from a Loan of
another type pursuant to this Agreement or the last day of the next
preceding Interest Period with respect to such Loan and ending on the
numerically corresponding day in the calendar month that is one, two,
three, or, subject to availability, six months thereafter, as the
Borrower may request in the Borrowing Request for such Loan.
"Investment" shall mean, as to any Person, any stock, bond,
note or other evidence of Indebtedness or any other security (other
than current trade and customer accounts) of, investment or partnership
interest in or loan to, such Person.
"L/C Exposure" shall mean, at any time, the maximum amount
available to be drawn under outstanding Letters of Credit at such time.
"Letter of Credit" shall mean each standby letter of credit
issued for the account of the Borrower pursuant to this Agreement.
"Letter of Credit Application" shall mean the standard letter
of credit application employed by the Administrative Agent, as the
issuer of the Letters of Credit, from time to time in connection with
letters of credit.
"Letter of Credit Payment" shall mean any payment made by the
Lenders or the Administrative Agent on behalf of the Lenders under a
Letter of Credit, to the extent that such payment has not been repaid
by the Borrower.
"LIBO Rate" means, with respect to a LIBO Rate Loan for the
relevant Interest Period, the applicable British Banker's Association
Interest Settlement
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Rate for deposits in U.S. dollars appearing on Reuters Screen FRBD as
of 11:00 a.m. (London time) two Business Days prior to the first day of
such Interest Period, and having a maturity equal to such Interest
Period, provided that, (i) if Reuters Screen FRBD is not available to
the Lender for any reason, the applicable LIBO rate for the relevant
Interest Period shall instead be the applicable British Bankers'
Association Interest Settlement Rate for deposits in U.S. dollars as
reported by any other generally recognized financial information
service as of 11:00 a.m. (London time) two Business Days prior to the
first day of such Interest Period, and having a maturity equal to such
Interest Period, and (ii) if no such British Bankers' Association
Interest Settlement Rate is available to the Lender, the applicable
LIBO Rate for the relevant Interest Period shall instead be the rate
determined by the Lender to be the rate at which Lender or one of its
Affiliate banks offers to place deposits in U.S. dollars with
first-class banks in the London interbank market at approximately 11:00
a.m. (London time) two Business Day prior to the first day of such
Interest Period, in the approximate amount of Bank One's relevant LIBO
Rate Loan and having a maturity equal to such Interest Period.
"LIBO Rate Loan" shall mean any Loan and any portion of the
Loan Balance which the Borrower has requested, in the initial or a
subsequent Borrowing Request for such Loan, bear interest at the
Adjusted LIBO Rate and which are permitted by the terms hereof to bear
interest at the Adjusted LIBO Rate.
"Lien" shall mean any interest in Property securing an
obligation owed to, or a claim by, a Person other than the owner of the
Property, whether such interest is based on common law, statute, or
contract, and including the lien or security interest arising from a
mortgage, encumbrance, pledge, security agreement, conditional sale or
trust receipt, or a lease, consignment or bailment for security
purposes and reservations, exceptions, encroachments, easements, rights
of way, covenants, conditions, restrictions, leases and other title
exceptions and encumbrances affecting Property which secure an
obligation owed to, or a claim by, a Person other than the owner of
such Property (for purposes of this Agreement, any of the Borrower, its
Subsidiaries or the Partnerships shall be deemed to be the owner of any
Property which it has acquired or holds subject to a conditional sale
agreement, financing lease or other arrangement pursuant to which title
to the Property has been retained by or vested in some other Person for
security purposes), and the filing or recording of any financing
statement or other security instrument in any public office.
"Limitation Period" shall mean, with respect to any Lender,
any period while any amount remains owing on any Note payable to such
Lender and during which interest on such amount calculated at the
applicable interest rate plus any fees or other sums payable to such
Lender under any Loan Document and deemed to be interest under
applicable law, would exceed the amount of interest which would accrue
at the Highest Lawful Rate.
"Loan" shall mean any advance to or for the benefit of the
Borrower pursuant to this Agreement and any payment made by the
Administrative Agent or any Lender under a Letter of Credit.
"Loan Balance" shall mean, at any time, the aggregate
outstanding principal balance of the Notes at such time.
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"Loan Documents" shall mean this Agreement, the Notes, the
Letters of Credit, the Letter of Credit Applications, the Security
Instruments, and all other documents, instruments and agreements now or
hereafter delivered pursuant to the terms of or in connection with this
Agreement, the Notes, the Letters of Credit, or the Letter of Credit
Applications, and all renewals, extensions, amendments, supplements and
restatements thereof.
"Material Adverse Effect" shall mean any material and adverse
effect on (a) the assets, liabilities, financial condition, business,
operations or prospects of the Borrower, or the Borrower and its
Subsidiaries on a consolidated basis, or the Partnerships taken as a
whole, from those reflected in the Financial Statements dated December
31, 1997, furnished to the Lenders or from the facts represented or
warranted in this Agreement or any other Loan Document, (b) the ability
of the Borrower individually, or the Borrower and its Subsidiaries on a
consolidated basis, or the Partnerships taken as a whole, to carry out
its or their business as at the date of this Agreement conducted, or
(c) the ability of the Borrower to meet its obligations generally, or
to meet its obligations under the Loan Documents on a timely basis as
provided therein.
"Maximum Facility Amount" shall mean the sum of the Facility Amounts of
all Lenders.
"Mortgaged Properties" shall mean all Oil and Gas Properties
of the Borrower subject to a perfected first-priority Lien in favor of
the Lender, subject only to Permitted Liens, as security for the
Obligations.
"Multi-employer Plan" shall mean a Plan which is a
multi-employer plan as defined in Section 4001(a)(3) of ERISA.
"Net Income" shall mean, for any period, the net income of the
Borrower and its Subsidiaries on a consolidated basis for such period,
determined in accordance with GAAP.
"Notes" shall mean, collectively, each of the promissory notes
of the Borrower payable to a Lender in the amount of the Facility
Amount of such Lender in the form attached hereto as Exhibit I, with
appropriate insertions, together with all renewals, extensions for any
period, increases, and rearrangements thereof.
"Notice of Termination" shall have the meaning assigned to such term in
Section 2.23.
"Obligations" shall mean, without duplication, (a) all
Indebtedness evidenced by the Notes, (b) the obligation of the Borrower
to provide to or reimburse the Administrative Agent or the Lenders, as
the case may be, for amounts payable, paid, or incurred with respect to
Letters of Credit, (c) the undrawn, unexpired amount of all outstanding
Letters of Credit, (d) the obligation of the Borrower for the payment
of fees and expenses pursuant to the Loan Documents, (f) the Hedging
Obligations, and (g) all other obligations and liabilities of the
Borrower to the Administrative Agent and the Lenders, now existing or
hereafter incurred, under, arising out of or in connection with any
Loan Document, and to the extent that any of the foregoing includes or
refers to the payment of amounts deemed or constituting interest, only
so much thereof as shall have accrued, been earned and which remains
unpaid at each relevant time of determination.
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"Oil and Gas Property" shall mean fee, leasehold or other
interests in or under mineral estates or oil, gas and other liquid or
gaseous hydrocarbon leases with respect to Properties situated in the
United States or offshore from any State of the United States,
including overriding royalty and royalty interests, leasehold estate
interests, net profits interests, production payment interests and
mineral fee interests, together with contracts executed in connection
therewith and all tenements, hereditaments, appurtenances and
Properties appertaining, belonging, affixed or incidental thereto.
"Partners" shall mean all present and future general and limited
partners of the Partnerships.
"Partnerships" shall mean all partnerships, including joint
ventures, in which the Borrower is a limited or general partner,
including the general and limited drilling partnerships and income
funds now or hereafter existing in connection with the exploration and
drilling or property acquisition and ownership programs of the Borrower
and with respect to which the Borrower is a general partner or the
managing general partner, and with respect to which a Distributive
Share is included in the Borrowing Base.
"Partnership Agreement" shall mean the partnership agreement
of any Partnership, as any such agreement may be amended, restated or
supplemented from time to time.
"Percentage Share" shall mean, as to any Lender, a fraction,
expressed as a percentage, the numerator of which is the Facility
Amount of such Lender and the denominator of which is the Maximum
Facility Amount.
"Permitted Liens" shall mean (a) Liens for taxes, assessments
or other governmental charges or levies not yet due or which (if
foreclosure, distraint, sale, or other similar proceedings shall not
have been initiated) are being contested in good faith by appropriate
proceedings diligently conducted, if such reserve as may be required by
GAAP shall have been made therefor; (b) Liens in connection with
workers' compensation, unemployment insurance or other social security
(other than Liens created by Section 4068 of ERISA), old age pension or
public liability obligations which are not yet due or which are being
contested in good faith by appropriate proceedings diligently
conducted, if such reserve as may be required by GAAP shall have been
made therefor; (c) Liens in favor of vendors, carriers, warehousemen,
repairmen, mechanics, workers, or materialmen, and construction or
other similar Liens arising by operation of law in the ordinary course
of business or incident to the construction or improvement of any
Property in respect of obligations which are not yet due or which are
being contested in good faith by appropriate proceedings diligently
conducted, if such reserve as may be required by GAAP shall have been
made therefor; (d) Liens securing the purchase price of equipment of
the Borrower, provided that (i) such Liens shall not extend to or cover
any other Property of the Borrower, and (ii) the aggregate unpaid
purchase price secured by all such Liens shall not exceed $5,000,000;
(e) Liens on assets, excluding Oil and Gas Properties and production
and proceeds therefrom, in an aggregate amount not to exceed
$1,000,000; (f) Liens to operators and non-operators under joint
operating agreements arising in the ordinary course of business to
secure amounts owing to operators, which amounts are not yet due or are
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being contested in good faith by appropriate proceedings diligently
conducted; (g) Liens under production sales agreements, division
orders, operating agreements and other agreements customary in the oil
and gas industry for processing, producing, and selling hydrocarbons
securing obligations not constituting Indebtedness and provided that
such Liens do not secure obligations to deliver hydrocarbons at some
future date without receiving full payment therefor within 90 days of
delivery; (h) the currently existing Liens described on Exhibit VI
under the heading "Liens"; easements, rights of way, restrictions and
other similar encumbrances, and minor defects in the chain of title
which are customarily accepted in the oil and gas financing industry,
none of which interfere with the ordinary conduct of the business of
any of the Borrower, its Subsidiaries or the Partnerships or materially
detract from the value or use of the Property to which they apply; (i)
Liens in favor of the Administrative Agent for the benefit of the
Lenders; and (j) any lien reserved in an Oil and Gas lease by the
Lessor to secure royalty payments under such lease without limit as to
amount.
"Person" shall mean an individual, corporation, partnership,
joint venture, association, joint stock company, trust, unincorporated
organization, Governmental Authority, or any other form of entity.
"Plan" shall mean, at any time, any employee benefit plan
which is covered by ERISA and in respect of which the Borrower or any
Commonly Controlled Entity is (or, if such plan were terminated at such
time, would under Section 4069 of ERISA be deemed to be) an "employer"
as defined in Section 3(5) of ERISA.
"Principal Office" shall mean the principal office of the
Administrative Agent in Houston, Texas, presently located at 910 Travis
Street.
"Property" shall mean any interest in any kind of property or
asset, whether real, personal, or mixed, tangible or intangible.
"Regulation D" shall mean Regulation D of the Board of
Governors of the Federal Reserve System (or any successor), as amended
or supplemented from time to time.
"Regulatory Change" shall mean, with respect to any Lender,
the passage, adoption, institution, or modification of any federal,
state, local, or foreign Requirement of Law (including Regulation D),
or any interpretation, directive, or request (whether or not having the
force of law) of any Governmental Authority or monetary authority
charged with the enforcement, interpretation, or administration
thereof, occurring after the Closing Date and applying to a class of
lenders including such Lender or its Applicable Lending Office.
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"Release of Hazardous Substances" shall mean any emission,
spill, release, disposal or discharge, except in accordance with a
valid permit, license, certificate or approval of the relevant
Governmental Authority, of any reportable quantity of Hazardous
Substance into or upon (a) the air, (b) soils or any improvements
located thereon, (c) surface water or groundwater, or (d) the sewer,
septic system or waste treatment, storage or disposal system servicing
any Property of any of the Borrower, its Subsidiaries or the
Partnerships.
"Replacement Lenders" shall have the meaning assigned to such term in
Section 2.23.
"Required Lenders" shall mean such Lenders as necessary to
make the Percentage Share for all of such Lenders total at least
66-2/3%.
"Required Payment" shall have the meaning assigned to such term in
Section 2.8.
"Requirement of Law" shall mean, as to any Person, any
applicable law, treaty, ordinance, order, judgment, rule, decree,
regulation, or determination of an arbitrator, court, or other
Governmental Authority, including rules, regulations, orders, and
requirements for permits, licenses, registrations, approvals, or
authorizations, in each case as such now exist or may be hereafter
amended and are applicable to or binding upon such Person or any of its
Property or to which such Person or any of its Property is subject.
"Reserve Report" shall mean each report provided by the
Borrower pursuant to Section 5.5.
"Reserve Requirement" shall mean, for any Interest Period for
any LIBO Rate Loan, the average maximum rate at which reserves
(including any marginal, supplemental, or emergency reserves) are
required to be maintained during such Interest Period under Regulation
D by member banks of the Federal Reserve System in Dallas, Texas, with
deposits exceeding one billion Dollars against "Eurocurrency
liabilities" (as such term is used in Regulation D) and any other
reserves required by reason of any Regulatory Change to be maintained
by such member banks against (a) any category of liabilities which
includes deposits by reference to which the LIBO Rate is to be
determined as provided herein in the definition of the term "LIBO Rate"
or (b) any category of extensions of credit or other assets which
include a LIBO Rate Loan.
"Responsible Officer" shall mean any Vice President, the
Treasurer or other authorized representative of the Borrower as
designated from time to time pursuant to written designation by the
Borrower.
"Security Instruments" shall mean the security instruments
executed and delivered in satisfaction of the condition set forth in
Section 3.1(f), and all other documents and instruments at any time
executed as security for all or any portion of the Obligations, as such
instruments may be amended, restated, or supplemented from time to
time.
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"Senior Subordinated Debt" shall mean the Indebtedness of
Borrower under the Senior Subordinated Notes in the amount up to
$150,000,000 due 2009, issued or to be issued in accordance with the
terms of the Prospectus Supplement draft dated July 6, 1999, relating
thereto.
"Subordinated Debt" shall mean the Indebtedness of the
Borrower under the 6.25% Convertible Subordinated Notes due November
15, 2006, in the maximum original principal amount of $115,000,000.
"Subsidiary" shall mean, as to any Person, a corporation of
which shares of stock having ordinary voting power (other than stock
having such power only by reason of the happening of a contingency) to
elect a majority of the board of directors or other managers of such
corporation are at the time owned, or the management of which is
otherwise controlled, directly or indirectly through one or more
intermediaries, or both, by such Person.
"Superfund Site" shall mean those sites listed on the
Environmental Protection Agency National Priority List and eligible for
remedial action, or any comparable state registries or list in any
state of the United States.
"Tangible Net Worth" shall mean (a) total assets, as would be
reflected on a balance sheet of the Borrower and its subsidiaries
prepared on a consolidated basis and in accordance with GAAP, exclusive
of experimental or organization expenses, franchises, licenses,
permits, and other intangible assets, treasury stock, unamortized
underwriters' debt discount and expenses, and goodwill minus (b) total
liabilities, as would be reflected on a balance sheet of the Borrower
prepared on a consolidated basis and in accordance with GAAP.
"Taxes" shall have the meaning assigned to such term in
Section 2.22.
"Terminated Lender" shall have the meaning assigned to such
term in Section 2.23.
"Year 2000 Compliance" shall mean, with regard to any entity,
that all software, embedded microchips, and other processing
capabilities utilized by, and material to the business operations or
financial condition of, such entity are able to interpret and
manipulate data on and involving all calendar dates correctly and
without causing any abnormal ending scenario, including in relation to
dates in and after the year 2000.
"Termination Date" shall have the meaning assigned to such
term in Section 2.23.
1.3 Undefined Financial Accounting Terms . Undefined financial accounting terms
used in this Agreement shall be defined according to GAAP at the time in
effect.
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1.4 References . References in this Agreement to Article, Section, or Exhibit
numbers shall be to Articles, Sections, and Exhibits of this Agreement,
unless expressly stated to the contrary. References in this Agreement to
"hereby," "herein," "hereinabove," "hereinafter," "hereinbelow," "hereof,"
"hereunder," and words of similar import shall be to this Agreement in its
entirety and not only to the particular Article, Section or Exhibit in
which such reference appears. References in this Agreement to "includes" or
"including" shall mean "includes, without limitation," or "including,
without limitation," as the case may be. References in this Agreement to
statutes, sections, or regulations are to be construed as including all
statutory or regulatory provisions consolidating, amending, replacing,
succeeding or supplementing such statutes, sections, or regulations.
1.5 Articles and Sections . This Agreement, for convenience only, has been
divided into Articles and Sections; and it is understood that the rights
and other legal relations of the parties hereto shall be determined from
this instrument as an entirety and without regard to the aforesaid division
into Articles and Sections and without regard to headings prefixed to such
Articles or Sections.
1.6 Number and Gender . Whenever the context requires, reference herein made to
the single number shall be understood to include the plural; and likewise,
the plural shall be understood to include the singular. Definitions of
terms defined in the singular or plural shall be equally applicable to the
plural or singular, as the case may be, unless otherwise indicated. Words
denoting sex shall be construed to include the masculine, feminine and
neuter, when such construction is appropriate; and specific enumeration
shall not exclude the general but shall be construed as cumulative.
1.7 Incorporation of Exhibits . The Exhibits attached to this Agreement are
incorporated herein and shall be considered a part of this Agreement for
all purposes.
ARTICLE 2
TERMS OF THE FACILITY
2.1 Revolving Line of Credit . Upon the terms and conditions and relying on the
representations and warranties contained in this Agreement, each Lender
severally agrees to make Loans during the Commitment Period to or for the
benefit of the Borrower in an aggregate principal amount not to exceed at any
time outstanding the lesser of the Facility Amount of such Lender or the
Percentage Share of such Lender of the Borrowing Base then in effect; provided,
however, that (i) the Loan Balance plus the L/C Exposure shall not exceed at any
time the lesser of the Maximum Facility Amount or the Borrowing Base then in
effect, and (ii) the sum of the outstanding principal balance of all Loans by
any Lender plus the Percentage Share of such Lender of the L/C Exposure shall
not exceed at any time an amount equal to the Percentage Share of such Lender
multiplied by the lesser of the Maximum Facility Amount or the Borrowing Base
then in effect. Loans shall be made from time to time on any Business Day
designated by the Borrower in its Borrowing Request.
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(b) Subject to the terms of this Agreement, during the Commitment Period, the
Borrower may borrow, repay, and reborrow and convert Loans of one type or with
one Interest Period into Loans of another type or with a different Interest
Period. Except for prepayments made pursuant to Section 2.12, each borrowing,
conversion, and prepayment of principal of Loans shall be in an amount at least
equal to $100,000 and multiples of $100,000. Each borrowing, prepayment, or
conversion of or into a Loan of a different type or, in the case of a LIBO Rate
Loan, having a different Interest Period, shall be deemed a separate borrowing,
conversion, and prepayment for purposes of the foregoing, one for each type of
Loan or Interest Period. Anything in this Agreement to the contrary
notwithstanding, the aggregate principal amount of LIBO Rate Loans having the
same Interest Period shall be at least equal to $1,000,000 with multiples of
$100,000; and if any LIBO Rate Loan would otherwise be in a lesser principal
amount for any period, such Loan shall be a Floating Rate Loan during such
period.
(c) Not later than 2:00 p.m., Central Standard or Daylight Savings Time, as the
case may be, on the date specified for each borrowing, each Lender shall make
available to the Administrative Agent an amount equal to the Percentage Share of
such Lender of the borrowing to be made on such date, at an account designated
by the Administrative Agent, for the account of the Borrower. The amount so
received by the Administrative Agent shall, subject to the terms and conditions
hereof, be made available to the Borrower in immediately available funds at the
Principal Office. All Loans by each Lender shall be maintained at the Applicable
Lending Office of such Lender and shall be evidenced by the Note of such Lender.
(d) The failure of any Lender to make any Loan required to be made by it
hereunder shall not relieve any other Lender of its obligation to make any Loan
required to be made by it, and no Lender shall be responsible for the failure of
any other Lender to make any Loan.
2.2 Letter of Credit Facility . (a)Upon the terms and conditions and relying on
the representations and warranties contained in this Agreement, the
Administrative Agent, as issuing bank for the Lenders, agrees, from the date of
this Agreement until the date which is 30 days prior to the Commitment
Termination Date, to issue, on behalf of the Lenders in their respective
Percentage Shares, Letters of Credit for the account of the Borrower and to
renew and extend such Letters of Credit. Letters of Credit shall be issued,
renewed, or extended from time to time on any Business Day designated by the
Borrower following the receipt in accordance with the terms hereof by the
Administrative Agent of the written (or oral, confirmed promptly in writing)
request by a Responsible Officer of the Borrower therefor and a Letter of Credit
Application. Letters of Credit shall be issued in such amounts as the Borrower
may request; provided, however, that (i) no Letter of Credit shall have an
expiration date which is more than 365 days after the issuance thereof or
subsequent to five days prior to the Commitment Termination Date, (ii) the Loan
Balance plus the L/C Exposure shall not exceed at any time the lesser of the
Maximum Facility Amount or the Borrowing Base, and (iii) the L/C Exposure shall
not exceed at any time $20,000,000.
