SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
DATE OF REPORT - FEBRUARY 25, 1999
(DATE OF EARLIEST EVENT REPORTED)
HS RESOURCES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
COMMISSION FILE NO. 0-18886
DELAWARE 94-303-6864
(STATE OF INCORPORATION) (I.R.S. EMPLOYER
IDENTIFICATION NO.)
ONE MARITIME PLAZA, 15TH FLOOR, SAN FRANCISCO, CALIFORNIA 94111
(ADDRESS OF PRINCIPAL (ZIP CODE)
EXECUTIVE OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (415) 433-5795
<PAGE>
FORM 8-K
HS RESOURCES, INC.
February 25, 1999
ITEM 5. OTHER EVENTS.
On February 25, 1999, HS Resources, Inc., a Delaware corporation ("HSR"
or the "Company"), issued its 1998 year-end earnings and operational update
press releases. A copy of the earnings press release, as corrected by the
Company's press release dated March 1, 1999, and as further corrected in the
attached exhibit, is attached hereto as Exhibit 99.1. The operational update
press release dated February 25, 1999, is attached as Exhibit 99.2. The edited
transcript of the earnings conference call held Thursday, February 25, 1999, as
edited by the Company, is attached as Exhibit 99.3.
ITEM 7(C). EXHIBITS FILED.
EXHIBIT NUMBER DESCRIPTION
99.1 Earnings Press Release, dated February 25, 1999, as corrected.
99.2 Operational Update Press Release, dated February 25, 1999.
99.3 Edited Transcript of Earnings Conference Call held on Thursday,
February 25, 1999.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
HS RESOURCES, INC.
By:/s/James M. Piccone
------------------
James M. Piccone
Vice President
Dated: March 23, 1999.
Exhibit 99.1
FOR IMMEDIATE RELEASE
FEBRUARY 25, 1999 (As corrected)
HS RESOURCES, INC. ANNOUNCES FOURTH QUARTER AND YEAR-END 1998
FINANCIAL RESULTS
San Francisco, California - HS Resources, Inc. (NYSE:HSE) today announced its
1998 fourth quarter and year-end operating and financial results. Although
production was up and operating costs were down, operating results were
negatively affected by significantly reduced product prices as compared with
prior periods. The Company also announced a change in accounting methods
effective December 31, 1998, from the full cost method to the successful efforts
method as is more common in its peer group. To provide consistency in
comparisons, prior periods have been restated under the successful efforts
method.
FOURTH QUARTER RESULTS. For the quarter, the Company reported a net loss of
$11.3 million, or $0.61 per share, compared to a net loss of $12.8 million, or
$0.73 per share for the comparable prior year period. These numbers include
"impairments," as restated under the successful efforts method of accounting, of
$5.3 million and $12.0 million for the 1998 and 1997 periods, respectively. The
components of these results are as follows.
Quarterly production was 13.0 billion cubic feet of natural gas ("Bcf") and
587,000 barrels of oil ("Bbl"), or 16.5 Bcf equivalents ("Bcfe"), a 14% increase
over 1997. Fourth quarter 1997 results, however, included production of
properties in the Mid-Continent region that the Company sold effective
September 1, 1998. Natural gas represents 78.7% of the Company's production on
an energy-equivalent basis. The following table shows comparative fourth quarter
production excluding the Mid-Continent properties.
<TABLE>
4th Qtr. Production Difference
------------------- ----------
1998 1997 Production %
---- ---- ---------- --
<S> <C> <C> <C> <C>
Oil, MBbl 587 519 68 13
Gas, MMcf 13,003 7,310 5,693 78
MMcfe 16,525 10,424 6,101 59
</TABLE>
Both oil and natural gas prices were down sharply from the prior period. Oil
prices declined to $11.18 per barrel from $18.58 during the prior year period
and gas prices declined to $1.80 per thousand cubic feet ("Mcf") from $2.69
during the prior year period. Overall, prices were off nearly a full dollar, or
35%, on an Mcf equivalent ("Mcfe") basis. As reflected in the following table,
the Company's 1998 hedge positions brought the net realized price up by
approximately $0.21 to $2.03 per Mcfe.
<PAGE>
<TABLE>
4th Qtr. 1998 4th Qtr. 1997
------------- -------------
Net Net
Price Hedge Realized Price Hedge Realized
----- ----- -------- ----- ----- --------
<S> <C> <C> <C> <C> <C> <C>
Oil, $ per Bbl 11.18 2.23 13.41 18.58 0.46 19.04
Gas, $ per Mcf 1.80 0.17 1.97 2.69 (0.12) 2.57
Mcfe, $ per 1.81 0.21 2.03 2.79 (0.07) 2.72
Mcfe
</TABLE>
Despite the higher production, operating cash flow as defined on the Company's
financial statements decreased from $19.2 million during the prior year period
to $16.4 million for the fourth quarter of 1998, due to lower product prices. On
a per share basis, operating cash flow was $0.88 compared to $1.10 for the prior
year period. Again, however, the fourth quarter 1997 results include production
from the Mid-Continent properties that were sold in September, 1998. The
weighted average diluted number of shares outstanding was 18.6 million for the
fourth quarter of 1998 compared to 17.5 million for the comparable 1997 period.