(b) Prior to any Letter of Credit Payment in respect of any Letter of Credit,
each Lender shall be deemed to be a participant through the Administrative Agent
with respect to the relevant Letter of Credit in the obligation of the
Administrative Agent, as the issuer of such Letter of Credit, in an amount equal
to the Percentage Share of such Lender of the maximum amount which is or at any
time may become available to be drawn thereunder. Upon delivery by
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such Lender of funds requested pursuant to Section 2.2(c), such Lender shall be
treated as having purchased a participating interest in an amount equal to such
funds delivered by such Lender to the Administrative Agent in the obligation of
the Borrower to reimburse the Administrative Agent, as the issuer of such Letter
of Credit, for any amounts payable, paid, or incurred by the Administrative
Agent, as the issuer of such Letter of Credit, with respect to such Letter of
Credit.
(c) Each Lender shall be unconditionally and irrevocably liable,
without regard to the occurrence of any Default or Event of Default, to the
extent of the Percentage Share of such Lender at the time of issuance of each
Letter of Credit, to reimburse, on demand, the Administrative Agent, as the
issuer of such Letter of Credit, for the amount of each Letter of Credit Payment
under such Letter of Credit. Each Letter of Credit Payment shall be deemed to be
a Floating Rate Loan by each Lender to the extent of funds delivered by such
Lender to the Administrative Agent with respect to such Letter of Credit Payment
and shall to such extent be deemed a Floating Rate Loan under and shall be
evidenced by the Note of such Lender and shall be payable by the Borrower upon
demand by the Administrative Agent.
(d) EACH LENDER AGREES TO INDEMNIFY THE ADMINISTRATIVE AGENT, AS THE ISSUER OF
EACH LETTER OF CREDIT, AND THE OFFICERS, DIRECTORS, EMPLOYEES, AGENTS,
ATTORNEYS-IN-FACT AND AFFILIATES OF THE ADMINISTRATIVE AGENT (TO THE EXTENT NOT
REIMBURSED BY THE BORROWER AND WITHOUT LIMITING THE OBLIGATION OF THE BORROWER
TO DO SO), RATABLY ACCORDING TO THE PERCENTAGE SHARE OF SUCH LENDER AT THE TIME
OF ISSUANCE OF SUCH LETTER OF CREDIT, FROM AND AGAINST ANY AND ALL LIABILITIES,
CLAIMS, OBLIGATIONS, LOSSES, DAMAGES, PENALTIES, ACTIONS, JUDGMENTS, SUITS,
COSTS, EXPENSES AND DISBURSEMENTS OF ANY KIND WHATSOEVER WHICH MAY AT ANY TIME
(INCLUDING ANY TIME FOLLOWING THE PAYMENT AND PERFORMANCE OF ALL OBLIGATIONS AND
THE TERMINATION OF THIS AGREEMENT) BE IMPOSED ON, INCURRED BY OR ASSERTED
AGAINST THE ADMINISTRATIVE AGENT AS THE ISSUER OF SUCH LETTER OF CREDIT OR ANY
OF ITS OFFICERS, DIRECTORS, EMPLOYEES, AGENTS, ATTORNEYS-IN-FACT OR AFFILIATES
IN ANY WAY RELATING TO OR ARISING OUT OF THIS AGREEMENT OR SUCH LETTER OF CREDIT
OR ANY ACTION TAKEN OR OMITTED BY THE ADMINISTRATIVE AGENT AS THE ISSUER OF SUCH
LETTER OF CREDIT OR ANY OF ITS OFFICERS, DIRECTORS, EMPLOYEES, AGENTS,
ATTORNEYS-IN-FACT OR AFFILIATES UNDER OR IN CONNECTION WITH ANY OF THE
FOREGOING, INCLUDING ANY LIABILITIES, CLAIMS, OBLIGATIONS, LOSSES, DAMAGES,
PENALTIES, ACTIONS, JUDGMENTS, SUITS, COSTS, EXPENSES AND DISBURSEMENTS IMPOSED,
INCURRED OR ASSERTED AS A RESULT OF THE NEGLIGENCE, WHETHER SOLE OR CONCURRENT,
OF THE ADMINISTRATIVE AGENT AS THE ISSUER OF SUCH LETTER OF CREDIT OR ANY OF ITS
OFFICERS, DIRECTORS, EMPLOYEES, AGENTS, ATTORNEYS-IN-FACT OR AFFILIATES;
PROVIDED THAT NO LENDER (OTHER THAN THE ADMINISTRATIVE AGENT AS THE ISSUER OF A
LETTER OF CREDIT) SHALL BE LIABLE FOR THE PAYMENT OF ANY PORTION OF SUCH
LIABILITIES, OBLIGATIONS, LOSSES, DAMAGES, PENALTIES, ACTIONS, JUDGMENTS, SUITS,
COSTS, EXPENSES OR DISBURSEMENTS RESULTING SOLELY FROM THE GROSS NEGLIGENCE OR
WILLFUL MISCONDUCT OF THE ADMINISTRATIVE AGENT AS THE ISSUER OF A LETTER OF
CREDIT. THE AGREEMENTS IN THIS SECTION SHALL SURVIVE THE PAYMENT AND PERFORMANCE
OF ALL OBLIGATIONS AND THE TERMINATION OF THIS AGREEMENT.
2.3 Limitations on Interest Periods . Each Interest Period selected by the
Borrower (a) which commences on the last Business Day of a calendar month (or
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any day for which there is no numerically corresponding day in the appropriate
subsequent calendar month) shall end on the last Business Day of the appropriate
subsequent calendar month, (b) which would otherwise end on a day which is not a
Business Day shall end on the next succeeding Business Day (or, if such next
succeeding Business Day falls in the next succeeding calendar month, on the next
preceding Business Day), (c) which would otherwise end after Final Maturity
shall end on Final Maturity, and (d) shall have a duration of not less than one
month and, if any Interest Period would otherwise be a shorter period, the
relevant Loan shall be a Floating Rate Loan during such period.
2.4 Limitation on Types of Loans . Anything herein to the contrary
notwithstanding, no more than ten separate Loans, including eight LIBO Rate
Loans, shall be outstanding at any one time, with, for purposes of this Section,
all Floating Rate Loans constituting one Loan, and all LIBO Rate Loans for the
same Interest Period constituting one Loan. Anything herein to the contrary
notwithstanding, if, on or prior to the determination of any interest rate for
any LIBO Rate Loan for any Interest Period therefor:
(a) the Administrative Agent determines (which determination shall be
conclusive, absent manifest error) that quotations of interest rates
for the deposits referred to in the definition of "LIBO Rate" in
Section 1.2 are not being provided in the relevant amounts or for the
relevant maturities for purposes of determining the rate of interest
for such Loan as provided in this Agreement; or
(b) the Administrative Agent determines (which determination shall be
conclusive, absent manifest error) that the rates of interest referred
to in the definition of "LIBO Rate" in Section 1.2 upon the basis of
which the rate of interest for such Loan for such Interest Period is to
be determined do not adequately cover the cost to the Lenders of making
or maintaining such Loan for such Interest Period,
then the Administrative Agent shall give the Borrower and the Lenders prompt
notice thereof; and so long as such condition remains in effect, the Lenders
shall be under no obligation to make LIBO Rate Loans or to convert Floating Rate
Loans into LIBO Rate Loans, and the Borrower shall, on the last day of the then
current Interest Period for each outstanding LIBO Rate Loan, either prepay such
LIBO Rate Loan or convert such Loan into a Floating Rate Loan in accordance with
Section 2.13.
2.5 Use of Loan Proceeds and Letters of Credit . Proceeds of all Loans shall be
used to finance the exploration, development and/or acquisition of Oil and Gas
Properties and for any corporate purpose of the Borrower not prohibited under
any Loan Document. Letters of Credit shall be obtained for any business activity
of the Borrower not prohibited under any Loan Document; provided, however,
Letters of Credit shall not be obtained to support Indebtedness to any Person
not a Lender or in lieu or in support of stay or appeal bonds in excess of
$1,000,000.
2.6 Interest . Subject to the terms of this Agreement (including Section ),
interest on the Loans shall accrue and be payable at a rate per annum equal to
the Floating Rate for each Floating Rate Loan and the Adjusted LIBO Rate for
each LIBO Rate Loan. Notwithstanding the foregoing, interest on past-due
principal and, to the extent permitted by applicable law, past-due interest,
shall accrue at the Default Rate and shall be payable upon demand by the
Administrative Agent at any time as to all or any portion of such interest. In
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the event that the Borrower fails to select the duration of any Interest Period
for any LIBO Rate Loan within the time period and otherwise as provided herein,
such Loan (if outstanding as a LIBO Rate Loan) will be automatically converted
into a Floating Rate Loan on the last day of the then current Interest Period
for such Loan or (if outstanding as a Floating Rate Loan) will remain as, or (if
not then outstanding) will be made as, a Floating Rate Loan. Interest provided
for herein shall be calculated on unpaid sums actually advanced and outstanding
pursuant to the terms of this Agreement and only for the period from the date or
dates of such advances until repayment.
2.7 Repayment of Loans and Interest . Accrued and unpaid interest on outstanding
Floating Rate Loans shall be due and payable monthly commencing April 1, 2000,
and continuing on the first day of each calendar month thereafter while any
Floating Rate Loan remains outstanding, the payment in each instance to be the
amount of interest which has accrued and remains unpaid with respect to Floating
Rate Loans. Accrued and unpaid interest on each outstanding LIBO Rate Loan shall
be due and payable on the last day of the Interest Period for such LIBO Rate
Loan and, in the case of any Interest Period in excess of three months, on the
day of the third calendar month following the commencement of such Interest
Period corresponding to the day of the calendar month on which such Interest
Period commenced, the payment in each instance to be the amount of interest
which has accrued and remains unpaid in respect of the relevant Loan. The Loan
Balance, together with all accrued and unpaid interest thereon, shall be due and
payable at Final Maturity. At the time of making each payment hereunder or under
the Notes, the Borrower shall specify to the Administrative Agent the Loans or
other amounts payable by the Borrower hereunder to which such payment is to be
applied. In the event the Borrower fails to so specify, or if an Event of
Default has occurred and is continuing, the Administrative Agent may apply such
payment as it may elect in its discretion and in accordance with the terms
hereof.
2.8 General Terms . (a)Absent manifest error, the outstanding principal balance
of the Note of each Lender reflected in the records of such Lender shall be
deemed rebuttably presumptive evidence of the principal amount owing on such
Note; provided, however, the liability for payment of principal and interest
evidenced by the Note of each Lender shall be limited to principal amounts
actually advanced and outstanding pursuant to this Agreement and interest on
such amounts calculated in accordance with this Agreement.
(b) Unless the Administrative Agent shall have been notified by a Lender or the
Borrower prior to the date on which either of them is scheduled to make payment
to the Administrative Agent of (in the case of a Lender) the proceeds of a Loan
to be made by such Lender hereunder or (in the case of the Borrower) a payment
to the Administrative Agent for the account of one or more of the Lenders
hereunder (such payment being herein called the "Required Payment"), which
notice shall be effective upon receipt, that it does not intend to make the
Required Payment to the Administrative Agent, the Administrative Agent may
assume that the Required Payment has been made and, in reliance upon such
assumption, may (but shall not be required to) make the amount thereof available
to the intended recipient on such date. If such Lender or the Borrower, as the
case may be, has not in fact made the Required Payment to the Administrative
Agent, the recipient of such payment shall, on demand, repay to the
Administrative Agent for its account the amount so made available together with
interest thereon in respect of each day during the period commencing on the date
such amount was so made available by the Administrative Agent until the date the
Administrative Agent recovers such amount at a rate per annum equal to, in the
case of a Lender as recipient, the
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Federal Funds Rate or, in the case of the Borrower as recipient, the Floating
Rate.
2.9 Time, Place, and Method of Payments . (a) All payments required pursuant to
this Agreement or the Notes shall be made without set-off or counterclaim in
Dollars and in immediately available funds. All payments by the Borrower shall
be deemed received on the next Business Day following receipt if such receipt is
after 2:00 p.m., Central Standard or Daylight Savings Time, as the case may be,
on any Business Day, and shall be made to the Administrative Agent at the
Principal Office. Except as provided to the contrary herein, if the due date of
any payment hereunder or under any Note would otherwise fall on a day which is
not a Business Day, such date shall be extended to the next succeeding Business
Day, and interest shall be payable for any principal so extended for the period
of such extension.
2.10 Pro Rata Treatment; Adjustments . Except to the extent
otherwise expressly provided herein, (i) each borrowing pursuant to this
Agreement shall be made from the Lenders pro rata in accordance with their
respective Percentage Shares, (ii) each payment by the Borrower of fees shall be
made for the account of the Lenders pro rata in accordance with their respective
Percentage Shares, (iii) each payment of principal of Loans shall be made for
the account of the Lenders pro rata in accordance with their respective shares
of the Loan Balance, and (iv) each payment of interest on Loans shall be made
for the account of the Lenders pro rata in accordance with their respective
shares of the aggregate amount of interest due and payable to the Lenders.
(b) The Administrative Agent shall distribute all payments with respect to the
Obligations to the Lenders promptly upon receipt in like funds as received. In
the event that any payments made hereunder by the Borrower at any particular
time are insufficient to satisfy in full the Obligations due and payable at such
time, such payments shall be applied (i) first, to fees and expenses due
pursuant to the terms of this Agreement or any other Loan Document, (ii) second,
to accrued interest, (iii) third, to the Loan Balance, and (iv) last, to any
other Obligations.
(c) If any Lender (for purposes of this Section, a "Benefitted Lender") shall at
any time receive any payment of all or part of its portion of the Obligations,
or receive any collateral or other Property in respect thereof (whether
voluntarily or involuntarily, by set-off, pursuant to events or proceedings of
the nature referred to in Sections 7.1 (e) or 7.1 (f), or otherwise) in an
amount greater than such Lender was entitled to receive pursuant to the terms
hereof, such Benefitted Lender shall purchase for cash from the other Lenders
such portion of the Obligations of such other Lenders, or shall provide such
other Lenders with the benefits of any such collateral or other Property or the
proceeds thereof, as shall be necessary to cause such Benefitted Lender to share
the excess payment or benefits of such collateral or other Property or proceeds
with each of the Lenders according to the terms hereof. If all or any portion of
such excess payment or benefits is thereafter recovered from such Benefitted
Lender, such purchase shall be rescinded and the purchase price and benefits
returned by such Lender, to the extent of such recovery, but without interest.
The Borrower agrees that each such Lender so purchasing a portion of the
Obligations of another Lender may exercise all rights of payment (including
rights of set-off) with respect to such portion as fully as if such Lender were
the direct holder of such portion. If any Lender ever receives, by voluntary
payment, exercise of rights of set-off or banker's lien, counterclaim,
cross-action or otherwise, any funds of the Borrower to be applied to the
Obligations, or receives any proceeds by
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realization on or with respect to any collateral or other Property, all such
funds and proceeds shall be forwarded immediately to the Administrative Agent
for distribution in accordance with the terms of this Agreement.
2.11 Borrowing Base Determinations. (a) The Borrowing Base as of November 1,
1999, is acknowledged by the Borrower and the Lenders to be $100,000,000 unless
and until the Borrowing Base has been redetermined pursuant to Section 2.11(b).
(b) The Borrowing Base shall be redetermined by the Administrative Agent with
the consent of the Required Lenders each May 1 and November 1, beginning May 1,
2000, during the term hereof on the basis of information supplied by the
Borrower in compliance with the provisions of this Agreement, including Reserve
Reports, and all other information available to the Lenders. In the event the
Required Lenders cannot agree on the Borrowing Base, the Borrowing Base shall be
set on the basis of the weighted (based on the Percentage Share of each Lender)
arithmetic average of the Borrowing Base as determined by each individual
Lender. However, the amount of the Borrowing Base cannot be increased at any
time without consent of 100% of the Lenders. In addition, the Administrative
Agent with the consent of the Required Lenders shall, in the normal course of
business following a request of the Borrower, redetermine the Borrowing Base;
provided, however, the Administrative Agent and the Lenders shall not be
obligated to respond to more than two such requests during any calendar year.
Notwithstanding the foregoing, the Required Lenders may at their discretion
redetermine the Borrowing Base at any time and from time to time, including,
without limitation, in connection with any sale or other transfer of Properties
by the Borrower pursuant to Section 6.4. To assist the Lenders in making a
redetermination of the Borrowing Base in connection with any sale or other
transfer of Properties by the Borrower pursuant to Section 6.4 and in making a
determination to make any such redetermination of the Borrowing Base, the
Borrower shall furnish to the Administrative Agent, contemporaneously with each
such sale or other transfer of Property, a breakout from the most recent Reserve
Report provided to the Lenders showing the value given to such Properties being
sold or transferred, together with any and all other information pertaining
thereto as the Administrative Agent may request.
(c) Upon each determination of the Borrowing Base, the Administrative Agent
shall notify the Borrower orally (confirming such notice promptly in writing) of
such determination, and the Borrowing Base so communicated to the Borrower shall
become effective upon such oral notification and shall remain in effect until
the next subsequent determination of the Borrowing Base.
(d) The Borrowing Base shall represent the determination by the Lenders, in
accordance with their customary lending procedures for evaluating oil and gas
reserves and other related assets at the time of determination, of the value,
for loan purposes, of the Distributive Shares and the Oil and Gas Properties of
the Borrower, subject, in the case of any increase in the Borrowing Base, to the
credit approval processes of the Lenders. Furthermore, the Borrower acknowledges
that the Lenders have no obligation to increase the Borrowing Base and may
reduce the Borrowing Base, in either case, at any time or as a result of any
circumstance and further acknowledges that the determination of the Borrowing
Base contains an equity cushion (market value in excess of loan value), which is
acknowledged by the Borrower to be essential for the adequate protection of the
Lenders.
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2.12 Mandatory Prepayments . If at any time the sum of the Loan Balance and the
L/C Exposure exceeds the lesser of the Maximum Facility Amount or the Borrowing
Base then in effect, the Borrower shall, within thirty days of notice from the
Administrative Agent of such occurrence, (a) prepay the amount of such excess
for application on the Loan Balance, (b) provide additional collateral, of
character and value satisfactory to the Lenders in their sole discretion, to
secure the Obligations by the execution and delivery to the Lenders of security
instruments in form and substance satisfactory to the Administrative Agent, or
(c) effect any combination of the alternatives described in clauses (a) and (b)
of this Section and acceptable to the Lenders in their sole discretion.. In the
event that a mandatory prepayment is required under this Section and the Loan
Balance is less than the amount required to be prepaid, the Borrower shall repay
the entire Loan Balance and, in accordance with the provisions of the relevant
Letter of Credit Applications executed by the Borrower or otherwise to the
satisfaction of the Administrative Agent, deposit with the Administrative Agent,
as additional collateral securing the Obligations, an amount of cash, in
immediately available funds, equal to the L/C Exposure minus the lesser of the
Maximum Facility Amount or the Borrowing Base. The cash deposited with the
Administrative Agent in satisfaction of the requirement provided in this Section
may be invested, at the sole discretion of the Administrative Agent and then
only at the express direction of the Borrower as to investment vehicle and
maturity (which shall be no later than the latest expiry date of any then
outstanding Letter of Credit), for the account of the Borrower in cash or cash
equivalent investments offered by or through the Lender serving as the
Administrative Agent.
2.13 Voluntary Prepayments and Conversions of Loans . Subject to applicable
provisions of this Agreement, the Borrower shall have the right at any time or
from time to time to prepay Loans and to convert Loans of one type or with one
Interest Period into Loans of another type or with a different Interest Period;
provided, however, that (a) the Borrower shall give the Administrative Agent
notice of each such prepayment or conversion of all or any portion of a LIBO
Rate Loan no less than three Business Days prior to prepayment or conversion,
(b) any LIBO Rate Loan may be prepaid or converted only on the last day of an
Interest Period for such Loan, (c) each prepayment shall be in an amount not
less than $500,000, (d) the Borrower shall pay all accrued and unpaid interest
on the amounts prepaid or converted, and (e) no such prepayment or conversion
shall serve to postpone the repayment when due of any Obligation.
2.14 Commitment Fee . To compensate the Lenders for making funds available under
this Agreement, the Borrower shall pay to the Administrative Agent for the
account of the Lenders in proportion to their respective Percentage Share, on
the first day of April, 2000, and on the first day of each third calendar month
thereafter and on the Commitment Termination Date, a fee in the amount as
determined by the ratio of (i) the sum of the Loan Balance and the L/C. Exposure
to (ii) the last calculated Borrowing Base, set forth below in basis points,
calculated on the basis of a year of 360 days and actual days elapsed (including
the first day but excluding the last day) on the average daily remainder, if
any, of (a) the lesser of the Maximum Facility Amount or the Borrowing Base
minus (b) the aggregate principal amount outstanding on the Notes plus the
amount of all outstanding Letters of Credit during the period from the date of
this Agreement or the previous calculation date, whichever is later, to the
relevant calculation date or the Commitment Termination Date, as the case may
be, as follows:
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<TABLE>
<CAPTION>
Ratio Commitment Fee
----- ---------------
<S> <C>
less than 50% 25.00 bps
equal to or greater
than 50% 37.50 bps
</TABLE>
2.15 Letter of Credit Fee . The Borrower shall pay to the Administrative Agent
for the account of the Lenders on the date of issuance or renewal of each Letter
of Credit, an issuing fee equal to the greater of $400 or the Applicable Margin
for LIBO Rate Loans, calculated on the basis of a year of 360 days and actual
days elapsed (including the first day but excluding the last day), on the face
amount of such Letter of Credit during the period for which such Letter of
Credit is issued or renewed. The Borrower also agrees to pay on demand to the
Administrative Agent for its own account as the issuer of the Letters of Credit
its customary letter of credit transactional fees and expenses, including
amendment fees, payable with respect to each Letter of Credit. The Borrower
shall pay to the Administrative Agent an additional fee of 0.125% per annum
calculated on a basis of 360 days and actual days elapsed (including the first
day but excluding the last day).
2.16 Loans to Satisfy Obligations of Borrower . The Lenders may, but shall not
be obligated to, make Loans for the benefit of the Borrower and apply proceeds
thereof to the satisfaction of any condition, warranty, representation, or
covenant of the Borrower contained in this Agreement or any other Loan Document.
Such Loans shall be evidenced by the Notes, shall bear interest at the Default
Rate and shall be payable upon demand.
2.17 Security Interest in Accounts; Right of Offset . As security for the
payment and performance of the Obligations, the Borrower hereby transfers,
assigns, and pledges to the Administrative Agent and each Lender (for the pro
rata benefit of all Lenders) and grants to the Administrative Agent and each
Lender (for the pro rata benefit of all Lenders) a security interest in all
funds of the Borrower now or hereafter or from time to time on deposit with the
Administrative Agent or such Lender, with such interest of the Administrative
Agent and the Lenders to be retransferred, reassigned, and/or released at the
reasonable expense of the Borrower upon payment in full and complete performance
of all Obligations and the termination of the Commitments. All remedies as
secured party or assignee of such funds shall be exercisable by the
Administrative Agent and the Lenders with the oral consent (confirmed promptly
in writing) of the Required Lenders upon the occurrence of any Event of Default,
regardless of whether the exercise of any such remedy would result in any
penalty or loss of interest or profit with respect to any withdrawal of funds
deposited in a time deposit account prior to the maturity thereof. Furthermore,
the Borrower hereby grants to the Administrative Agent and each Lender (for the
pro rata benefit of all Lenders) the right, exercisable at such time as any
Event of Default shall occur, of offset or banker's lien against all funds of
the Borrower now or hereafter or from time to time on deposit with the
Administrative Agent or such Lender, regardless of whether the exercise of any
such remedy would result in any penalty or loss of interest or profit with
respect to any withdrawal of funds deposited in a time deposit account prior to
the maturity thereof.
2.18 General Provisions Relating to Interest . (a) It is the intention of the
parties hereto to comply strictly with all applicable usury laws. In this
connection,
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there shall never be collected, charged, or received on the sums advanced
hereunder interest in excess of that which would accrue at the Highest Lawful
Rate. For purposes of Tex. Fin. Code Ann. ss. 303.301 (Vernon's 1998), as
amended, the Borrower agrees that the Highest Lawful Rate shall be the
"indicated (weekly) rate ceiling" as defined in such Article, provided that the
Administrative Agent and the Lenders may also rely, to the extent permitted by
applicable laws, on alternative maximum rates of interest under other laws, if
greater.
(b) Notwithstanding anything herein or in the Notes to the contrary, during any
Limitation Period, the interest rate to be charged on amounts evidenced by the
Notes shall be the Highest Lawful Rate, and the obligation, if any, of the
Borrower for the payment of fees or other charges deemed to be interest under
applicable law shall be suspended. During any period or periods of time
following a Limitation Period, to the extent permitted by applicable laws, the
interest rate to be charged hereunder shall remain at the Highest Lawful Rate
until such time as there has been paid to the Administrative Agent and each
Lender (i) the amount of interest in excess of that accruing at the Highest
Lawful Rate that such Lender would have received during the Limitation Period
had the interest rate remained at the otherwise applicable rate, and (ii) all
interest and fees otherwise payable to the Administrative Agent and such Lender
but for the effect of such Limitation Period.
(c) If, under any circumstances, the aggregate amounts paid on the Notes or
under this Agreement or any other Loan Document include amounts which by law are
deemed interest and which would exceed the amount permitted if the Highest
Lawful Rate were in effect, the Borrower stipulates that such payment and
collection will have been and will be deemed to have been, to the extent
permitted by applicable laws, the result of mathematical error on the part of
the Borrower, the Administrative Agent, and the Lenders; and the party receiving
such excess shall promptly refund the amount of such excess (to the extent only
of such interest payments in excess of that which would have accrued and been
payable on the basis of the Highest Lawful Rate) upon discovery of such error by
such party or notice thereof from the Borrower. In the event that the maturity
of any Obligation is accelerated, by reason of an election by the Lenders or
otherwise, or in the event of any required or permitted prepayment, then the
consideration constituting interest under applicable laws may never exceed the
Highest Lawful Rate; and excess amounts paid which by law are deemed interest,
if any, shall be credited by the Administrative Agent and the Lenders on the
principal amount of the Obligations, or if the principal amount of the
Obligations shall have been paid in full, refunded to the Borrower.
(d) All sums paid, or agreed to be paid, to the Administrative Agent and the
Lenders for the use, forbearance and detention of the proceeds of any advance
hereunder shall, to the extent permitted by applicable law, be amortized,
prorated, allocated, and spread throughout the full term hereof until paid in
full so that the actual rate of interest is uniform but does not exceed the
Highest Lawful Rate throughout the full term hereof.
2.19 Obligations Absolute . Subject to the further provisions of this Section,
the Obligations of the Borrower under this Article shall be absolute and
unconditional under any and all circumstances and irrespective of any set-off,
counterclaim, or defense to payment or performance which the Borrower may have
or have had against the Administrative Agent, any Lender, or any beneficiary of
any Letter of Credit. The Borrower agrees that none of the Administrative Agent
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or the Lenders shall be responsible for, nor shall the Obligations be affected
by, among other things, (a) the validity or genuineness of documents or any
endorsements thereon presented in connection with any Letter of Credit, even if
such documents shall in fact prove to be in any and all respects invalid,
fraudulent or forged, AND EVEN IF DUE TO THE NEGLIGENCE, WHETHER SOLE OR
CONCURRENT, OF THE ADMINISTRATIVE AGENT OR ANY LENDER, so long as the
Administrative Agent, as the issuer of such Letter of Credit, has no actual
knowledge of any such invalidity, lack of genuineness, fraud, or forgery prior
to the presentment for payment of a corresponding Letter of Credit or any draft
thereunder; provided, however, with respect to the preceding matters in this
Section, the Administrative Agent, as the issuer of the Letters of Credit,
agrees to exercise ordinary care in examining each document required to be
presented pursuant to each Letter of Credit to ascertain that each such document
appears on its face to comply with the terms thereof, or (b) any dispute between
or among the Borrower and any beneficiary of any Letter of Credit or any other
party to which any Letter of Credit may be transferred, or any claims whatsoever
of the Borrower against any beneficiary of any Letter of Credit or any such
transferee, EVEN IF DUE TO THE NEGLIGENCE, WHETHER SOLE OR CONCURRENT, OF THE
ADMINISTRATIVE AGENT OR ANY LENDER; provided, in all respects, that the
Administrative Agent, as the issuer of Letters of Credit, shall be liable to the
Borrower to the extent, but only to the extent, of any direct, as opposed to
consequential or punitive, damages suffered by the Borrower as a result of the
willful misconduct or gross negligence of the Administrative Agent as the issuer
of Letters of Credit in determining whether documents presented under a Letter
of Credit complied with the terms of such Letter of Credit that resulted in
either a wrongful payment under such Letter of Credit or a wrongful dishonor of
a claim or draft properly presented under such Letter of Credit. In the absence
of gross negligence or willful misconduct by the Administrative Agent as the
issuer of Letters of Credit, the Administrative Agent shall not be liable for
any error, omission, interruption or delay, EVEN IF DUE TO THE NEGLIGENCE,
WHETHER SOLE OR CONCURRENT, OF THE ADMINISTRATIVE AGENT, in transmission,
dispatch or delivery of any message or advice, however transmitted, in
connection with any Letter of Credit. The Administrative Agent, the Lenders, and
the Borrower agree that any action taken or omitted by the Administrative Agent,
as issuer of any Letter of Credit, under or in connection with any Letter of
Credit or the related drafts or documents, EVEN IF DUE TO THE NEGLIGENCE,
WHETHER SOLE OR CONCURRENT, OF THE ADMINISTRATIVE AGENT OR ANY LENDER, if done
in the absence of gross negligence or willful misconduct, shall be binding as
among the Administrative Agent, as issuer of such Letter of Credit or otherwise,
the Lenders, and the Borrower and shall not put the Administrative Agent, as
issuer of such Letter of Credit or otherwise, or any Lender under any liability
to the Borrower.
2.20 Yield Protection . (a) Without limiting the effect of the other provisions
of this Section (but without duplication), the Borrower shall pay to the
Administrative Agent and each Lender from time to time such amounts as the
Administrative Agent or such Lender may determine are necessary to compensate it
for any Additional Costs incurred by the Administrative Agent or such Lender.
(b) Without limiting the effect of the other provisions of this Section (but
without duplication), the Borrower shall pay to each Lender from time to time on
request such amounts as such Lender may determine are necessary to compensate
such Lender for any costs attributable to the maintenance by such Lender (or any
Applicable Lending Office), pursuant to any Regulatory Change, of capital in
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respect of its Commitment, such compensation to include an amount equal to any
reduction of the rate of return on assets or equity of such Lender (or any
Applicable Lending Office) to a level below that which such Lender (or any
Applicable Lending Office) could have achieved but for such Regulatory Change.
(c) Without limiting the effect of the other provisions of this Section (but
without duplication), in the event that any Requirement of Law or Regulatory
Change or the compliance by the Administrative Agent or any Lender therewith
shall (i) impose, modify, or hold applicable any reserve, special deposit, or
similar requirement against any Letter of Credit or obligation to issue Letters
of Credit, or (ii) impose upon the Administrative Agent or such Lender any other
condition regarding any Letter of Credit or obligation to issue Letters of
Credit, and the result of any such event shall be to increase the cost to the
Administrative Agent or such Lender of issuing or maintaining any Letter of
Credit or obligation to issue Letters of Credit or any liability with respect to
Letter of Credit Payments, or to reduce any amount receivable in connection
therewith, then upon demand by the Administrative Agent or such Lender, as the
case may be, the Borrower shall pay to the Administrative Agent or such Lender,
from time to time as specified by the Administrative Agent or such Lender,
additional amounts which shall be sufficient to compensate the Administrative
Agent or such Lender for such increased cost or reduced amount receivable.
(d) Without limiting the effect of the other provisions of this Section (but
without duplication), the Borrower shall pay to the Administrative Agent and
each Lender such amounts as shall be sufficient in the reasonable opinion of the
Administrative Agent and such Lender to compensate them for any loss, cost, or
expense incurred by and as a result of:
(i) any payment, prepayment, or conversion by the Borrower of a
LIBO Rate Loan on a date other than the last day of an
Interest Period for such Loan; or
(ii) any failure by the Borrower to borrow a LIBO Rate Loan or to
convert a Floating Rate Loan into a LIBO Rate Loan on the
date for such borrowing or conversion specified in the
relevant Borrowing Request;
such compensation to include with respect to any LIBO Rate Loan, an amount equal
to the excess, if any, of (A) the amount of interest which would have accrued on
the principal amount so paid, prepaid, converted, or not borrowed or converted
for the period from the date of such payment, prepayment, conversion, or failure
to borrow or convert to the last day of the then current Interest Period for
such Loan (or, in the case of a failure to borrow or convert, the Interest
Period for such Loan which would have commenced on the date of such failure to
borrow or convert) at the applicable rate of interest for such Loan provided for
herein over (B) the interest component of the amount the Administrative Agent or
such Lender would have bid in the London interbank market for Dollar deposits of
amounts comparable to such principal amount and maturities comparable to such
period, as reasonably determined by the Administrative Agent or such Lender.
(e) Determinations by the Administrative Agent or any Lender for purposes of
this Section of the effect of any Regulatory Change on capital maintained, its
costs or rate of return, maintaining Loans, issuing Letters of Credit, its
obligation to make Loans and issue Letters of Credit, or on amounts receivable
by it in respect of Loans, Letters of Credit, or such obligations, and the
additional amounts required to compensate the Administrative Agent and such
Lender under this Section shall be conclusive, absent manifest error, provided
that such determinations are made on a reasonable basis. The Administrative
Agent
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or the relevant Lender shall furnish the Borrower with a certificate setting
forth in reasonable detail the basis and amount of increased costs incurred or
reduced amounts receivable as a result of any such event, and the statements set
forth therein shall be conclusive, absent manifest error. The Administrative
Agent or the relevant Lender shall (i) notify the Borrower, as promptly as
practicable after the Administrative Agent or such Lender obtains knowledge of
any Additional Costs or other sums payable pursuant to this Section and
determines to request compensation therefor, of any event occurring after the
Closing Date which will entitle the Administrative Agent or such Lender to
compensation pursuant to this Section; and (ii) designate a different Applicable
Lending Office for the Loans affected by such event if such designation will
avoid the need for or reduce the amount of such compensation and will not, in
the sole opinion of the Administrative Agent or such Lender, be disadvantageous
to the Administrative Agent or such Lender. If any Lender requests compensation
from the Borrower under this Section, the Borrower may, after payment of all
compensation then accrued and by notice to the Administrative Agent and such
Lender, require that the Loans by such Lender of the type with respect to which
such compensation is requested be converted into Floating Rate Loans in
accordance with Section . Any compensation requested by the Administrative Agent
or any Lender pursuant to this Section shall be due and payable within five days
of delivery of any such notice to the Borrower.
(f) The Administrative Agent and the Lenders agree not to request, and the
Borrower shall not be obligated to pay, any Additional Costs or other sums
payable pursuant to this Section unless similar additional costs and other sums
payable are also generally assessed by the Administrative Agent or such Lender
against other customers similarly situated where such customers are subject to
documents providing for such assessment.
2.21 Illegality . Notwithstanding any other provision of this Agreement, in the
event that it becomes unlawful for any Lender or its Applicable Lending Office
to (a) honor its obligation to make LIBO Rate Loans, or (b) maintain LIBO Rate
Loans, then such Lender shall promptly notify the Administrative Agent and the
Borrower thereof. The obligation of such Lender to make LIBO Rate Loans and
convert Floating Rate Loans into LIBO Rate Loans shall then be suspended until
such time as such Lender may again make and maintain LIBO Rate Loans, and the
outstanding LIBO Rate Loans of such Lender shall be converted into Floating Rate
Loans in accordance with Section 2.13.
2.22 Taxes . (a) All payments made by the Borrower under this Agreement shall be
made free and clear of, and without reduction or withholding for or on account
of, present or future income, stamp or other taxes, levies, imposts, duties,
charges, fees, deductions or withholdings, hereafter imposed, levied, collected,
withheld or assessed by any Governmental Authority on the basis of any change
after the date hereof in any applicable treaty, law, rule, guideline or
regulations or in the interpretation or administration thereof, excluding, in
the case of the Administrative Agent and each Lender, net income and franchise
taxes imposed on the Administrative Agent or such Lender by the jurisdiction
under the laws of which the Administrative Agent or such Lender is organized or
any political subdivision or taxing authority thereof or therein, or by any
jurisdiction in which such Lender's lending office is located or any political
subdivision or taxing authority thereof or therein (all such non-excluded taxes,
levies, imposts, deductions, charges or withholdings being hereinafter called
"Taxes"). If any Taxes are required to be withheld from any amounts payable to
the Administrative
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Agent or any Lender hereunder or under any other Loan Document, the amounts so
payable to the Administrative Agent or such Lender shall be increased to the
extent necessary to yield to the Administrative Agent or such Lender (after
payment of all Taxes) interest or any such other amounts payable hereunder at
the rates or in the amounts specified in this Agreement and the other Loan
Documents. Whenever any Taxes are payable by the Borrower, as promptly as
possible thereafter, the Borrower shall send to the Administrative Agent for its
own account or for the account of such Lender, as the case may be, a certified
copy of an original official receipt received by the Borrower showing payment
thereof. If the Borrower fails to pay any Taxes when due to the appropriate
taxing authority or fails to remit to the Administrative Agent the required
receipts or other required documentary evidence, the Borrower shall indemnify
the Administrative Agent and the Lenders for any incremental taxes, interest or
penalties that may become payable by the Administrative Agent or any Lender as a
result of any such failure. The agreements in this Section shall survive the
termination of this Agreement and the payment of all Obligations.
(b) Each Lender that is not incorporated under the laws of the United States of
America or a state thereof agrees that, prior to the first date on which any
payment is due to it hereunder, it will, to the extent it may lawfully do so,
deliver to the Borrower and the Administrative Agent two duly completed copies
of United States Internal Revenue Service Form 1001 or 4224 or successor
applicable form, as the case may be, certifying in each case that such Lender is
entitled to receive payments under this Agreement and the Note payable to it,
without deduction or withholding of any United States federal income taxes. At
the written request of the Borrower, each Lender which delivers to the Borrower
and the Administrative Agent a Form 1001 or 4224 pursuant to the preceding
sentence further undertakes to deliver to the Borrower and the Administrative
Agent two further copies of such Form 1001 or 4224, or successor applicable
forms, or other manner of certification, as the case may be, on or before the
date that any such letter or form expires or becomes obsolete or after the
occurrence of any event requiring a change in the most recent form previously
delivered by it to the Borrower, and such extensions or renewals thereof as may
reasonably be requested by the Borrower, certifying in the case of Form 1001 or
4224 that such Lender is entitled to receive payments under this Agreement
without deduction or withholding of any United States federal income taxes,
unless in any such case, an event (including any change in treaty, law or
regulation) has occurred prior to the date on which any such delivery would
otherwise be required which renders all such forms inapplicable or which would
prevent such Lender from duly completing and delivering any such form with
respect to it and such Lender advises the Borrower that it is not capable of
receiving payments without any deduction or withholding of United States federal
income tax.
(2.23) Replacement Lenders . (a) If any Lender has notified the Borrower of its
incurring additional costs under Section or has required the Borrower to make
payments for Taxes under Section , the Borrower may, unless such Lender has
notified the Borrower that the circumstances giving rise to such notice no
longer apply, terminate, in whole but not in part, the Commitment of such Lender
(other than the Administrative Agent) (the "Terminated Lender") at any time upon
five Business Days' prior written notice to the Terminated Lender and the
Administrative Agent (such notice referred to herein as a "Notice of
Termination").
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(b) In order to effect the termination of the Commitment of the Terminated
Lender, the Borrower shall (i) obtain an agreement with one or more Lenders to
increase their Commitments and/or (ii) request any one or more other banking
institutions to become a "Lender" in place and instead of such Terminated Lender
and agree to accept a Commitment; provided, however, that such one or more other
banking institutions are reasonably acceptable to the Administrative Agent and
become parties by executing an Assignment Agreement (the Lenders or other
banking institutions that agree to accept in whole or in part the Commitment of
the Terminated Lender being referred to herein as the "Replacement Lenders"),
such that the aggregate increased and/or accepted Facility Amounts of the
Replacement Lenders under clauses (i) and (ii) above equal the Facility Amount
of the Terminated Lender.
(c) The Notice of Termination shall include the name of the Terminated Lender,
the date the termination will occur (the "Termination Date"), the Replacement
Lender or Replacement Lenders to which the Terminated Lender will assign its
Commitment, and, if there will be more than one Replacement Lender, the portion
of the Terminated Lender's Commitment to be assigned to each Replacement Lender.
(d) On the Termination Date, (i) the Terminated Lender shall by execution and
delivery of an Assignment Agreement assign its Commitment to the Replacement
Lender or Replacement Lenders (pro rata, if there is more than one Replacement
Lender, in proportion to the portion of the Terminated Lender's Commitment to be
assigned to each Replacement Lender) indicated in the Notice of Termination and
shall assign to the Replacement Lender or Replacement Lenders its Loan (if any)
then outstanding pro rata as aforesaid), (ii) the Terminated Lender shall
endorse its Note, payable without recourse, representation or warranty to the
order of the Replacement Lender or Replacement Lenders (pro rata as aforesaid),
(iii) the Replacement Lender or Replacement Lenders shall purchase the Note held
by the Terminated Lender (pro rata as aforesaid) at a price equal to the unpaid
principal amount thereof plus interest and fees accrued and unpaid to the
Termination Date, and (iv) the Replacement Lender or Replacement Lenders will
thereupon (pro rata as aforesaid) succeed to and be substituted in all respects
for the Terminated Lender with like effect as if becoming a Lender pursuant to
the terms of Section 9.1(b), and the Terminated Lender will have the rights and
benefits of an assignor under Section 9.1(b). To the extent not in conflict, the
terms of Section 9.1(b) shall supplement the provisions of this Section.