Operating efficiencies continued to improve, as aggregate cash operating costs
(production taxes, lease operating expenses and overhead) decreased 29%, from
$1.00 per Mcfe to $0.71 per Mcfe. Interest costs amounted to $0.56 per Mcfe
during the quarter compared to $0.60 per Mcfe during the prior year period.
Exploration costs, including geological and geophysical expenses and
impairments, charged under the successful efforts method of accounting, declined
by 34% to $1.26 per Mcfe from $1.92 per Mcfe during the prior year period. The
primary component of the decline was due to reduced seismic expenses during the
quarter.
1998 RESULTS. As with the fourth quarter, full-year 1998 results reflect
significantly increased production offset by sharply lower product prices. For
the full year, oil and gas revenues increased to a record $150.1 million, up a
modest 9% despite a 31% increase in production volume. These volumes generated
operating cash flow of $72.9 million or $3.92 per share, up 9.1% from $66.9
million or $3.91 per share for the prior year. The Company recorded a net loss
of $18.6 million, or $1.00 per share, compared to a loss of $15.5 million, or
$0.91 per share, for 1997. Net income includes exploration costs, geological and
geophysical costs and non-cash impairments of $41.7 million during 1998 and
$46.2 million during 1997.
Production for the year increased to 72.7 Bcfe, up 31% from the 55.5 Bcfe
produced during 1997. Natural gas represented 78.4% of the Company's production
on an energy-equivalent basis. The increased production can be attributed to the
Company's active exploitation program during the year plus the impact of the
acquisition of the Amoco D-J Basin properties in late 1997. These were partially
offset by the sale of the Company's Mid-Continent properties as of
<PAGE>
September 1, 1998. Production increases in 1998 over 1997 are summarized in the
following table.
<TABLE>
Comparative production
----------------------
1998 1997 Difference %
---- ---- ---------- --
<S> <C> <C> <C> <C>
Oil, MBbl 2,630 2,400 230 10%
Gas, MMcf 56,969 41,125 15,844 39%
MMcfe 72,749 55,525 17,224 31%
</TABLE>
On an absolute basis, product prices declined 23%, from $2.51 per Mcfe to $1.93
per Mcfe. Oil prices declined 34%, while natural gas prices declined 17%. The
Company's hedge position added $0.13 per Mcfe, for a net realized price of $2.06
per Mcfe. Component details are set forth in the following table.
<TABLE>
1998 1997
---- ----
Net Net
Price Hedge Realized Price Hedge Realized
<S> <C> <C> <C> <C> <C> <C>
Oil, $ per Bbl 12.99 1.59 14.58 19.57 0.15 19.71
Gas, $ per Mcf 1.87 0.09 1.96 2.24 (0.06) 2.19
Mcfe, $ per Mcfe 1.93 0.13 2.06 2.51 (0.04) 2.47
</TABLE>
For the full year, operating efficiencies improved by 19%, declining from $0.83
in 1998 per Mcfe to $0.67 per Mcfe in 1997. Interest costs amounted to $0.58 per
Mcfe compared to $0.58 for 1997. Exploration costs, geological and geophysical
costs and impairments amounted to $0.57 per Mcfe compared to $0.83 per Mcfe for
1997.
RESERVE REPORT. The Company also reported that at year-end 1998 it had total
proved reserves of 37.4 million barrels of oil (MMbbl) and 797 Bcf of natural
gas, for a total of 170.3 MMBoe or 1.02 trillion cubic feet of natural gas on an
energy-equivalent basis. Natural gas constituted 78% of the reserves, and 69% of
the reserves were developed. The Company operates virtually all of its producing
properties.
Total proved reserves at year-end 1997 were 192 MMBoe, including approximately
32 MMBoe of reserves attributable to Mid-Continent properties which were sold.
During 1998 the Company produced approximately 12 MMBoe. Lower product prices
resulted in a downward revision of an additional 16 MMBoe.
These events were partially offset by a 38.4 MMBoe increase in reserves
attributable primarily to successful development activity in the D-J Basin,
coupled with a new field spacing rule promulgated by the Colorado Oil and Gas
Conservation Commission, and by the Company's Gulf Coast exploration program.
The 38.4 MMBoe of new reserves represents a replacement
<PAGE>
rate of over 300% of production and 184% of the combined effects of production
and price related revisions.
The pretax net present value of the reserves, discounted at 10%, was $531.9
million, a reduction from the $822.5 million at year-end 1997. Year-end reserve
values were calculated based on constant prices and costs using year-end field
prices of $1.94 per Mcf and $9.99 per Bbl. Product prices did not take into
consideration the effect of product price hedging. Product prices of $16.38 per
Bbl and $2.31 per Mcf were applied in the 1997 year-end reserve calculation. If
the year-end 1997 product prices had been applied to the 1998 reserves, the
pretax net present value would have been $761.9 million.