2.24 Regulatory Change . In the event that by reason of any Regulatory Change or
any other circumstance arising after the Closing Date affecting any Lender, such
Lender (a) incurs Additional Costs based on or measured by the excess above a
specified level of the amount of a category of deposits or other liabilities of
such Lender which includes deposits by reference to which the interest rate on
any LIBO Rate Loan is determined as provided in this Agreement or a category of
extensions of credit or other assets of such Lender which includes any LIBO Rate
Loan, or (b) becomes subject to restrictions on the amount of such a category of
liabilities or assets which it may hold, then, at the election of such Lender
with notice to the Administrative Agent and the Borrower, the obligation of such
Lender to make LIBO Rate Loans and to convert Floating Rate Loans into LIBO Rate
Loans shall be suspended until such time as such
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Regulatory Change or other circumstance ceases to be in effect, and all such
outstanding LIBO Rate Loans shall be converted into Floating Rate Loans in
accordance with Section 2.13.
ARTICLE 3
CONDITIONS
3.1 Conditions Precedent to Initial Loan and Letter of Credit . The Lenders
shall have no obligation to make the initial Loan and the Administrative Agent
shall have no obligation to issue the initial Letter of Credit unless and until
all matters incident to the consummation of the transactions contemplated herein
shall be satisfactory to the Administrative Agent, and the Administrative Agent
shall have received, reviewed, and approved the following documents and other
items, appropriately executed when necessary and, where applicable, acknowledged
by one or more authorized officers of the Borrower, all in form and substance
satisfactory to the Administrative Agent and dated, where applicable, of even
date herewith or a date prior thereto and acceptable to the Administrative
Agent.
(a) multiple counterparts of this Agreement, as requested by the
Administrative Agent;
(b) the Notes;
(c) copies of the Articles of Incorporation or Certificate of
Incorporation and all amendments thereto and the bylaws and all
amendments thereto of the Borrower, accompanied by a certificate issued
by the secretary or an assistant secretary of the Borrower, to the
effect that each such copy is correct and complete;
(d) certificates of incumbency and signatures of all officers of the
Borrower who are authorized to execute Loan Documents on behalf of the
Borrower, each such certificate being executed by the secretary or an
assistant secretary of the Borrower;
(e) copies of corporate resolutions approving the Loan Documents and
authorizing the transactions contemplated herein and therein, duly
adopted by the board of directors of the Borrower, accompanied by
certificates of the secretary or an assistant secretary of the Borrower
to the effect that such copies are true and correct copies of
resolutions duly adopted at a meeting or by unanimous consent of the
board of directors of the Borrower and that such resolutions constitute
all the resolutions adopted with respect to such transactions, have not
been amended, modified, or revoked in any respect, and are in full
force and effect as of the date of such certificate;
(f) multiple counterparts, as requested by the Administrative Agent, of
the following Security Instruments creating, evidencing, perfecting,
and otherwise
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establishing Liens in favor of the Administrative Agent for the benefit
of the Lenders in and to the Collateral which must be furnished on or
before May 15, 2000.
(i) Mortgage, Deed of Trust, Indenture, Security Agreement, Assignment
of Production, and Financing Statement from the Borrower covering
certain designated Oil and Gas Properties of the Borrower covering the
value, acceptable to all Lenders, of such Oil and Gas Properties and
all improvements, personal property, and fixtures related thereto which
form shall be approved by the Required Lenders and if such Lenders have
not responded to the Administrative Agent within 10 days from receipt
of such form, it will be deemed that such Lenders have approved the
form;
(ii) Financing Statements from the Borrower as debtor, constituent to
the instrument described in clause (i) above; and
(iii) undated letters, in form and substance satisfactory to the
Lender, from the Borrower to each purchaser of production and disburser
of the proceeds of production from or attributable to the Mortgaged
Properties, together with additional letters with the addressees left
blank, authorizing and directing the addressees to make future payments
attributable to production from the Mortgaged Properties directly to
the Lender which letters shall only be used by the Administrative Agent
if there is a Default or Event of Default;
(g) unaudited Financial Statements of the Borrower as of September 30,
1999;
(h) certificates dated as of a recent date from the Secretary of State or
other appropriate Governmental Authority for the State of Texas evidencing
the existence or qualification and good standing of the Borrower in such
jurisdiction;
(i) reserve data in a form and containing such information as may be
satisfactory to the Lenders covering the Oil and Gas Properties of the
Borrower, its Subsidiaries and the Partnerships;
(j) the opinion of counsel to the Borrower, in the form attached hereto as
Exhibit VII, with such changes thereto as may be approved by the
Administrative Agent and the Required Lenders and if such Lenders have not
responded within 10 days of receipt of such form, it will be deemed that
such Lenders have approved the form of such opinion;
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(k) such other agreements, documents, instruments, opinions, certificates,
waivers, consents, and evidence as the Administrative Agent or any Lender
may reasonably request.
3.2 Conditions Precedent to Each Loan . The obligations of the Lenders to make
each Loan are subject to the satisfaction of the following additional conditions
precedent:
(a) the Borrower shall have delivered to the Administrative Agent a
Borrowing Request at least the requisite time prior to the requested date
for the relevant Loan; and each statement or certification made in such
Borrowing Request shall be true and correct in all material respects on the
requested date for such Loan;
(b) no Default or Event of Default shall exist or will occur as a result of
the making of the requested Loan;
(c) if requested by the Administrative Agent or any Lender, the Borrower
shall have delivered evidence satisfactory to the Administrative Agent or
such Lender substantiating any of the matters contained in this Agreement
which are necessary to enable the Borrower to qualify for such Loan;
(d) the Administrative Agent shall have received, reviewed, and approved
such additional documents and items as described in Section as may be
requested by the Administrative Agent with respect to such Loan;
(e) no Material Adverse Effect shall have occurred;
(f) each of the representations and warranties contained in this Agreement
and the other Loan Documents shall be true and correct and shall be deemed
to be repeated by the Borrower as if made on the requested date for such
Loan;
(g) neither the consummation of the transactions contemplated hereby nor
the making of such Loan shall contravene, violate, or conflict with any
Requirement of Law;
(h) the Administrative Agent and each Lender shall have received the
payment of all fees payable by the Borrower hereunder and the
Administrative Agent shall have received reimbursement from the Borrower,
or special legal counsel for the Administrative Agent shall have received
payment from the Borrower, for all reasonable fees and expenses of counsel
to the Administrative Agent for which the Borrower is responsible pursuant
to applicable provisions of this Agreement and for which invoices have been
presented as of or prior to the date of the relevant Loan; and
(i) all matters incident to the consummation of the transactions hereby
contemplated shall be satisfactory to the Administrative Agent and each
Lender.
3.3 Conditions Precedent to Issuance of Letters of Credit . The obligation of
the Administrative Agent, as the issuer of the Letters of Credit, to issue,
renew, or extend any Letter of Credit is subject to the satisfaction of the
following additional conditions precedent:
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(a) the Borrower shall have delivered to the Administrative Agent a written
(or oral, confirmed promptly in writing) request for the issuance, renewal,
or extension of a Letter of Credit at least three Business Days prior to
the requested issuance, renewal, or extension date and a Letter of Credit
Application at least one Business Day prior to the requested issuance date;
and each statement or certification made in such Letter of Credit
Application shall be true and correct in all material respects on the
requested date for the issuance of such Letter of Credit;
(b) no Default or Event of Default shall exist or will occur as a result of
the issuance, renewal, or extension of such Letter of Credit; and
(c) the terms, provisions, and beneficiary of the Letter of Credit or such
renewal or extension shall be satisfactory to the Administrative Agent, as
the issuer of the Letters of Credit, in its sole discretion.
ARTICLE 4
REPRESENTATIONS AND WARRANTIES
To induce the Administrative Agent and the Lenders to enter
into this Agreement and to extend credit to the Borrower, the Borrower
represents and warrants to the Administrative Agent and each Lender (which
representations and warranties shall survive the delivery of the Notes) that:
4.1 Existence of Borrower and Subsidiaries . Each of the Borrower and its
Subsidiaries is a corporation, duly organized, validly existing and in good
standing under the laws of the state of its incorporation and is authorized to
do business and in good standing as a foreign corporation in every jurisdiction
in which it owns or leases real property or in which the nature of its business
requires it to be so qualified, except where the failure to so qualify,
individually or in the aggregate, could not reasonably be expected to have a
Material Adverse Effect.
4.2 Existence of Partnerships . Each of the Partnerships is duly formed and
legally existing under the laws of its jurisdiction of formation and is
qualified to do business in every jurisdiction in which the nature of its
business requires it to be so qualified, except where the failure to so qualify,
individually or in the aggregate, could not reasonably be expected to have a
Material Adverse Effect.
4.3 Due Authorization . The execution and delivery by the Borrower of this
Agreement and the borrowings hereunder; the execution and delivery by the
Borrower of the Notes and the other Loan Documents; the repayment by the
Borrower of the Indebtedness evidenced by the Notes and interest and fees, if
any, provided in the Notes and the other Loan Documents are within the power of
the Borrower; have been duly authorized by all necessary action; and do not and
will not (a) require the consent of any Governmental Authority, (b) contravene
or conflict with any Requirement of Law or the articles or certificate of
incorporation, bylaws, or other organizational or governing documents of the
Borrower, (c) contravene or conflict with any Partnership Agreement, or any
indenture, instrument or other agreement to which the Borrower is a party or by
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which the Property of the Borrower is bound or encumbered, or (d) result in or
require the creation or imposition of any Lien upon any of the Properties of the
Borrower other than as contemplated in the Loan Documents.
4.4 Valid and Binding Obligations of Borrower . This Agreement and the other
Loan Documents, when duly executed and delivered, will be legal, valid and
binding obligations of the Borrower, enforceable in accordance with their
respective terms, subject to any applicable bankruptcy, insolvency or other laws
of general application affecting creditors' rights and judicial decisions
interpreting any of the foregoing.
4.5 Security Instruments . The provisions of each Security Instrument are
effective to create in favor of the Lender, a legal, valid, and enforceable Lien
in all right, title, and interest of the Borrower in the Collateral described
therein, which Liens, assuming the accomplishment of recording and filing in
accordance with applicable laws prior to the intervention of rights of other
Persons, shall constitute fully perfected first-priority Liens on all right,
title, and interest of the Borrower in the Collateral described therein subject
to the Permitted Liens.
4.6 Scope and Accuracy of Financial Statements . The Financial Statements of the
Borrower and its Subsidiaries as of December 31, 1999, provided to the Lenders
have been prepared in accordance with GAAP consistently applied and fairly
reflect the financial condition and the results of the operations of the
Borrower, and its Subsidiaries in all material respects as of the dates and for
the periods stated therein. No event or circumstance has occurred since December
31, 1997, that has resulted or could reasonably be expected to result in a
Material Adverse Effect.
4.7 Liabilities, Litigation and Restrictions . Except for the liabilities shown
in the Financial Statements provided to the Lenders prior to the Closing Date,
none of the Borrower, its Subsidiaries or the Partnerships has any liabilities,
direct or contingent, which may reasonably be expected to result in a Material
Adverse Effect. Except as disclosed to the Lenders in writing prior to the
Closing Date, no litigation or other action of any nature affecting any of the
Borrower, its Subsidiaries or the Partnerships is pending before any
Governmental Authority or, to the knowledge of the Borrower, threatened against
or affecting any of the Borrower, its Subsidiaries or the Partnerships, which
might reasonably be expected to result in a Material Adverse Effect. To the
knowledge of the Borrower, no unusual or unduly burdensome restriction,
restraint or hazard exists by contract, law, governmental regulation or
otherwise relative to the business or material Properties of any of the
Borrower, its Subsidiaries or the Partnerships other than such as relate
generally to Persons engaged in the business activities similar to those
conducted by the Borrower or such Subsidiary or Partnership, as the case may be.
4.8 Title to Properties . Each of the Borrower, its Subsidiaries and the
Partnerships has good and indefeasible title to all of its material
(individually or in the aggregate) Properties, free and clear of all Liens other
than Permitted Liens.
4.9 Compliance with Federal Reserve Regulations. The Borrower is not engaged
principally, or as one of its important activities, in the business of extending
credit for the purpose of purchasing or carrying margin stock (within the
meaning of Regulations G, U or X of the Board of Governors of the Federal
Reserve System). No part of the proceeds of any extension of credit under this
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Agreement will be used to purchase or carry any such margin stock or to extend
credit to others for the purpose of purchasing or carrying any such margin
stock. No transaction contemplated by the Loan Documents is in violation of any
regulations promulgated by the Board of Governors of the Federal Reserve System,
including Regulations G, T, U or X.
4.10 Authorizations and Consents . No authorization, consent, approval,
exemption, franchise, permit or license of, or filing with, any Governmental
Authority or other Person is required to authorize, or is otherwise required in
connection with, the valid execution and delivery by the Borrower of this
Agreement and the other Loan Documents or the repayment and performance by the
Borrower of the Obligations.
4.11 Compliance with Laws, Rules, Regulations and Orders . To the knowledge of
the Borrower, neither the business nor any of the activities of any of the
Borrower, its Subsidiaries or the Partnerships, as presently conducted, violates
any Requirement of Law the result of which violation could reasonably be
expected to result in a Material Adverse Effect. Each of the Borrower, its
Subsidiaries and the Partnerships possesses all licenses, approvals,
registrations, permits and other authorizations necessary to enable it to carry
on its business in all material respects as now conducted; all such licenses,
approvals, registrations, permits and other authorizations are in full force and
effect; and the Borrower has no reason to believe that it or any Subsidiary or
Partnership will be unable to obtain the renewal of any such licenses,
approvals, registrations, permits and other authorizations.
4.12 Proper Filing of Tax Returns and Payment of Taxes Due . Each of the
Borrower, its Subsidiaries and the Partnerships has duly and properly filed all
United States income tax returns and all other tax returns which are required to
be filed and has paid all taxes due, except such taxes, if any, as are being
contested in good faith and as to which adequate reserves in accordance with
GAAP have been made. The charges and reserves on the books of each of the
Borrower, its Subsidiaries and the Partnerships with respect to taxes and other
governmental charges are adequate.
4.13 ERISA Compliance . Each of the Borrower, its Subsidiaries and the
Partnerships is in compliance in all material respects with the applicable
provisions of ERISA. No "reportable event", as such term is defined in Section
4043 of ERISA, has occurred with respect to any Plan. None of the Borrower, its
Subsidiaries or the Partnerships has incurred or expects to incur any material
liability to the Pension Benefit Guaranty Corporation or any Plan. With respect
to each Plan, the total value of the accrued benefits (both vested and
nonvested) does not materially exceed the value of the assets of such Plan, both
valued as of the end of the Plan year immediately prior to the date of this
Agreement. None of the Borrower, its Subsidiaries or the Partnerships currently
contributes to, or has an obligation to contribute to, or has at any time
contributed to, or had an obligation to contribute to, any Multi-employer Plan.
4.14 Take-or-Pay; Gas Imbalances . Except as disclosed in writing to the Lenders
prior to the Closing Date, none of the Borrower, its Subsidiaries or the
Partnerships is obligated in any material respect by virtue of any prepayment
made under any contract containing a "take-or-pay" or "prepayment" provision or
under any similar agreement to deliver hydrocarbons produced from or allocated
to any of its Oil and Gas Properties at some future date without receiving full
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payment therefor at the time of delivery. Except as disclosed in writing to the
Lenders prior to the Closing Date, none of the Borrower, its Subsidiaries or the
Partnerships has produced gas, in any material amount, subject to balancing
rights of third parties or subject to balancing duties under governmental
requirements, except as to such matters for which the Borrower or the relevant
Subsidiary or Partnership has established monetary reserves adequate in amount
to satisfy such obligations and has segregated such reserves from other
accounts.
4.15 Refunds . No orders of, proceedings pending before, or other requirements
of, the Federal Energy Regulatory Commission, the Texas Railroad Commission, the
Oklahoma Corporation Commission, the Louisiana Conservation Commission, or any
other Governmental Authority exist which could result in any of the Borrower,
its Subsidiaries or the Partnerships being required to refund any material
portion of the proceeds received or to be received from the sale of hydrocarbons
constituting part of its Oil and Gas Properties.
4.16 Casualties or Taking of Property . Except as disclosed to the Lenders in
writing prior to the Closing Date, since September 30, 1999, neither the
business nor any Property of any of the Borrower, its Subsidiaries or the
Partnerships has been materially adversely affected as a result of any fire,
explosion, earthquake, flood, drought, windstorm, accident, strike or other
labor disturbance, embargo, requisition of taking of Property or cancellation of
contracts, permits or concessions by any Governmental Authority, riot,
activities of armed forces or acts of God.
4.17 Locations of Business and Offices . The principal place of business and
chief executive office of the Borrower is located at the address for the
Borrower set forth in Section 9.4 or at such other location as the Borrower may
have, with prior written notice, advised the Administrative Agent.
4.18 Environmental Compliance . Except as has been disclosed to the Lenders in
writing prior to the Closing Date:
(a) no Property of any of the Borrower, its Subsidiaries or the
Partnerships is currently on, or, to the best knowledge of the Borrower
after due inquiry made in accordance with good commercial practices, has
ever been on, any federal or state list of Superfund Sites;
(b) except in compliance with all applicable Requirements of Law, no
Hazardous Substances have been generated, transported and/or disposed of by
any of the Borrower, its Subsidiaries or the Partnerships at a site which
was, at the time of such generation, transportation and/or disposal, or has
since become, a Superfund Site;
(c) no Release of Hazardous Substances by any of the Borrower, its
Subsidiaries or the Partnerships or, to the best knowledge of the Borrower
after due inquiry made in accordance with good commercial practices, from,
affecting or related to any Property of any of the Borrower, its
Subsidiaries or the Partnerships has occurred; and
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(d) no Environmental Complaint has been received by the any of the
Borrower, its Subsidiaries or the Partnerships.
4.19 Investment Company Act Compliance . The Borrower is not an "investment
company" or a company "controlled" by an "investment company," within the
meaning of the Investment Company Act of 1940, as amended.
4.20 Public Utility Holding Company Act Compliance . The Borrower is not a
"holding company," or a "subsidiary company" of a "holding company" or an
"affiliate" of either a "holding company" or a "subsidiary company" within the
meaning of the Public Utility Holding Company Act of 1935, as amended.
4.21 No Material Misstatements. No information, exhibit or report prepared by or
at the direction or with the supervision of the Borrower and furnished to any
Lender or the Administrative Agent in connection with the negotiation and
preparation of this Agreement or any Loan Document contains any material
misstatements of fact or omits to state a material fact necessary to make the
statements contained therein not misleading as of the date made or deemed made.
4.22 Subsidiaries . As of the date hereof, except as set forth on Exhibit VIII,
the Borrower has no Subsidiaries and none of the Borrower or its Subsidiaries is
a partner or participant in any partnership or joint venture. The percentage
ownership by the Borrower of outstanding common stock of each Subsidiary and the
partnership interest (Distributive Share) of the Borrower in each Partnership is
as set forth on Exhibit VIII.
4.23 Defaults. None of the Borrower, its Subsidiaries or the Partnerships is in
default, nor has any event or circumstance occurred which, but for the passage
of time or the giving of notice, or both, would constitute a default, under any
loan or credit agreement, indenture, mortgage, deed of trust, security agreement
or other instrument or agreement evidencing or pertaining to any Indebtedness of
the Borrower or such Subsidiary or Partnership, as the case may be, or under any
other material agreement or instrument to which the Borrower or such Subsidiary
or Partnership is a party or by which any of them or the Property of any of them
is bound, including agreements and instruments relating to the Oil and Gas
Properties. No Default or Event of Default exists.
4.24 Maintenance of Properties . Each of the Borrower, its Subsidiaries and the
Partnerships has maintained its Properties in good and workable condition,
ordinary wear and tear excepted, and in compliance in all material respects with
all applicable Requirements of Law.
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ARTICLE 5
AFFIRMATIVE COVENANTS
So long as any Obligation remains outstanding or unpaid or any
Commitment exists, the Borrower shall:
5.1 Maintenance and Access to Records . Keep, and cause each of its Subsidiaries
and the Partnerships to keep, adequate records in accordance with GAAP, of all
of its transactions so that at any time, and from time to time, its financial
condition may be readily determined and, at the reasonable request of the
Administrative Agent or any Lender, make such records available for inspection
and permit the Administrative Agent or such Lender to make and take away copies
thereof.
5.2 Quarterly Financial Statements . Deliver to each Lender, on or before the
60th day after the end of each of the first three fiscal quarters of the
Borrower, the unaudited consolidated and consolidating Financial Statements of
the Borrower and its Subsidiaries, as at the end of such period and from the
beginning of such fiscal year to the end of such period, as applicable, which
Financial Statements shall be certified by the chief financial officer of the
Borrower as having been prepared in accordance with GAAP, consistently applied,
and as a fair presentation of the condition of the Borrower and its
Subsidiaries, subject to changes resulting from normal year-end audit
adjustments.
5.3 Annual Financial Statements . Deliver to each Lender, as soon as available
but not later than the 120th day after the close of each fiscal year of the
Borrower, a copy of the annual audited consolidated and consolidating Financial
Statements of the Borrower and its Subsidiaries.
5.4 Compliance Certificates . Concurrently with the furnishing of the Financial
Statements submitted pursuant to Sections 5.2 and 5.3, provide the
Administrative Agent a Compliance Certificate; and concurrently with the
furnishing of the Financial Statements submitted pursuant to Section 5.3 if
requested by any Lender, provide each Lender a certificate in customary form
from the independent certified public accountants for the Borrower stating that
their audit has not disclosed the existence of any Default or Event of Default
or, if their audit has disclosed the existence of any Default or Event of
Default, specifying the nature, period of existence and status thereof.
5.5 Oil and Gas Reserve Reports . (a) Deliver to each Lender each April 1 during
the term of this Agreement, engineering reports in usual and customary form and
substance, certified by any nationally- or regionally- recognized independent
consulting petroleum engineers acceptable to the Lenders as fairly and
accurately setting forth (i)the proven and producing, shut in, behind pipe and
undeveloped oil and gas reserves (separately classified as such) attributable to
the Oil and Gas Properties of the Borrower, its Subsidiaries and the
Partnerships as of January 1 of the year for which such reserve reports are
furnished, (ii)the aggregate present value of the future net income with respect
to such Properties, discounted at a stated per annum discount rate of proven and
producing reserves, (iii)projections of the annual rate of production, gross
income
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and net income with respect to such proven and producing reserves, and
information with respect to the "take or pay," "prepayment" and gas balancing
liabilities of the Borrower, its Subsidiaries and the Partnerships.
(b) Deliver to each Lender no later than October 1 of each year during the term
of this Agreement, engineering reports in form and substance satisfactory to the
Lender prepared by or under the supervision of the chief petroleum engineer of
the Borrower evaluating the Oil and Gas Properties of the Borrower, its
Subsidiaries and the Partnerships as of July 1 of the year for which such
reserve reports and furnished and updating information provided in the reports
pursuant to Section 5.5(a).
(c) All of the reports provided pursuant to this Section shall be submitted to
the Lenders together with additional data concerning pricing, quantities of
production from the Oil and Gas Properties of the Borrower, its Subsidiaries and
the Partnerships, purchasers of production and such other information and
engineering and geological data with respect thereto as the Lenders may
reasonably request and shall set forth the interests of the Borrower in all such
Oil and Gas Properties and separately designate such Properties by field.
5.6 SEC and Other Reports . Deliver to each Lender, within five days after any
material report (other than financial statements) or other communication is sent
by any of the Borrower, its Subsidiaries or the Partnerships to its stockholders
or partners or is filed by any of the Borrower, its Subsidiaries or the
Partnerships with the Securities and Exchange Commission or any successor or
analogous Governmental Authority, copies of such report or communication.
5.7 Notices . Deliver to Administrative Agent, promptly upon any officer of the
Borrower having knowledge of the occurrence of any of the following events or
circumstances, a written statement with respect thereto, signed by the chief
financial officer of the Borrower, or other authorized representative of the
Borrower designated from time to time pursuant to written designation by the
Borrower delivered to the Administrative Agent, advising the Lenders of the
occurrence of such event or circumstance and the steps, if any, being taken by
the Borrower with respect thereto:
(a) any Default or Event of Default;
(b) any default or event of default under any contractual obligation of the
Borrower, or any litigation, investigation or proceeding between any of the
Borrower, its Subsidiaries or the Partnerships and any Governmental
Authority which, in either case, if not cured or if adversely determined,
as the case may be, could reasonably be expected to have a Material Adverse
Effect;
(c) any litigation or proceeding involving any of the Borrower, its
Subsidiaries or the Partnerships as a defendant or in which any Property of
any of the Borrower, its Subsidiaries or the Partnerships is subject to a
claim and in which the amount involved is $1,000,000 or more and which is
not covered by insurance or in which injunctive or similar relief is
sought;
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(d) the receipt by any of the Borrower, its Subsidiaries or the
Partnerships of any Environmental Complaint or any formal request from any
Governmental Authority or other Person for information (other than
requirements for compliance reports) regarding any Release of Hazardous
Substances by any of the Borrower, its Subsidiaries or the Partnerships or
from, affecting or related to any Property of any of the Borrower, its
Subsidiaries or the Partnerships or adjacent to any Property of any of the
Borrower, its Subsidiaries or the Partnerships;
(e) any actual, proposed or threatened testing or other investigation by
any Governmental Authority or other Person concerning the environmental
condition of, or relating to, any Property of any of the Borrower, its
Subsidiaries or the Partnerships or adjacent to any Property of any of the
Borrower, its Subsidiaries or the Partnerships following any allegation of
a violation of any Requirement of Law;
(f) any Release of Hazardous Substances by any of the Borrower, its
Subsidiaries or the Partnerships or from, affecting or related to any
Property of any of the Borrower, its Subsidiaries or the Partnerships or
adjacent to any Property of any of the Borrower, its Subsidiaries or the
Partnerships;
(g) the violation of any Environmental Law or the revocation, suspension or
forfeiture of or failure to renew, any permit, license, registration,
approval or authorization which could reasonably be expected to have a
Material Adverse Effect;
(h) the institution by the Borrower or any of its Affiliates of any
Multi-employer Plan or the withdrawal or partial withdrawal by the Borrower
or any of its Affiliates from any Multi-employer Plan;
(i) the sale or other transfer of any Oil and Gas Properties or any
interest therein to any Partnership;
(j) the incurrence of any Contingent Obligation permitted by Section
6.1(i), the making of any loan or advance permitted by Section 6.2(g), or
the acquisition or making of any Investment permitted by Section 6.8(h)
which causes the aggregate of all such Contingent Obligations, loans,
advances, and Investments to exceed $10,000,000; and
(k) any other event or condition which could reasonably be expected to have
a Material Adverse Effect.
5.8 Letters in Lieu of Transfer Orders; Division Orders . Promptly upon request
by the Lender at any time and from time to time, execute such letters in lieu of
transfer orders, in addition to the letters signed by the Borrower and delivered
to the Lender in satisfaction of the condition set forth in Section 3.1(f)(iv)
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and/or division and/or transfer orders as are necessary or appropriate to
transfer and deliver to the Lender proceeds from or attributable to any
Mortgaged Property. The above shall only be used if there is a Default or Event
of Default.
5.9 Additional Information . Furnish to the Administrative Agent, promptly upon
the request of the Administrative Agent, such additional financial or other
information concerning the assets, liabilities, operations and transactions of
the Borrower, its Subsidiaries and the Partnerships as the Administrative Agent
or any Lender may from time to time reasonably request, including copies of the
Partnership Agreements and all amendments thereto, certified as being true and
correct by the secretary or assistant secretary of the Borrower; and promptly
notify the Administrative Agent each time that a change in the Loan Balance, L/C
Exposure, or Borrowing Base would result in a change in the Applicable Margin.
5.10 Payment of Assessments and Charges . Pay, and cause each of its
Subsidiaries and the Partnerships to pay, all taxes, assessments, governmental
charges, claims for labor, supplies, rent and other obligations which, if
unpaid, might become a Lien against any of its Property, except any of the
foregoing being contested in good faith and as to which adequate reserves in
accordance with GAAP have been established or unless failure to pay would not
have a Material Adverse Effect.
5.11 Compliance with Laws . Comply, and cause each of its Subsidiaries and the
Partnerships to comply, with all Requirements of Law, including (a)the Natural
Gas Policy Act of 1978, as amended, (b)Environmental Laws, and (c)all permits,
licenses, registrations, approvals and authorizations (i)related to any natural
or environmental resource or media located on, above, within, in the vicinity
of, related to or affected by any of its Property, (ii)required for the
performance or conduct of its operations, or (iii)applicable to the use,
generation, handling, storage, treatment, transport or disposal of Hazardous
Substances; and cause all of its employees, agents, contractors, subcontractors
and future lessees (pursuant to appropriate lease provisions), while such
Persons are acting within the scope of their relationship with the Borrower,
such Subsidiary or Partnership, as the case may be, to comply with all
applicable Requirements of Law as may be necessary or appropriate to enable the
Borrower or such Subsidiary or Partnership, as the case may be, to so comply.
5.12 ERISA Information and Compliance . Furnish to each Lender upon request,
copies of each annual and other report with respect to each Plan or any trust
created thereunder filed with the United States Secretary of Labor or the
Pension Benefit Guaranty Corporation; fund, and cause each of its Subsidiaries
and the Partnerships to fund, all current service pension liabilities as they
are incurred under the provisions of all Plans and Multi-employer Plans; and
comply, and cause each of its Subsidiaries and the Partnerships to comply, with
all applicable provisions of ERISA.
5.13 Hazardous Substances Indemnification . INDEMNIFY AND HOLD EACH LENDER AND
THE ADMINISTRATIVE AGENT AND ALL OFFICERS, DIRECTORS, EMPLOYEES, AGENTS,
ATTORNEYS-IN-FACT AND AFFILIATES OF EACH LENDER AND THE ADMINISTRATIVE AGENT
HARMLESS FROM AND AGAINST ANY AND ALL CLAIMS, LOSSES, DAMAGES, LIABILITIES,
FINES, PENALTIES, CHARGES, ADMINISTRATIVE AND JUDICIAL PROCEEDINGS AND ORDERS,
JUDGMENTS, REMEDIAL ACTIONS, REQUIREMENTS AND ENFORCEMENT ACTIONS OF ANY KIND,
AND ALL COSTS AND EXPENSES INCURRED IN CONNECTION THEREWITH (INCLUDING
ATTORNEYS' FEES AND EXPENSES), ARISING DIRECTLY OR INDIRECTLY, IN WHOLE OR IN
PART, FROM (A)THE PRESENCE OF ANY HAZARDOUS SUBSTANCE ON, UNDER OR FROM THE
PROPERTY OF ANY OF THE BORROWER, ITS SUBSIDIARIES OR THE
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PARTNERSHIPS, WHETHER PRIOR TO OR DURING THE TERM HEREOF, (B)ANY ACTIVITY
CARRIED ON OR UNDERTAKEN ON OR OFF THE PROPERTY OF ANY OF THE BORROWER, ITS
SUBSIDIARIES OR THE PARTNERSHIPS, WHETHER PRIOR TO OR DURING THE TERM HEREOF,
AND WHETHER BY ANY OF THE BORROWER, ITS SUBSIDIARIES OR THE PARTNERSHIPS OR ANY
PREDECESSOR IN TITLE OR ANY EMPLOYEES, AGENTS, CONTRACTORS OR SUB-CONTRACTORS OF
ANY OF THE BORROWER, ITS SUBSIDIARIES OR THE PARTNERSHIPS OR ANY PREDECESSOR IN
TITLE, OR ANY THIRD PERSONS AT ANY TIME OCCUPYING OR PRESENT ON SUCH PROPERTIES,
IN CONNECTION WITH THE HANDLING, TREATMENT, REMOVAL, STORAGE, DECONTAMINATION,
CLEANUP, TRANSPORTATION OR DISPOSAL OF ANY HAZARDOUS SUBSTANCE AT ANY TIME
LOCATED OR PRESENT ON OR UNDER SUCH PROPERTY, (C)ANY RESIDUAL CONTAMINATION ON
OR UNDER THE PROPERTY OF ANY OF THE BORROWER, ITS SUBSIDIARIES OR THE
PARTNERSHIPS, OR (D) ANY CONTAMINATION OF ANY PROPERTY OR NATURAL RESOURCES
ARISING IN CONNECTION WITH OR RESULTING FROM THE GENERATION, USE, HANDLING,
STORAGE, TRANSPORTATION OR DISPOSAL OF ANY HAZARDOUS SUBSTANCE BY ANY OF THE
BORROWER, ITS SUBSIDIARIES OR THE PARTNERSHIPS OR ANY EMPLOYEE, AGENT,
CONTRACTOR OR SUBCONTRACTOR OF ANY OF THE BORROWER, ITS SUBSIDIARIES OR THE
PARTNERSHIPS WHILE SUCH PERSONS ARE ACTING WITHIN THE SCOPE OF THEIR
RELATIONSHIP WITH THE BORROWER, SUCH SUBSIDIARY OR PARTNERSHIP, AS THE CASE MAY
BE, IRRESPECTIVE OF WHETHER ANY OF SUCH ACTIVITIES WERE OR WILL BE UNDERTAKEN IN
ACCORDANCE WITH REQUIREMENTS OF LAW, INCLUDING ANY OF THE FOREGOING ARISING FROM
NEGLIGENCE, WHETHER SOLE OR CONCURRENT, OF ANY LENDER OR THE ADMINISTRATIVE
AGENT OR ANY OF THEIR OFFICERS, DIRECTORS, EMPLOYEES, AGENTS, ATTORNEYS IN FACT
AND AFFILIATES. THE FOREGOING INDEMNITY SHALL SURVIVE SATISFACTION OF ALL
OBLIGATIONS AND THE TERMINATION OF THIS AGREEMENT.
5.14 Further Assurances . Promptly cure any defects, errors, or omissions in the
execution and delivery of any of the Loan Documents and all agreements
contemplated thereby, and upon notice, promptly execute and deliver to the
Administrative Agent all such other assurances and instruments as shall, in the
opinion of the Administrative Agent, be necessary to fulfill the terms of the
Loan Documents.
5.15 Fees and Expenses of Administrative Agent . Upon request by the
Administration Agent, promptly reimburse the Administrative Agent for all
amounts reasonably expended, advanced or incurred by the Administrative Agent in
connection with the development, preparation and execution of this Agreement and
the other Loan Documents and all amendments, restatements, supplements and
modifications hereto and thereto and the consummation of the transactions
contemplated hereby and thereby and all amounts reasonably expended, advanced or
incurred by the Administrative Agent or any Lender to collect the Notes and
enforce the rights of the Lenders and the Administrative Agent under this
Agreement and the other Loan Documents, which amounts shall be deemed
compensatory in nature and liquidated as to amount upon notice to the Borrower
by the Administrative Agent or such Lender as applicable and which amounts will
include, but not be limited to, (a)attorneys' fees, (b)all court costs, (c)fees
of auditors and accountants, (d)investigation expenses, (e)fees and expenses
incurred in connection with the participation of the Lenders and the
Administrative Agent as members of the creditors' committee in a case commenced
under Title 11 of the United States Code or other similar law of the United
States, the State of Texas or any other jurisdiction, incurred by the
Administrative Agent in connection with the collection of the Obligations,
(f)and
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any and all search, registration, recording and filing fees and any and all
liabilities with respect to stamp, excise and other taxes, together with
interest at the Floating Rate, calculated on the basis of a year of 365 or 366
days, as the case may be, on each such amount from the date of notification to
the Borrower that the same was expended, advanced or incurred by the
Administrative Agent until the date it is repaid to the Administrative Agent.
The obligations of the Borrower under this Section shall survive the
nonassumption of this Agreement in a case commenced under Title 11 of the United
States Code or other similar law of the United States, the State of Texas or any
other jurisdiction and be binding upon the Borrower and any trustee, receiver or
liquidator of the Borrower appointed in any such case.
5.16 Indemnification of Lenders and Administrative Agent . INDEMNIFY AND HOLD
EACH LENDER AND THE ADMINISTRATIVE AGENT AND ALL OFFICERS, DIRECTORS, EMPLOYEES,
AGENTS, ATTORNEYS-IN-FACT AND AFFILIATES OF EACH LENDER AND THE ADMINISTRATIVE
AGENT (EACH SUCH PERSON AN "INDEMNITEE") HARMLESS FROM ANY AND ALL LIABILITIES,
OBLIGATIONS, LOSSES, DAMAGES, PENALTIES, ACTIONS, JUDGMENTS, SUITS, COSTS,
EXPENSES AND DISBURSEMENTS OF ANY KIND OR NATURE WHATSOEVER (INCLUDING
REASONABLE ATTORNEYS' FEES AND DISBURSEMENTS) INCURRED BY OR ASSERTED AGAINST
ANY INDEMNITEE ARISING OUT OF, IN ANY WAY CONNECTED WITH, OR AS A RESULT OF
(A)THE EXECUTION OR DELIVERY OF THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT,
(B)THE PERFORMANCE BY THE PARTIES TO THE LOAN DOCUMENTS OF THEIR RESPECTIVE
OBLIGATIONS THEREUNDER OR THE CONSUMMATION OF THE TRANSACTIONS CONTEMPLATED
THEREBY, OR (C)THE ENFORCEMENT OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS
(ALL THE FOREGOING IN THIS SECTION, COLLECTIVELY, THE "INDEMNIFIED
LIABILITIES"), INCLUDING INDEMNIFIED LIABILITIES ARISING FROM THE NEGLIGENCE,
WHETHER SOLE OR CONCURRENT, OF ANY INDEMNITEE; PROVIDED THAT THE BORROWER SHALL
HAVE NO OBLIGATION UNDER THIS SECTION TO ANY INDEMNITEE WITH RESPECT TO
INDEMNIFIED LIABILITIES THAT ARE DETERMINED BY A COURT OF COMPETENT JURISDICTION
BY FINAL AND NON-APPEALABLE JUDGMENT TO HAVE RESULTED FROM THE GROSS NEGLIGENCE
OR WILLFUL MISCONDUCT OF SUCH INDEMNITEE OR FROM THE BREACH BY SUCH INDEMNITEE
OF ITS OBLIGATIONS UNDER ANY LOAN DOCUMENT. THE OBLIGATIONS OF THE BORROWER
UNDER THIS SECTION SHALL SURVIVE THE SATISFACTION OF ALL OBLIGATIONS, THE
TERMINATION OF THIS AGREEMENT AND THE NONASSUMPTION OF THIS AGREEMENT IN A CASE
COMMENCED UNDER TITLE 11 OF THE UNITED STATES CODE OR OTHER SIMILAR LAW OF THE
UNITED STATES, THE STATE OF TEXAS OR ANY OTHER JURISDICTION AND BE BINDING UPON
THE BORROWER AND ANY TRUSTEE, RECEIVER OR LIQUIDATOR OF THE BORROWER APPOINTED
IN ANY SUCH CASE.
5.17 Maintenance of Existence and Good Standing . Maintain, and cause each of
its Subsidiaries and the Partnerships to maintain, its corporate or partnership
existence, as the case may be; and maintain, and cause each of its Subsidiaries
and the Partnerships to maintain, its qualification and good standing in all
jurisdictions wherein the Property now owned or hereafter acquired or the
business now or hereafter conducted necessitates same except where the failure
to so maintain such qualification and good standing would not have a Material
Adverse Effect.
5.18 Maintenance of Tangible Property . Maintain, and cause each of its
Subsidiaries and the Partnerships to maintain, all of its material tangible
Property in good repair and condition and make all necessary replacements
thereof and operate such Property in a good and workmanlike manner.
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5.19 Maintenance of Insurance . Maintain, or cause to be maintained, insurance
with respect to the properties and business of each of the Borrower, its
Subsidiaries and the Partnerships against such liabilities, casualties, risks
and contingencies and in such amounts as is customary in the industry; and
furnish to the Administrative Agent, at the execution of this Agreement and at
the request of any Lender thereafter, certificates evidencing such insurance.
5.20 Inspection of Tangible Property . Permit any authorized representative of
any Lender or the Administrative Agent, at the sole risk of such party and such
authorized representatives, to visit and inspect any tangible Property of any of
the Borrower, its Subsidiaries or the Partnerships.
5.21 Payment of Notes and Performance of Obligations . Pay the Notes according
to the reading, tenor and effect thereof, as modified by this Agreement, and pay
and perform all Obligations.
5.22 Operation of Oil and Gas Properties . Develop, maintain and operate, and
cause each of its Subsidiaries and the Partnerships to develop, maintain and
operate, its Oil and Gas Properties in a prudent and workmanlike manner in
accordance with industry standards.
5.23 Performance of Designated Contracts . Perform and observe in all material
respects all of its obligations under the Partnership Agreements and perform and
observe, and cause each of its Subsidiaries and the Partnerships to perform and
observe, in all material respects all of its obligations under all material
agreements and contracts of such Person.
5.24 Title Information . Furnish to the Administrative Agent by April 15, title
information and property descriptions for the Mortgage exhibit sufficient for
Counsel to the Administrative Agent to summarize such title information and
submit such summary to the Lenders and the Required Lenders must approve such
summary within 10 days of receipt of such summary and if such Lenders have not
responded within such time period it will be deemed that they have approved such
summary.