In commenting on the Company's fourth quarter and year-end results, Chairman and
Chief Executive Officer Nicholas J. Sutton said, "Calendar year 1998 was a
difficult one for virtually every independent oil and gas producer. Product
prices, particularly oil, were at historically low levels, and that rippled
through our entire sector. We believe, however, that the fundamentals for our
Company are as strong as they have ever been in our 20-year history.
"Operationally, we integrated the Amoco properties into our operations smoothly
and efficiently, and our field staff increased production from those properties
by more than 10%, without considering production additions from refracs and
other operations. Furthermore, the efficiencies inherent in adding these
properties is evident in our financial results. Our Gulf Coast projects have
advanced from the geological and geophysical stage to the drilling stage,
resulting in the Company drilling or participating in 24 gross (6.6 net) wells;
75% of the Company's net wells were completed as producers. Proved reserves from
these activities at year-end 1998 were 4.3 MMBoe, up 619% from year-end 1997.
Excluding front-end land and seismic costs that must be allocated over a number
of projects and properties, the finding cost of Gulf Coast reserves added during
1998 was $1.51 per Boe. Indeed, the fact that we were able to grow total Company
reserves by more than 6% (after giving effect to the Mid-Continent property sale
and despite the reduction of reserves due to product prices) in a year of
dramatically reduced commodity prices is indicative of the quantity and quality
of our exploitation and exploration inventory.
"1999 will bring many challenges to independent oil and gas producers, but many
opportunities as well. We believe that HS Resources has the project inventory,
the financial flexibility and the tools to add value internally and to take
advantage of externally generated opportunities that arise."
Company President P. Michael Highum added, "During 1998, our D-J Basin District
team undertook more than 450 separate activities ranging from refracs and
recompletions to deepening existing wells and drilling new wells. That team has
applied creativity and flexibility to its operations, generating additional
operational efficiencies. The Company's combined cash cost of $0.67 per Mcfe for
production taxes, lease operating expenses and overhead, is among the best in
the industry, something that is particularly important in times of soft product
prices. During 1999, we will continue to actively and aggressively exploit our
D-J Basin assets where we have literally thousands of opportunities, virtually
all of which are held by production.
<PAGE>
"Our onshore Gulf Coast activities have been equally exciting. In 1996, we
initiated a deliberate and focused approach to the Gulf Coast, capturing plays
and prospects where we could enhance our geologic understanding by adding the
information gained with 3-D seismic imaging techniques. We intend to provide
additional information on the status of these projects in a separate press
release. However, as we look to 1999 we think the Gulf Coast has excellent
potential and, depending on success, we could participate in as many as 50 wells
there."
Chief Financial Officer, James E. Duffy, commented on the Company's financial
position, its hedging position and the change in accounting methods. "During
1998 we added financial stability and flexibility through two key actions. We
repaid more than $150 million of bank debt with the proceeds of our
Mid-Continent asset sale in September and we issued $85 million of 9 1/4% Senior
Subordinated Notes in December. That allowed us to replace bank debt with
financing better aligned with the long-term nature of our producing assets. Our
1999 capital plan is to spend no more than our cash flow, presently expected to
be $65-75 million based on present product price forecasts. Capital will be
allocated throughout the year depending on results, but our preliminary plan is
to allocate approximately 40% to D-J Basin exploitation activities, 40% to Gulf
Coast exploration projects, and 20% to other activities and contingencies. We
are confident that we will be able to continue to achieve growth in reserves and
production despite the current environment."
"During 1998, our hedging activities contributed over $9 million to our bottom
line, and looking to 1999 we currently have hedged approximately 55% of our gas
production at rates that will yield an average wellhead netback price of $1.98
per Mcf. We also have hedged about 43% of our estimated 1999 oil production at a
netback price of over $15.00 per Bbl. Based on a current NYMEX price strip, our
hedge position would contribute over $13 million to our 1999 financial results."
Mr. Duffy continued, "During its early years the Company concentrated its
activities mainly in the D-J Basin. The low risk nature of those activities and
the Company's size then made the full cost method of accounting the preferred
method. However, the growth of the Company and the increase in exploration
activities in the Gulf Coast and elsewhere caused us to change to the successful
efforts method of accounting. This method is more the norm for our peer group
and is considered preferable by the Securities and Exchange Commission and the
Financial Accounting Standards Board. As required by generally accepted
accounting principles, this change in accounting has been applied retroactively
and, accordingly, we have restated our financial statements for all previous
periods."
Statements concerning ability to add value; drilling, exploration, exploitation,
development and other plans; numbers of opportunities; capital spending and
allocation plans; expectations concerning production or reserve growth targets;
financial stability and flexibility; and all similar statements or implications
are forward looking statements within the meaning of Federal securities laws.
Actual results or events may differ materially from these forward looking
statements, depending upon a variety of factors, including commodity prices,
availability of capital, results of exploration and other drilling, cash flow
from operations, costs of materials and labor, availability of equipment,
regulatory burdens, gathering system and processing plant
<PAGE>
operating constraints, Company objectives and business judgment and other
factors, both within and outside of the Company's control. The Company's forward
looking statements are qualified in their entirety by these and other factors
more fully set forth on the Company's report on Form 8-K filed February 26,
1997.
HS