ARTICLE 6
NEGATIVE COVENANTS
So long as any Obligation remains outstanding or any
Commitment exists, without the prior written consent of the Required Lenders,
the Borrower will not:
6.1 Indebtedness; Contingent Obligations . Create, incur, assume or permit to
exist any Indebtedness or Contingent Obligations, or permit any of its
Subsidiaries or the Partnerships to do so; provided, however, the foregoing
restrictions shall not apply to (a)the Obligations other than Hedging
Obligations; (b)unsecured accounts payable incurred in the ordinary course of
business, which are not unpaid in excess of 60 days beyond invoice date or are
being contested in good faith and as to which such reserve as is required by
GAAP has been made; (c)performance guarantees and performance surety or other
bonds provided in the ordinary course of business; (d)operating leases entered
into in the ordinary course of business or endorsements of instruments for
collection in the ordinary course of business; (e)purchase-money Indebtedness of
the Borrower only incurred in connection with the acquisition of equipment not
exceeding $5,000,000 at any time outstanding; (f)Subordinated Debt; (g)Senior
Subordinated Debt (h)obligations with respect to Hedging Agreements entered into
with any Lender or any affiliate of any Lender or another counterparty
satisfactory to the Administrative Agent provided that (i) in
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the case of hydrocarbon Hedging Agreements, such Hedging Agreements protect
against actual exposure to volatility in hydrocarbon prices and the aggregate of
the notional and contracted amounts of such Hedging Agreements in any form other
than put options do not cover at any time a volume of hydrocarbons exceeding 80%
of the projected production from the proved producing reserves as reflected on
the Reserve Report most recently provided to the Administrative Agent, and the
aggregate of the notional and contracted amounts of all Hedging Agreements do
not cover at any time a volume of hydrocarbons exceeding 100% of the projected
production from the proved producing reserves as reflected on the Reserve Report
most recently provided to the Administrative Agent, and (ii) the net
mark-to-market exposure under such Hedging Agreements does not exceed $2,500,000
in the aggregate for the Borrower, its Subsidiaries, and the Partnerships,
(j)and other Indebtedness not exceeding $5,000,000 in the aggregate at any time
outstanding for the Borrower and its Subsidiaries.
6.2 Loans or Advances . Make or agree to make or allow to remain outstanding any
loans or advances to any Person, or permit any of its Subsidiaries or the
Partnerships to do so; provided, however, the foregoing restrictions shall not
apply to (a) advances or extensions of credit in the form of accounts receivable
incurred in the ordinary course of business and upon terms common in the
industry for such accounts receivable, (b) accounts receivable owed by the
Partnerships to the Borrower with respect to general and administrative and/or
direct expenses and not outstanding for more than 60 days, (c) loans, advances
or extensions of credit to suppliers or contractors under applicable contracts
or agreements in connection with oil and gas development activities of the
Borrower or such Subsidiary or Partnership, (d) loans and advances to employees
of the Borrower or such Subsidiary in the ordinary course of business not
exceeding $1,000,000 in the aggregate at any time outstanding, (e) loans or
advances by the Borrower to any Partnership not outstanding for more than 60
days and not exceeding the uncollected but accrued revenues payable to the
Borrower with respect to Oil and Gas Properties but attributable to such
Partnership, the aggregate of which for all Partnerships shall not exceed
$8,000,000 at any time outstanding, or (f) loans or advances by the Borrower to
Swift Energy Marketing Company which, together with Investments permitted
pursuant to Section 6.8(g) shall not exceed $6,000,000.
6.3 Mortgages or Pledges of Assets . Create, incur, assume or permit to exist,
any Lien on any of its Properties, or permit any of its Subsidiaries or the
Partnerships to do so; provided, however, the foregoing restriction in this
Section shall not apply to Permitted Liens.
6.4 Sales of Properties; Leasebacks . Sell, transfer or otherwise dispose of, in
any 12-month period, in one or any series of transactions, in excess of
$10,000,000 in the aggregate per fiscal year of its Property, or enter into any
arrangement to do so, or enter into any arrangement to sell or transfer any
Property and thereafter rent or lease as lessee such Property or other Property
intended for the same use or purpose of the Property sold or transferred, or
permit any of its Subsidiaries or the Partnerships to do any of the foregoing in
this Section; provided, however, the foregoing restrictions shall not apply to
(a) the sale of hydrocarbons or inventory in the ordinary course of business at
prices at least substantially equivalent to the open market prices at the time
of sale for comparable hydrocarbons or inventory other than the sale of a
production payment and provided that no contract for the sale of hydrocarbons
shall obligate any of the Borrower, its Subsidiaries or the Partnerships to
deliver hydrocarbons at some future date without receiving full payment therefor
within 90 days of delivery, (b) the sale or other disposition of Property
destroyed, lost, worn out, damaged or having only salvage value or no longer
used or useful in the business of the Borrower, (c) farmouts or similar
agreements entered into in the ordinary course of business; or (d) sales of
Partnership interest.
6.5 Dividends and Distributions . Declare, pay or make, whether in cash or other
Property, any dividend or distribution on any share of any class of its capital
stock other than cash dividends not exceeding $2,000,000 in any fiscal year and
dividends paid in capital stock of the Borrower; or purchase, redeem or
otherwise acquire, directly or indirectly, for value or set apart in any way for
redemption, retirement or other acquisition, directly or indirectly, any of its
stock now
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or hereafter outstanding; return any capital to its stockholders; or make any
distribution (whether by reduction of capital or otherwise) of its assets to its
stockholders. Provided, however, the Borrower may acquire of its common stock
after the Closing Date having a fair market value at the time of Acquisition not
to exceed in the aggregate $15,000,000.
6.6 Changes in Corporate Structure . Enter into any transaction of
consolidation, merger or amalgamation unless the Borrower is the surviving
corporation of any such consolidation, merger or amalgamation and no Default or
Event of Default exists or will occur as a result thereof; or liquidate, wind up
or dissolve or suffer any liquidation or dissolution.
6.7 Rental or Lease Agreements . Enter into any contract to rent or lease any
Properties, real or personal, the aggregate of rental and lease payments under
which for the Borrower, its Subsidiaries and the Partnerships on a consolidated
basis will exceed $1,000,000 in any calendar or fiscal year or $5,000,000 during
the term of such leases; provided, however, the foregoing restriction shall not
apply to bonuses and rentals paid under oil, gas and mineral leases, or the
lease covering the corporate office of the Borrower.
6.8 Investments . Acquire Investments in, or purchase or otherwise acquire all
or substantially all of the assets of, any Person, or permit any of its
Subsidiaries or the Partnerships to do so; provided, however, the foregoing
shall not apply to investments in (a) United States government-issued securities
with maturities of no more than one year or certificates of deposit or
repurchase agreements issued by (i) any Lender or (ii) any bank or trust company
organized under the laws of the United States or any state thereof and having
capital surplus and undivided profits aggregating at least $250,000,000 and with
maturities of no more than one year, (b) commercial paper rated at least P-1 by
Moody's Investor Service, Inc. or A-1 by Standard & Poor's Corporation and with
maturities of no more than nine months from the date of acquisition thereof, (c)
short-term investments in the Eurodollar market through (i) any Lender, (ii) any
bank or trust company organized under the laws of the United States or any state
thereof and having capital surplus and undivided profits aggregating at least
$250,000,000, or (iii) any other Person acceptable to the Administrative Agent,
(d) short-term interest bearing deposits with any (i) Lender or (ii) any bank or
trust company organized under the laws of the United States or any state thereof
and having capital surplus and undivided profits aggregating at least
$250,000,000, (e) the purchase of Oil and Gas Properties or investments with
respect to and relating to the production of oil, gas and other liquid or
gaseous hydrocarbons from Oil and Gas Properties, or (f) investments by the
Borrower in the Partnerships in amounts not to exceed those required as capital
contributions under the applicable Partnership Agreements; provided, however, at
any time that a Default or Event of Default exists, no investment may be made in
any partnership or joint venture in which the Borrower is not, at such time, a
partner or joint venturer other than those formed pursuant to Registration
Statement No. 33-37983 on Form S-1 filed by the Borrower with the Securities and
Exchange Commission on November 28, 1990 (Swift Depositary Interests I), or (g)
Investments by the Borrower in Swift Energy Marketing Company which, together
with loans and advances permitted by Section 6.2(f) shall not exceed $6,000,000.
6.9 Lines of Business; Subsidiaries . Expand, on its own or through a
Subsidiary, into any line of business other than (a) those in which the Borrower
or such Subsidiary is engaged as of the date hereof and (b) other lines of
business related to the production of oil, gas and other hydrocarbons; or permit
any material change to be made in the character of its business as conducted as
of the date hereof.
6.10 ERISA Compliance. Permit any Plan maintained by it or any Partnership to
(a) engage in any "prohibited transaction" as such term is defined in Section
4975 of the Internal Revenue Code of 1954, as amended, (b) incur any
"accumulated funding deficiency," as such term is defined in Section 302 of
ERISA, or(c) terminate in a manner which could result in the imposition of a
Lien on any Property of the Borrower pursuant to Section 4068 of ERISA;
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assume an obligation to contribute to any Multi-employer Plan; or acquire any
Person or the assets of any Person which has now or has had at any time an
obligation to contribute to any Multi-employer Plan.
6.11 Sale or Discount of Receivables . Except to minimize losses on bona fide
debts previously contracted, discount or sell with recourse, or sell for less
than the greater of the face or market value thereof, any of its notes
receivable or accounts receivable.
6.12 Transactions With Affiliates . Enter into any transaction (including the
sale, lease or exchange of Property or the rendering of service), directly or
indirectly, with any of its Affiliates other than upon fair and reasonable terms
no less favorable than the Borrower could obtain in an arm's length transaction
with a Person which was not an Affiliate.
6.13 Tangible Net Worth . Permit Tangible Net Worth as of the close of any
fiscal quarter to be less than $86,589,159 plus 75% of positive Net Income and
100% of net proceeds from any equity offering for all fiscal periods ending
subsequent to September 30, 1998.
6.14 Current Ratio . Permit the ratio of Current Assets (plus Available
Commitment) to Current Liabilities to be at any time less than 1.1 to 1.0.
6.15 Debt Coverage Ratio . Permit the ratio for any fiscal quarter of Cash Flow
to Debt Service to be less than 1.00 to 1.00 at December 31, 1998, March 31,
1999, and June 30, 1999; 1.05 to 1.00 at September 30, 1999; 1.10 to 1.00 at
December 31, 1999; 1.15 to 1.00 at March 31, 2000; and 1.20 to 1.00 at June 30,
2000, and thereafter.
6.16 Total Liabilities to Tangible Net Worth . Permit the ratio of total
liabilities of the Borrower and its Subsidiaries on a consolidated basis to
Tangible Net Worth to be at any time greater than 3.0 to 1.0 from September 30,
1999 through June 30, 2000, 2.75 to 1.0 from September 30, 2000 through June 30,
2001, and 2.5 to 1.0 from September 30, 2001 to Final Maturity.
6.17 Amendment of Partnership Agreements . Amend or consent to the amendment of
any Partnership Agreement the effect of which may result in the diminution of
the Distributive Share with respect to the relevant Partnership or otherwise
adversely affect the interest of the Borrower in such Partnership or increase
the capital contribution of the Borrower with respect to such Partnership.
6.18 Subordinated Debt and Senior Subordinated Debt . Amend, extend or modify
any of the terms or provisions of any documents, notes, or agreements evidencing
or governing the Subordinated Debt and Senior Subordinated Debt or consent to
any of the foregoing; or at any time following the occurrence and during the
continuance of any Default or Event of Default, make any payment, whether in
cash or other Property, on or with respect to the Subordinated Debt.
6.19 Negative Pledges . Except pursuant to this Agreement, enter into or permit
to exist any agreement which prohibits or restricts the granting, incurring,
assuming, or permitting to exist any Lien on any of its Properties or provides
that any such occurrence shall constitute a default or breach of such agreement.
Notwithstanding the above, this shall not apply to the New Zealand property as
described on Exhibit IX.
6.20 Senior Subordinated Debt . The terms of the Senior Subordinated Debt shall
not deviate materially from the Prospectus Supplement draft dated July 6, 1999.
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ARTICLE 7
EVENTS OF DEFAULT
7.1 Enumeration of Events of Default . Any of the following events shall be
considered an Event of Default as that term is used herein:
(a) Default shall be made in the payment when due of any installment of
principal or interest under this Agreement or any Note or any fees or
other sums payable hereunder or under any other Loan Document;
(b) Default shall be made by the Borrower in the due observance or
performance of any covenant or agreement set forth in any of Sections
5.2 through 5.7 and such default shall continue for in excess of 15
days after the earlier of notice thereof by the Administrative Agent to
the Borrower or knowledge thereof by the Borrower, or default shall be
made by the Borrower in the due observance or performance of any other
covenant or agreement set forth in this Agreement or any other Loan
Document;
(c) Any representation or warranty made by any of the Borrower, its
Subsidiaries, or the Partnerships in this Agreement or any other Loan
Document proves to have been untrue in any material respect when made
or deemed to have been made, or any representation, warranty, statement
(including Financial Statements), certificate or data furnished or made
by any of the Borrower, its Subsidiaries, or the Partnerships to any
Lender or the Administrative Agent in connection herewith proves to
have been untrue in any material respect as of the date the facts
therein set forth were stated or certified;
(d) Default shall be made by any of the Borrower, its Subsidiaries, or the
Partnerships in the payment or performance of any bond, debenture,
note, security (as defined in the Securities Act of 1933, as amended),
or other evidence of Indebtedness, or under any credit agreement, loan
agreement, indenture, promissory note, or similar agreement or
instrument executed in connection with any of the foregoing, and such
default shall remain unremedied for in excess of the period of grace,
if any, with respect thereto, and the effect of such default is to
cause, or permit the holders of such Indebtedness or security to cause,
the acceleration of the maturity of any such Indebtedness or to permit
a trustee or holder of any security to elect (whether or not such
trustee or holder does elect) a majority of the directors on the board
of directors of any of the Borrower or its Subsidiaries;
(e) Any of the Borrower, its Subsidiaries, or the Partnerships shall (i)
apply for or consent to the appointment of a receiver, trustee, or
liquidator of it or all or a substantial part of its assets, (ii) file
a voluntary petition commencing an Insolvency Proceeding, (iii) make a
general assignment for the benefit of creditors, (iv) be unable, or
admit in writing its inability, to pay its debts generally as they
become due, or (v) file an answer admitting the material allegations of
a petition filed against it in any Insolvency Proceeding;
(f) An order, judgment or decree shall be entered against any of the
Borrower, its Subsidiaries, or the Partnerships by any court of
competent jurisdiction or by any other duly authorized authority, on
the petition of a creditor or
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otherwise, granting relief in any Insolvency Proceeding or approving a
petition seeking reorganization or an arrangement of its debts or
appointing a receiver, trustee, conservator, custodian, or liquidator
of it or all or any substantial part of its assets, and such order,
judgment, or decree shall not be dismissed or stayed within 30 days;
(g) Any of the Borrower, its Subsidiaries, or the Partnerships shall have
concealed, removed, or permitted to be concealed or removed, any part
of its Property, with intent to hinder, delay, or defraud its creditors
or any of them, made or suffered a transfer of any of its Property
which may be fraudulent under any bankruptcy, fraudulent conveyance, or
similar law and not otherwise permitted under the provisions of this
Agreement, or made any transfer of its Property to or for the benefit
of a creditor at a time when other creditors similarly situated have
not been paid;
(h) The levy against any significant portion of the Property of any of the
Borrower, its Subsidiaries, or the Partnerships or any execution,
garnishment, attachment, sequestration, or other writ or similar
proceeding which is not permanently dismissed or discharged within 60
days;
(i) A final and non-appealable order, judgment, or decree shall be entered
against any of the Borrower, its Subsidiaries, or the Partnerships for
money damages and/or Indebtedness due in an amount in excess of $50,000
and such order, judgment, or decree shall not be dismissed or stayed
within 60 days;
(j) The Borrower shall default in any of its material obligations as a
Partner under any Partnership Agreement; or
(k) If the Borrower has not executed the documents required by Section
3.1(f) in the time prescribed therein, it shall be an Event of Default.
7.2 Rights Upon Default . (a) Upon the occurrence of any Event of Default
specified in Sections 7.1 (e) or (f), immediately and without notice, (i) all
Obligations shall become due and payable, without presentment, demand, protest,
notice of protest or dishonor, notice of intent to accelerate maturity, notice
of acceleration of maturity or other notice of any kind, all of which are
expressly waived by the Borrower, (ii) the Commitments shall immediately
terminate unless and until the Lenders and the Administrative Agent shall
reinstate the same in writing, and with (iii) the oral consent of the Required
Lenders (confirmed promptly in writing), each Lender and the Administrative
Agent are hereby authorized at any time and from time to time, without notice to
the Borrower (any such notice being expressly waived by the Borrower), to
set-off and apply any and all deposits (general or special, time or demand,
provisional or final) held by such Lender or the Administrative Agent and any
and all other indebtedness at any time owing by such Lender or the
Administrative Agent to or for the credit or account of the Borrower against any
and all Obligations.
(b) Upon the occurrence of any other Event of Default, the Administrative
Agent may, or upon the request of the Required Lenders, the Administrative Agent
shall, declare all Obligations immediately due and payable, without presentment,
demand, protest, notice of protest or dishonor, notice of intent to accelerate
maturity, notice of acceleration of maturity or other notice of any kind, all of
which are hereby expressly waived by the Borrower, the Administrative Agent may,
or upon the request of the Required Lenders, the Administrative Agent shall,
declare the Commitments terminated, whereupon the Commitments shall immediately
terminate unless and until the Lenders and the Administrative Agent shall
reinstate
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the same in writing, and with the oral consent of the Required Lenders
(confirmed promptly in writing), the Administrative Agent and each Lender are
hereby authorized at any time and from time to time, without notice to the
Borrower (any such notice being expressly waived by the Borrower), to set-off
and apply any and all deposits (general or special, time or demand, provisional
or final) held by the Administrative Agent or such Lender and any and all other
indebtedness at any time owing by the Administrative Agent or such Lender to or
for the credit or account of the Borrower against any and all Obligations.
(c) In addition to the foregoing, upon the occurrence of any Event of Default,
each Lender and the Administrative Agent in accordance with the provisions of
this Agreement may exercise any or all of their rights and remedies provided by
law or pursuant to the Loan Documents.
ARTICLE 8
THE ADMINISTRATIVE AGENT
8.1 Appointment . Each Lender hereby designates and appoints the Administrative
Agent as the agent of such Lender under this Agreement and the other Loan
Documents. Each Lender authorizes the Administrative Agent, as the agent for
such Lender, to take such action on behalf of such Lender under the provisions
of this Agreement and the other Loan Documents and to exercise such powers and
perform such duties as are expressly delegated to the Administrative Agent by
the terms of this Agreement and the other Loan Documents, together with such
other powers as are reasonably incidental thereto. Notwithstanding any provision
to the contrary elsewhere in this Agreement or in any other Loan Document, the
Administrative Agent shall not have any duties or responsibilities except those
expressly set forth herein or in any other Loan Document or any fiduciary
relationship with any Lender; and no implied covenants, functions,
responsibilities, duties, obligations or liabilities on the part of the
Administrative Agent shall be read into this Agreement or any other Loan
Document or otherwise exist against the Administrative Agent.
8.1 Delegation of Duties . The Administrative Agent may execute any of its
duties under this Agreement and the other Loan Documents by or through agents or
attorneys-in-fact and shall be entitled to advice of counsel concerning all
matters pertaining to such duties. The Administrative Agent shall not be
responsible for the negligence or misconduct of any agents or attorneys-in-fact
selected by it with reasonable care.
8.3 Exculpatory Provisions . Neither the Administrative Agent nor any of its
officers, directors, employees, agents, attorneys-in-fact or affiliates shall be
required to initiate or conduct any litigation or collection proceedings
hereunder, except with the concurrence of the Required Lenders and contribution
by each Lender of its Percentage Share of costs reasonably expected by the
Administrative Agent to be incurred in connection therewith, liable for any
action lawfully taken or omitted to be taken by it or such Person under or in
connection with this Agreement or any other Loan Document (except for gross
negligence or willful misconduct of the Administrative Agent or such Person), or
responsible in any manner to any Lender for any recitals, statements,
representations or warranties made by the Borrower or any officer thereof
contained in this Agreement or any other Loan Document or in any certificate,
report, statement or other document referred to or provided for in, or received
by the Administrative Agent under or in connection with, this Agreement or any
other Loan Document, or for the value, validity, effectiveness, genuineness,
enforceability or sufficiency of this Agreement or any other Loan Document or
for any failure of the Borrower to perform its obligations hereunder or
thereunder. The Administrative Agent shall not be under any obligation to any
Lender to ascertain or to inquire as to the observance or performance of any of
the agreements contained in, or conditions of, this Agreement or any other Loan
Document, or to inspect the properties, books or records of the Borrower.
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8.4 Reliance by Administrative Agent . The Administrative Agent shall be
entitled to rely, and shall be fully protected in relying, upon any Note,
writing, resolution, notice, consent, certificate, affidavit, letter, cablegram,
telegram, telecopy, telex or teletype message, statement, order or other
document or conversation believed by it to be genuine and correct and to have
been signed, sent or made by the proper Person or Persons and upon advice and
statements of legal counsel (including counsel to the Borrower), independent
accountants and other experts selected by the Administrative Agent. The
Administrative Agent may deem and treat the payee of any Note as the owner
thereof for all purposes unless and until a written notice of assignment,
negotiation or transfer thereof shall have been received by the Administrative
Agent. The Administrative Agent shall be fully justified in failing or refusing
to take any action under this Agreement or any other Loan Document unless it
shall first receive such advice or concurrence of the Required Lenders or all
Lenders to the extent required by Section 9.2 as it deems appropriate and
contribution by each Lender of its Percentage Share of costs reasonably expected
by the Administrative Agent to be incurred in connection therewith. The
Administrative Agent shall in all cases be fully protected in acting, or in
refraining from acting, under this Agreement and the other Loan Documents in
accordance with a request of the Required Lenders or all Lenders to the extent
required by Section 9.2. Such request and any action taken or failure to act
pursuant thereto shall be binding upon the Lenders and all future holders of the
Notes. In no event shall the Administrative Agent be required to take any action
that exposes the Administrative Agent to personal liability or that is contrary
to any Loan Document or applicable Requirement of Law.
8.5 Notice of Default . The Administrative Agent shall not be deemed to have
knowledge or notice of the occurrence of any Default or Event of Default unless
the Administrative Agent has received notice from a Lender or the Borrower
referring to this Agreement, describing such Default or Event of Default and
stating that such notice is a "notice of default." In the event that the
Administrative Agent receives such a notice, the Administrative Agent shall give
notice thereof to the Lenders. The Administrative Agent shall take such action
with respect to such Default or Event of Default as shall be reasonably directed
by the Required Lenders; provided that unless and until the Administrative Agent
shall have received such directions, subject to the provisions of Section 7.2,
the Administrative Agent may (but shall not be obligated to) take such action,
or refrain from taking such action, with respect to such Default or Event of
Default as it shall deem advisable in the best interests of the Lenders. In the
event that the officer of the Administrative Agent primarily responsible for the
lending relationship with the Borrower or the officer of any Lender primarily
responsible for the lending relationship with the Borrower becomes aware that a
Default or Event of Default has occurred and is continuing, the Administrative
Agent or such Lender, as the case may be, shall use its good faith efforts to
inform the other Lenders and/or the Administrative Agent, as the case may be, of
such occurrence. Notwithstanding the preceding sentence, failure to comply with
the preceding sentence shall not result in any liability to the Administrative
Agent or any Lender.
8.6 Non-Reliance on Administrative Agent and Other Lenders . Each Lender
expressly acknowledges that neither the Administrative Agent nor any other
Lender nor any of their respective officers, directors, employees, agents,
attorneys-in-fact or affiliates has made any representation or warranty to such
Lender and that no act by the Administrative Agent or any other Lender hereafter
taken, including any review of the affairs of the Borrower, shall be deemed to
constitute any representation or warranty by the Administrative Agent or any
Lender to any other Lender. Each Lender represents to the Administrative Agent
that it has, independently and without reliance upon the Administrative Agent or
any other Lender, and based on such documents and information as it has deemed
appropriate, made its own appraisal of and investigation into the business,
operations, property, condition (financial and otherwise) and creditworthiness
of the Borrower and the value of the Properties of the Borrower and has made its
own decision to enter into this Agreement. Each Lender also represents that it
will,
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independently and without reliance upon the Administrative Agent or any other
Lender and based on such documents and information as it shall deem appropriate
at the time, continue to make its own credit analysis, appraisals and decisions
in taking or not taking action under this Agreement and the other Loan
Documents, and to make such investigation as it deems necessary to inform itself
as to the business, operations, property, condition (financial and otherwise)
and creditworthiness of the Borrower and the value of the Properties of the
Borrower. Except for notices, reports and other documents expressly required to
be furnished to the Lenders by the Administrative Agent hereunder, the
Administrative Agent shall not have any duty or responsibility to provide any
Lender with any credit or other information concerning the business, operations,
property, condition (financial and otherwise) or creditworthiness of the
Borrower or the value of the Properties of the Borrower which may come into the
possession of the Administrative Agent or any of its officers, directors,
employees, agents, attorneys-in-fact or affiliates.
8.7 Indemnification . EACH LENDER AGREES TO INDEMNIFY THE ADMINISTRATIVE AGENT
AND ITS OFFICERS, DIRECTORS, EMPLOYEES, AGENTS, ATTORNEYS-IN-FACT AND AFFILIATES
(TO THE EXTENT NOT REIMBURSED BY THE BORROWER AND WITHOUT LIMITING THE
OBLIGATION OF THE BORROWER TO DO SO), RATABLY ACCORDING TO THE PERCENTAGE SHARE
OF SUCH LENDER, FROM AND AGAINST ANY AND ALL LIABILITIES, CLAIMS, OBLIGATIONS,
LOSSES, DAMAGES, PENALTIES, ACTIONS, JUDGMENTS, SUITS, COSTS, EXPENSES AND
DISBURSEMENTS OF ANY KIND WHATSOEVER WHICH MAY AT ANY TIME (INCLUDING ANY TIME
FOLLOWING THE PAYMENT AND PERFORMANCE OF ALL OBLIGATIONS AND THE TERMINATION OF
THIS AGREEMENT) BE IMPOSED ON, INCURRED BY OR ASSERTED AGAINST THE
ADMINISTRATIVE AGENT OR ANY OF ITS OFFICERS, DIRECTORS, EMPLOYEES, AGENTS,
ATTORNEYS-IN-FACT OR AFFILIATES IN ANY WAY RELATING TO OR ARISING OUT OF THIS
AGREEMENT OR ANY OTHER LOAN DOCUMENT, OR ANY OTHER DOCUMENT CONTEMPLATED OR
REFERRED TO HEREIN OR THE TRANSACTIONS CONTEMPLATED HEREBY OR ANY ACTION TAKEN
OR OMITTED BY THE ADMINISTRATIVE AGENT OR ANY OF ITS OFFICERS, DIRECTORS,
EMPLOYEES, AGENTS, ATTORNEYS-IN-FACT OR AFFILIATES UNDER OR IN CONNECTION WITH
ANY OF THE FOREGOING, INCLUDING ANY LIABILITIES, CLAIMS, OBLIGATIONS, LOSSES,
DAMAGES, PENALTIES, ACTIONS, JUDGMENTS, SUITS, COSTS, EXPENSES AND DISBURSEMENTS
IMPOSED, INCURRED OR ASSERTED AS A RESULT OF THE NEGLIGENCE, WHETHER SOLE OR
CONCURRENT, OF THE ADMINISTRATIVE AGENT OR ANY OF ITS OFFICERS, DIRECTORS,
EMPLOYEES, AGENTS, ATTORNEYS-IN-FACT OR AFFILIATES; PROVIDED THAT NO LENDER
SHALL BE LIABLE FOR THE PAYMENT OF ANY PORTION OF SUCH LIABILITIES, OBLIGATIONS,
LOSSES, DAMAGES, PENALTIES, ACTIONS, JUDGMENTS, SUITS, COSTS, EXPENSES OR
DISBURSEMENTS RESULTING SOLELY FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT
OF THE ADMINISTRATIVE AGENT OR ANY OF ITS OFFICERS, DIRECTORS, EMPLOYEES,
AGENTS, ATTORNEYS-IN-FACT OR AFFILIATES. THE AGREEMENTS IN THIS SECTION SHALL
SURVIVE THE PAYMENT AND PERFORMANCE OF ALL OBLIGATIONS AND THE TERMINATION OF
THIS AGREEMENT.
8.8 Restitution . Should the right of the Administrative Agent or any Lender to
realize funds with respect to the Obligations be challenged and any application
of such funds to the Obligations be reversed, whether by Governmental Authority
or otherwise, or should the Borrower otherwise be entitled to a refund or return
of funds distributed to the Lenders in connection with the Obligations, the
Administrative Agent or such Lender, as the case may be, shall promptly notify
the Lenders of such fact. Not later than Noon, Central Standard or Daylight
Savings Time, as the case may be, of the Business Day following such notice,
each Lender shall pay to the Administrative Agent an amount equal to the ratable
share of such Lender of the funds required to be returned to the Borrower. The
ratable share of each Lender shall be determined on the basis of the percentage
of the payment all or a portion of which is required to be refunded originally
distributed to such Lender, if such percentage can be determined, or, if such
percentage cannot be determined, on the basis of the Percentage Share of such
Lender. The
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Administrative Agent shall forward such funds to the Borrower or to the Lender
required to return such funds. If any such amount due to the Administrative
Agent is made available by any Lender after Noon, Central Standard or Daylight
Savings Time, as the case may be, of the Business Day following such notice,
such Lender shall pay to the Administrative Agent (or the Lender required to
return funds to the Borrower, as the case may be) for its own account interest
on such amount at a rate equal to the Federal Funds Rate for the period from and
including the date on which restitution to the Borrower is made by the
Administrative Agent (or the Lender required to return funds to the Borrower, as
the case may be) to but not including the date on which such Lender failing to
timely forward its share of funds required to be returned to the Borrower shall
have made its ratable share of such funds available.
8.9 Administrative Agent in Its Individual Capacity . The Administrative Agent
and its affiliates may make loans to, accept deposits from and generally engage
in any kind of business with the Borrower as though the Administrative Agent
were not the agent hereunder. With respect to any Note issued to the Lender
serving as the Administrative Agent, the Administrative Agent shall have the
same rights and powers under this Agreement as a Lender and may exercise such
rights and powers as though it were not the Administrative Agent. The terms
"Lender" and "Lenders" shall include the Administrative Agent in its individual
capacity.
8.10 Successor Administrative Agent . The Administrative Agent may resign as
Administrative Agent upon ten days' notice to the Lenders and the Borrower. If
the Administrative Agent shall resign as Administrative Agent under this
Agreement and the other Loan Documents, Lenders for which the Percentage Shares
aggregate at least 66-2/3% shall appoint from among the Lenders a successor
agent for the Lenders, whereupon such successor agent shall succeed to the
rights, powers and duties of the Administrative Agent. The term "Administrative
Agent" shall mean such successor agent effective upon its appointment. The
rights, powers and duties of the former Administrative Agent as Administrative
Agent shall be terminated, without any other or further act or deed on the part
of such former Administrative Agent or any of the parties to this Agreement or
any holders of the Notes. After the removal or resignation of any Administrative
Agent hereunder as Administrative Agent, the provisions of this Article and
Sections 5.12, 5.14, and 5.15 shall inure to its benefit as to any actions taken
or omitted to be taken by it while it was Administrative Agent under this
Agreement and the other Loan Documents.
8.11 Applicable Parties . The provisions of this Article 8 are solely for the
benefit of the Administrative Agent and the Lenders, and the Borrower shall not
have any rights as a third party beneficiary or otherwise under any of the
provisions of this Article. In performing functions and duties hereunder and
under the other Loan Documents, the Administrative Agent shall act solely as the
agent of the Lenders and does not assume, nor shall it be deemed to have
assumed, any obligation or relationship of trust or agency with or for the
Borrower or any legal representative, successor and assign of the Borrower. The
Documenting Agent and the Syndication Agent have no duties hereunder.
ARTICLE 9
MISCELLANEOUS
9.1 Assignments; Participations . (a) The Borrower may not assign any of its
rights or obligations under any Loan Document without the prior consent of the
Administrative Agent and all of the Lenders.
(b) With the consent of the Administrative Agent (which shall not be
unreasonably withheld), any Lender may assign to one or more assignees all or a
portion of its rights and obligations under this Agreement pursuant to an
Assignment Agreement. Any such
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assignment shall be in the amount of at least $10,000,000 (or any whole multiple
of $1,000,000 in excess thereof). Any such assignment shall become effective
upon the execution and delivery to the Administrative Agent of the Assignment
Agreement and the consent of the Administrative Agent. Promptly following
receipt of an executed Assignment Agreement, the Administrative Agent shall send
to the Borrower a copy of such executed Assignment Agreement. Promptly following
receipt of such executed Assignment Agreement, the Borrower shall execute and
deliver, at its own expense, new Notes to the assignee and, if applicable, the
assignor, in accordance with their respective interests, whereupon the prior
Notes of the assignor and, if applicable, the assignee, shall be canceled and
returned to the Borrower. Upon the effectiveness of any assignment pursuant to
this Section , the assignee will become a "Lender," if not already a "Lender,"
for all purposes of the Loan Documents, and the assignor shall be relieved of
its obligations hereunder to the extent of such assignment. If the assignor no
longer holds any rights or obligations under this Agreement, such assignor shall
cease to be a "Lender" hereunder, except that its rights under Sections , 5.13,
and 5.16 shall not be affected. On the last Business Day of each month during
which an assignment has become effective pursuant to this Section , the
Administrative Agent shall prepare a new Exhibit V giving effect to all such
assignments effected during such month and will promptly provide a copy thereof
to the Borrower and each Lender.
(c) Each Lender may transfer, grant, or assign participations in all or any
portion of its interests hereunder to any Person pursuant to this Section ,
provided that such Lender shall remain a "Lender" for all purposes of this
Agreement and the transferee of such participation shall not constitute a
"Lender" hereunder. In the case of any such participation, the participant shall
not have any rights under any Loan Document, the rights of the participant in
respect of such participation to be against the granting Lender as set forth in
the agreement with such Lender creating such participation, and all amounts
payable by the Borrower hereunder shall be determined as if such Lender had not
sold such participation.
(d) The Lenders may furnish any information concerning the Borrower in the
possession of the Lenders from time to time to assignees and participants and
prospective assignees and participants.
(e) Notwithstanding anything in this Section to the contrary, any Lender may
assign and pledge all or any of its Notes or any interest therein to any Federal
Reserve Bank or the United States Treasury as collateral security pursuant to
Regulation A of the Board of Governors of the Federal Reserve System and any
operating circular issued by such Federal Reserve System and/or such Federal
Reserve Bank. No such assignment or pledge shall release the assigning or
pledging Lender from its obligations hereunder.
(f) Notwithstanding any other provisions of this Section, no transfer or
assignment of the interests or obligations of any Lender or grant of
participations therein shall be permitted if such transfer, assignment, or grant
would require the Borrower to file a registration statement with the Securities
and Exchange Commission or any successor Governmental Authority or qualify the
Loans under the "Blue Sky" laws of any state.
9.2 Amendments and Waivers . Neither this Agreement nor any of the other Loan
Documents nor any terms hereof or thereof may be amended, supplemented or
modified except in accordance with the provisions of this Section. The
Administrative Agent and the Borrower may, with the written consent of the
Required Lenders, from time to time, enter into written amendments, supplements
or modifications to the Loan Documents for the purpose of adding any provisions
to this Agreement or the other Loan Documents or changing in any manner the
rights of the Lenders or the Borrower hereunder or thereunder or waiving, on
such terms and conditions as the Administrative Agent may specify in such
instrument, any of the requirements of this Agreement or the other Loan
Documents or any Default or Event of Default
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and its consequences; provided, however, that no such amendment, supplement,
modification or waiver shall extend the time of payment of any Note or any
installment thereof, reduce the rate or extend the time of payment of interest
thereon, extend the Commitment Termination Date or Final Maturity, reduce or
extend the time of payment of any fee payable to the Lenders hereunder, reduce
the principal amount of the Obligations, release any Collateral in excess of
that allowed by Section 6.4, change the Percentage Share of any Lender or the
definition of the Facility Amount or the Borrowing Base, amend, modify or waive
any provision of this Section or Section 2.11, 3.2, 3.3, 5.12, 5.15 or 8.10 or
any other provision applicable to the determination of the Borrowing Base,
change the percentage specified in the definition of Required Lenders, or
consent to the assignment or transfer by the Borrower of any of its rights or
obligations under this Agreement or the other Loan Documents, in any such case
without the written consent of all Lenders, amend, modify or waive any provision
of Article 8 or the rights or obligations of the Administrative Agent without
the written consent of the Administrative Agent, or amend, modify or waive any
provision of Section 2.20 or the rights or obligations of the Administrative
Agent as the issuer of Letters of Credit without the written consent of the
Administrative Agent. Any such amendment, supplement, modification or waiver
shall apply equally to each of the Lenders and shall be binding upon the
Borrower, the Lenders, the Administrative Agent, and all future holders of the
Notes. In the event of any waiver, the Borrower, the Lenders, and the
Administrative Agent shall be restored to their respective former positions and
rights hereunder and under the other Loan Documents, and any Default or Event of
Default waived shall be deemed to be cured and not continuing; but no such
waiver shall extend to any subsequent or other Default or Event of Default or
impair any right with respect thereto. Neither this Agreement nor any provision
hereof may be changed, waived, discharged or terminated orally, but only by an
instrument in writing signed by the party against whom enforcement of the
change, waiver, discharge or termination is sought.
9.3 Survival of Representations, Warranties and Covenants . All representations
and warranties of the Borrower and all covenants and agreements herein made
shall survive the execution and delivery of the Notes and this Agreement and
shall remain in force and effect so long as any Obligation remains outstanding
or any Commitment exists.
9.4 Notices and Other Communications . Except as to oral notices expressly
authorized herein, which oral notices shall be confirmed in writing, all
notices, requests, and communications hereunder shall be in writing (including
by telecopy). Unless otherwise expressly provided herein, any such notice,
request, demand, or other communication shall be deemed to have been duly given
or made when delivered by hand, or, in the case of delivery by mail, two
Business Days after deposited in the mail, certified mail, return receipt
requested, postage prepaid, or, in the case of telecopy notice, when receipt
thereof is acknowledged orally or by written confirmation report, addressed to
each party at the "Address for Notices" specified below its name on the
signature pages hereof or at such other address as shall be designated by such
party in a properly given notice; provided, that notice, request or
communication to or upon the Administrative Agent pursuant to Section 2.1(a) or
Section 2.2(a) shall not be effective until actually received.
9.5 Parties in Interest . All covenants and agreements herein contained by or on
behalf of the Borrower, the Lenders, and the Administrative Agent shall be
binding upon and inure to the benefit of the Borrower, the Lenders, or the
Administrative Agent, as the case may be, and their respective legal
representatives, successors and assigns.
9.6 No Waiver; Rights Cumulative . No course of dealing on the part of any
Lender or the Administrative Agent or the officers or employees of any Lender or
the Administrative Agent, nor any failure or delay by any Lender or the
Administrative Agent with respect to exercising any of their rights, powers or
privileges under this Agreement or any other Loan Document shall operate as a
waiver thereof. The rights and remedies of the Lenders and
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the Administrative Agent under this Agreement and the other Loan Documents shall
be cumulative, and the exercise or partial exercise of any such right or remedy
shall not preclude the exercise of any other right or remedy. No making of a
Loan or issuance of a Letter of Credit shall constitute a waiver of any of the
covenants or warranties of the Borrower contained herein or of any of the
conditions to the obligation of the Lenders to make other Loans or the
Administrative Agent to issue other Letters of Credit hereunder. In the event
the Borrower is unable to satisfy any such covenant, warranty or condition, no
such Loan shall have the effect of precluding the Administrative Agent from
thereafter declaring such inability to be an Event of Default as hereinabove
provided.
9.7 Survival Upon Unenforceability . In the event any one or more of the
provisions contained in this Agreement or any other Loan Document shall, for any
reason, be held to be invalid, illegal or unenforceable in any respect, such
invalidity, illegality or unenforceability shall not affect any other provision
hereof or of any other Loan Document.
9.8 Rights of Third Parties . All provisions herein are imposed solely and
exclusively for the benefit of the Lenders, the Administrative Agent, and the
Borrower; and no other Person shall have standing to require satisfaction of
such provisions in accordance with their terms or be entitled to assume that the
Lenders will refuse to make Loans or the Administrative Agent will refuse to
issue Letters of Credit in the absence of strict compliance with any or all of
such provisions; and any or all of such provisions may, subject to the
provisions of Section 9.2 as to the rights of the Lenders, be freely waived in
whole or in part by the Administrative Agent at any time if in its sole
discretion it deems it advisable to do so.
9.9 Controlling Agreement . In the event of a conflict between the provisions
of this Agreement and those of any other Loan Document, the provisions of this
Agreement shall control.
9.10 Integration . THIS AGREEMENT AMENDS, RESTATES, AND REPLACES THE EXISTING
CREDIT AGREEMENT AND CONSTITUTES THE ENTIRE AGREEMENT AMONG THE PARTIES HERETO
WITH RESPECT TO THE SUBJECT HEREOF. THIS AGREEMENT SUPERSEDES ANY PRIOR
AGREEMENT AMONG THE PARTIES HERETO, WHETHER WRITTEN OR ORAL, RELATING TO THE
SUBJECT HEREOF. THIS AGREEMENT AND THE OTHER WRITTEN LOAN DOCUMENTS REPRESENT,
COLLECTIVELY, THE FINAL AGREEMENT AMONG THE PARTIES THERETO AND MAY NOT BE
CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS
OF SUCH PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.
9.11 Jurisdiction and Venue . ALL ACTIONS OR PROCEEDINGS WITH RESPECT TO,
ARISING DIRECTLY OR INDIRECTLY IN CONNECTION WITH, OUT OF, RELATED TO, OR FROM
THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT MAY BE LITIGATED, AT THE SOLE
DISCRETION AND ELECTION OF THE ADMINISTRATIVE AGENT, IN COURTS HAVING SITUS IN
HOUSTON, HARRIS COUNTY, TEXAS. THE BORROWER HEREBY SUBMITS TO THE JURISDICTION
OF ANY LOCAL, STATE, OR FEDERAL COURT LOCATED IN HOUSTON, HARRIS COUNTY, TEXAS,
AND HEREBY WAIVES ANY RIGHTS IT MAY HAVE TO TRANSFER OR CHANGE THE JURISDICTION
OR VENUE OF ANY LITIGATION BROUGHT AGAINST IT BY THE ADMINISTRATIVE AGENT OR ANY
LENDER IN ACCORDANCE WITH THIS SECTION.
9.12 Waiver of Rights to Jury Trial . THE BORROWER, THE ADMINISTRATIVE AGENT,
AND EACH LENDER HEREBY KNOWINGLY, VOLUNTARILY, INTENTIONALLY, IRREVOCABLY, AND
UNCONDITIONALLY WAIVE ALL RIGHTS TO TRIAL BY JURY IN ANY ACTION, SUIT,
PROCEEDING, COUNTERCLAIM, OR OTHER LITIGATION THAT RELATES TO OR ARISES OUT OF
ANY OF THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT OR THE ACTS OR OMISSIONS OF THE
ADMINISTRATIVE AGENT OR ANY LENDER IN THE ENFORCEMENT OF ANY OF THE TERMS
57
117
<PAGE>
OR PROVISIONS OF THIS AGREEMENT OR ANY OTHER LOAN DOCUMENT OR OTHERWISE WITH
RESPECT THERETO. THE PROVISIONS OF THIS SECTION ARE A MATERIAL INDUCEMENT FOR
THE ADMINISTRATIVE AGENT AND THE LENDERS ENTERING INTO THIS AGREEMENT.
9.13 Governing Law . THIS AGREEMENT AND THE NOTES SHALL BE DEEMED TO BE
CONTRACTS MADE UNDER AND SHALL BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY
THE LAWS OF THE STATE OF TEXAS WITHOUT GIVING EFFECT TO PRINCIPLES THEREOF
RELATING TO CONFLICTS OF LAW; PROVIDED, HOWEVER, THAT VERNON'S TEXAS CIVIL
STATUTES, ARTICLE 5069, CHAPTER 15 (WHICH REGULATES CERTAIN REVOLVING CREDIT
LOAN ACCOUNTS AND REVOLVING TRIPARTY ACCOUNTS) SHALL NOT APPLY.
9.14 Counterparts . For the convenience of the parties, this Agreement may be
executed in multiple counterparts and by different parties hereto in separate
counterparts, each of which when so executed shall be deemed to be an original
and all of which together shall constitute one and the same agreement.
IN WITNESS WHEREOF, this Agreement is executed effective as of the date
first above written.
BORROWER:
SWIFT ENERGY COMPANY
By
-------------------
John R. Alden
Senior Vice President
Address for Notices:
Swift Energy Corporation
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Attention: John R. Alden
Telecopy: (713) 874-2701
58
118
<PAGE>
ADMINISTRATIVE AGENT AND LENDER:
BANK ONE, TEXAS, NATIONAL
ASSOCIATION
By:
--------------------
Charles Kingswell-Smith
First Vice President
Applicable Lending Office
for Floating Rate Loans and
LIBO Rate Loans:
910 Travis
Houston, Texas 77002
Address for Notices:
Bank One, Texas, National Association
910 Travis
Houston, Texas 77002
Attention: Charles Kingswell-Smith
Telecopy: (713) 751-3544
59
119
<PAGE>
Exhibit 12
120
<PAGE>
SWIFT ENERGY COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
Twelve Months Ended December 31,
--------------------------------
1999 1998 1997
------------------- ----------------- -----------------
<S> <C> <C> <C>
GROSS G&A 20,518,843 21,010,960 20,098,383
NET G&A 4,497,400 3,853,812 3,523,604
INTEREST EXPENSE 14,442,815 8,752,195 5,032,952
RENT EXPENSE 1,272,497 1,117,351 1,039,210
NET INCOME BEFORE TAXES 29,736,151 (73,391,581) 33,129,606
CAPITALIZED INTEREST 4,142,098 3,849,665 2,326,691
DEPLETED CAPITALIZED INTEREST 323,124 292,267 201,169
CALCULATED DATA
--------------------------------------------------------
UNALLOCATED G&A (%) 21.92% 18.34% 17.53%
NON-CAPITAL RENT EXPENSE 278,911 204,944 182,192
1/3 NON-CAPITAL RENT EXPENSE 92,970 68,315 60,731
FIXED CHARGES 18,677,883 12,670,175 7,420,374
EARNINGS 44,595,061 (64,278,804) 38,424,458
RATIO OF EARNINGS TO FIXED CHARGES 2.39 --- 5.18
=================== ================= =================
</TABLE>
For purposes of calculating the ratio of earnings to fixed charges,
fixed charges include interest expense, capitalized interest, amortization
of debt issuance costs and discounts, and that portion of non-capitalized
rental expense deemed to be the equivalent of interest. Earnings
represents income before income taxes from continuing operations before
fixed charges. Due to the $90.8 million non-cash charge incurred in the
third quarter of 1998 caused by a write-down in the carrying value of oil
and gas properties, nine months ended September 30, 1998 earnings are
insufficient by $80.6 million to cover fixed charges in this period. If
the $90.8 million non-cash charge is excluded, the ratio of earnings to
fixed charges would have been 2.22 for the nine months ended September 30,
1998.
121
<PAGE>
EXHIBIT 23 (A)
122
<PAGE>
CONSENT OF H.J. GRUY AND ASSOCIATES, INC.
We hereby consent to the use of the name H.J. Gruy and Associates, Inc. and of
references to H.J. Gruy and Associates, Inc. and to the inclusion of and
references to our report dated February 9, 2000, (Year-End 1999 Reserves Audit)
prepared for Swift Energy Company in the Swift Energy Company Annual Report on
Form 10-K for the year ended December 31, 1999.
H.J. GRUY AND ASSOCIATES, INC.
by: s/b Marilyn Wilson
------------------------------
Marilyn Wilson
President & Chief Operating Officer
March 24, 2000
Houston, Texas
D:\S\SWIFT\CONSENTS\CONSENT.3-00.doc
123
<PAGE>
EXHIBIT 23 (B)
124
<PAGE>
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated February 9, 2000, included in the annual report of Swift Energy
Company on Form 10-K for the year ended December 31, 1999, into Swift Energy
Company's previously filed Registration Statement File Numbers 33-14305,
33-36310, 33-80228, and 33-80240 on Form S-8 and Number 33-81651 on Form S-3.
ARTHUR ANDERSEN LLP
125
Houston, Texas
March 28, 2000
<PAGE>
EXHIBIT 99
126
<PAGE>
February 9, 2000
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Re: Year-End 1999
Reserves Audit
99-003-148
Gentlemen:
At your request, we have independently audited the estimates of reserves and
future net cash flows as of December 31, 1999, that Swift Energy Company (Swift)
attributes to net interests owned by Swift. Based on our audit, we consider the
Swift estimates of net reserves and net cash flows, in the aggregate, to be in
reasonable agreement with those estimates that would result if we performed a
completely independent evaluation effective December 31, 1999.
The estimated net reserves, future net cash flow, and discounted future net cash
flow are summarized below:
<TABLE>
<CAPTION>
Estimated Estimated
Net Reserves Future Net Cash Flow
---------------------------------- ----------------------------------------
Oil & Discounted
Condensate Gas at 10%
(Barrels) (Mcf) Nondiscounted Per Year
-------------- ----------- ------------------ -----------------
<S> <C> <C> <C> <C>
Proved Developed 8,437,299 174,046,096 $ 444,492,726 $ 301,199,660
Proved Undeveloped 12,368,964 155,913,654 $ 416,716,419 $ 262,854,849
-------------- ----------- ------------------ -----------------
Total Proved 20,806,263 329,959,750 $ 861,209,145 $ 564,054,509
G & A $ (6,690,416) $ (3,835,854)
-------------- ----------- ------------------ -----------------
TOTAL 20,806,263 329,959,750 $ 854,518,729 $ 560,218,655
</TABLE>
The discounted future net cash flows summarized in the above table are computed
using a discount rate of 10 percent per annum. The reserves included in the
Swift estimates conform to the Petroleum Reserves Definitions approved by the
Society of Petroleum Engineers, Inc. The definitions are included as Attachment
I. The reserves discussed herein are estimates only and should not be construed
as exact quantities. Future conditions may affect recovery of estimated reserves
and cash flows, and reserves of all categories may be subject to revision as
more performance data become available.
127
<PAGE>
Swift represents that the future net cash flows discussed herein were computed
based on prices received for oil and natural gas as of December 31, 1999. Those
values reflect accounting for adjustments related to transportation, geographic
property location, and quality or energy content. Product prices, direct
operating costs, and future capital expenditures are not escalated and therefore
remain constant for the projected life of each property.
This audit has been conducted according to the Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserve Information approved by the Board
of Directors of the Society of Petroleum Engineers, Inc. Our audit included
examination, on a test basis, of the evidence supporting the reserves discussed
herein. We have reviewed the subject properties, and where we had material
disagreements with the Swift reserve estimates, Swift revised its estimate to be
in agreement. In conducting our audit, we investigated each property to the
level of detail that we believe necessary to provide a reasonable basis for the
judgements expressed herein.
Based on our investigations, it is our judgement that Swift used appropriate
engineering, geologic, and evaluation principles and methods that are consistent
with practices generally accepted in the petroleum industry. Reserve estimates
were based on extrapolation of established performance trends, material balance
calculations, volumetric calculations, analogy with the performance of
comparable wells, or a combination of these methods. Reserve estimates from
volumetric calculations or from analogies are often less certain than reserve
estimates based on well performance obtained over a period during which a
substantial portion of the reserve was produced.
Estimates of net cash flow and discounted net cash flow should not be
interpreted to represent the fair market value for the audited reserves. The
estimated reserves discussed herein have not been adjusted for uncertainty.
Future net cash flow as presented herein is defined as the future cash inflow
attributable to the evaluated interest less, if applicable, future direct
operating costs, ad valorem taxes, and future capital expenditures. Future cash
inflow is defined as gross cash inflow less, if applicable, royalties and
severance taxes. Future cash inflow and future net cash flow stated in this
report exclude consideration of state or federal income tax. Future costs of
abandoning the facilities and wells, and the restoration of producing properties
to satisfy environmental standards are not deducted from cash flow.
In conducting this audit, we relied on data supplied by Swift. The extent and
character of ownership, oil and natural gas sales prices, direct operating
costs, future capital expenditures, historical production, accounting,
geological, and engineering data were accepted as represented. No independent
well tests, property inspections, or audits of operating expenses were conducted
by our staff in conjunction with this work. We did not verify or determine the
extent, character, status, or liability, if any, of gas imbalances or any
current or possible future detrimental environmental site conditions.
In order to audit the reserves and future cash flows estimated by Swift, we have
relied in part on geological, engineering, and economic data furnished by our
client. Although we have made a best efforts attempt to acquire all pertinent
data and to analyze it carefully with methods accepted by the petroleum
industry, there is no guarantee that the volumes of hydrocarbons or the cash
flows projected will be realized. The reserve and cash flow projections
discussed in this report may require revision as additional data become
available.
If investments or business decisions are to be made in reliance on these
judgements by anyone other than our client, such person, with the approval of
our client, is invited to visit our offices at his expense so that he can
evaluate the assumptions made and the completeness and extent of the data
available on which our opinions are based.
Any distribution or publication of this work or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
by:
--------------------------------
Marilyn Wilson, PE
President and Chief Operating Officer
Attachment
MW:cjd
128
<PAGE>
ATTACHMENT I
129
<PAGE>
PETROLEUM RESERVES DEFINITIONS
SOCIETY OF PETROLEUM ENGINEERS (SPE) AND WORLD PETROLEUM CONGRESS (WPC)1
Reserves are those quantities of petroleum which are anticipated to be
commercially recovered from known accumulations from a given date forward. All
reserve estimates involve some degree of uncertainty. The uncertainty depends
chiefly on the amount of reliable geologic and engineering data available at the
time of the estimate and the interpretation of these data. The relative degree
of uncertainty may be conveyed by placing reserves into one of two principal
classifications, either proved or unproved. Unproved reserves are less certain
to be recovered than proved reserves and may be further sub-classified as
probable and possible reserves to denote progressively increasing uncertainty in
their recoverability.
The intent of the SPE and WPC in approving additional classifications beyond
proved reserves is to facilitate consistency among professionals using such
terms. In presenting these definitions, neither organization is recommending
public disclosure of reserves classified as unproved. Public disclosure of the
quantities classified as unproved reserves is left to the discretion of the
countries or companies involved.
Estimation of reserves is done under conditions of uncertainty. The method of
estimation is called deterministic if a single best estimate of reserves is made
based on known geological, engineering and economic data. The method of
estimation is called probabilistic when the known geological, engineering, and
economic data are used to generate a range of estimates and their associated
probabilities. Identifying reserves as proved, probable, and possible has been
the most frequent classification method and gives an indication of the
probability of recovery. Because of potential differences in uncertainty,
caution should be exercised when aggregating reserves of different
classifications.
Reserves estimates will generally be revised as additional geologic or
engineering data become available or as economic conditions change. Reserves do
not include quantities of petroleum being held in inventory, and may be reduced
for usage of processing losses if required for financial reporting.
Reserves may be attributed to either natural energy or improved recovery
methods. Improved recovery methods include all methods for supplementing natural
energy or altering natural forces in the reservoir to increase ultimate
recovery. Examples of such methods are pressure maintenance, cycling,
waterflooding, thermal methods, chemical flooding, and the use of miscible and
immiscible displacement fluids. Other improved recovery methods may be developed
in the future as petroleum technology continues to evolve.
PROVED RESERVES
Proved reserves are those quantities of petroleum which, by analysis of
geological and engineering data, can be estimated with reasonable certainty to
be commercially recoverable, from a given date forward, from known reservoirs
and under current economic conditions, operating methods, and government
regulations. Proved reserves can be categorized as developed or undeveloped.
If deterministic methods are used, the term reasonable certainty is intended to
express a high degree of confidence that the quantities will be recovered. If
probabilistic methods are used, there should be at least a 90% probability that
the quantities actually recovered will equal or exceed the estimate.
Establishment of current economic conditions should include relevant historical
petroleum prices and associated costs and may involve an averaging period that
is consistent with the purpose of the reserve estimate, appropriate contract
obligations, corporate procedures, and government regulations involved in
reporting these reserves.
In general, reserves are considered proved if the commercial producibility of
the reservoir is supported by actual production or formation tests. In this
context, the term proved refers to the actual quantities of petroleum reserves
and not just the productivity of the well or reservoir. In certain cases, proved
reserves may be assigned on the basis of well logs and/or core analysis that
indicate the subject reservoir is hydrocarbon bearing and is analogous to
reservoirs in the same area that are producing or have demonstrated the ability
to produce on formation tests.
The area of the reservoir considered as proved includes (1) the area delineated
by drilling and defined by fluid contacts, if any, and (2) the undrilled
portions of the reservoir that can reasonably be judged as commercially
productive on the basis of available geological and engineering data. In the
absence of data on fluid contacts, the lowest known occurrence of hydrocarbons
controls the proved limit unless otherwise indicated by definitive geological,
engineering or performance data.
- ---------------------------
(1) Approved by the Board of Directors, Society of Petroleum Engineers (SPE),
Inc. on March 7, 1997.
130
<PAGE>
Reserves may be classified as proved if facilities to process and transport
those reserves to market are operational at the time of the estimate or there is
a reasonable expectation that such facilities will be installed. Reserves in
undeveloped locations may be classified as proved undeveloped provided (1) the
locations are direct offsets to wells that have indicated commercial production
in the objective formation, (2) it is reasonably certain such locations are
within the known proved productive limits of the objective formation, (3) the
locations conform to existing well spacing regulations where applicable, and (4)
it is reasonably certain the locations will be developed. Reserves from other
locations are categorized as proved undeveloped only where interpretations of
geological and engineering data from wells indicate with reasonable certainty
that the objective formation is laterally continuous and contains commercially
recoverable petroleum at locations beyond direct offsets.
Reserve which are to be produced through the application of established improved
recovery methods are included in the proved classification when (1) successful
testing by a pilot project or favorable response of an installed program in the
same or an analogous reservoir with similar rock and fluid properties provides
support for the analysis on which the project was based, and, (2) it is
reasonably certain that project will proceed. Reserves to be recovered by
improved recovery methods that have yet to be established through commercially
successful applications are included in the proved classification only (1) after
a favorable production response from the subject reservoir from either (a) a
representative pilot or (b) an installed program where the response provides
support for the analysis on which the project is based and (2) it is reasonably
certain the project will proceed.
UNPROVED RESERVES
Unproved reserves are based on geologic and/or engineering data similar to that
used in estimates of proved reserves; but technical, contractual, economic, or
regulatory uncertainties preclude such reserves being classified as proved.
Unproved reserves may be further classified as probable reserves and possible
reserves.
Unproved reserves may be estimated assuming future economic conditions different
from those prevailing at the time of the estimate. The effect of possible future
improvements in economic conditions and technological developments can be
expressed by allocating appropriate quantities of reserves to the probable and
possible classifications.
PROBABLE RESERVES
Probable reserves are those unproved reserves which analysis of geological and
engineering data suggests are more likely than not to be recoverable. In this
context, when probabilistic methods are used, there should be a least a 50%
probability that the quantities actually recovered will equal or exceed the sum
of estimated proved plus probable reserves.
In general, probable reserves may include (1) reserves anticipated to be proved
by normal step-out drilling where subsurface control is inadequate to classify
these reserves as proved, (2) reserves in formations that appear to be
productive based on well log characteristics but lack core data or definitive
tests and which are not analogous to producing or proved reservoirs in the area,
(3) incremental reserves attributable to infill drilling that could have been
classified as proved if closer statutory spacing had been approved at the time
of the estimate, (4) reserves attributable to improved recovery methods that
have been established by repeated commercially successful applications when (a)
a project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir characteristics appear favorable for commercial application, (5)
reserves in an area of the formation that appears to be separated from the
proved area by faulting and the geologic interpretation indicates the subject
area is structurally higher than the proved area, (6) reserves attributable to a
future workover, treatment, re-treatment, change of equipment, or other
mechanical procedures, where such procedure has not been proved successful in
wells which exhibit similar behavior in analogous reservoirs, and (7)
incremental reserves in proved reservoirs where an alternative interpretation of
performance or volumetric data indicates more reserves than can be classified as
proved.
POSSIBLE RESERVES
Possible reserves are those unproved reserves which analysis of geological and
engineering data suggests are less likely to be recoverable than probable
reserves. In this context, when probabilistic methods are used, there should be
a least a 10% probability that the quantities actually recovered will equal or
exceed the sum of estimated proved plus probable plus possible reserves.
In general, possible reserves may include (1) reserves which, based on
geological interpretations, could possibly exist beyond areas classified as
probable, (2) reserves in formations that appear to be petroleum bearing based
131
<PAGE>
on log and core analysis but may not be productive at commercial rates, (3)
incremental reserves attributed to infill drilling that are subject to technical
uncertainty, (4) reserves attributed to improved recovery methods when (a) a
project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir characteristics are such that a reasonable doubt exists that the
project will be commercial, and (5) reserves in an area of the formation that
appears to be separated from the proved area by faulting and geological
interpretation indicates the subject area is structurally lower than the proved
area.
RESERVE STATUS CATEGORIES
Reserve status categories define the development and producing status of wells
and reservoirs.
Developed: Developed reserves are expected to be recovered from existing
wells including reserves behind pipe. Improved recovery reserves are
considered developed only after the necessary equipment has been installed,
or when the costs to do so are relatively minor. Developed reserves may be
sub-categorized as producing or non-producing.
Producing: Reserves subcategorized as producing are expected to be
recovered from completion intervals which are open and producing at the
time of the estimate. Improved recovery reserves are considered
producing only after the improved recovery project is in operation.
Non-producing: Reserves subcategorized as non-producing include shut-in
and behind-pipe reserves. Shut-in reserves are expected to be recovered
from (1) completion intervals which are open at the time of the
estimate but which have not started producing, (2) wells which were
shut-in for market conditions or pipeline connections (3) wells not
capable of production for mechanical reasons. Behind-pipe reserves are
expected to be recovered from zones in existing wells, which will
require additional completion work or future recompletion prior to the
start of production.
Undeveloped Reserves: Undeveloped reserves are expected to be recovered:
(1) from new wells on undrilled acreage, (2) from deepening existing wells
to a different reservoir, or (3) where a relatively large expenditure is
required to (a) recomplete an existing well or (b) install production or
transportation facilities for primary or improved recovery projects.
132
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from Swift Energy
Company's financial statements contained in its annual report on Form 10-K
for the year ended December 31, 1999.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 22,685,648
<SECURITIES> 0
<RECEIVABLES> 27,171,891
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 50,605,488
<PP&E> 638,801,509
<DEPRECIATION> (242,966,019)
<TOTAL-ASSETS> 454,299,414
<CURRENT-LIABILITIES> 34,070,085
<BONDS> 0
0
0
<COMMON> 216,832
<OTHER-SE> 170,187,285
<TOTAL-LIABILITY-AND-EQUITY> 454,299,414
<SALES> 108,898,696
<TOTAL-REVENUES> 110,671,007
<CGS> 0
<TOTAL-COSTS> 61,994,641<F1>
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 14,442,815
<INCOME-PRETAX> 29,736,151
<INCOME-TAX> 10,449,577
<INCOME-CONTINUING> 19,286,574
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 19,286,574
<EPS-BASIC> 1.07
<EPS-DILUTED> 1.07
<FN>
<F1>Includes deprecitaion, depletion and amortization expense and oil and gas
production costs. Excludes general and administrative and interest expense.
</FN>
</TABLE>
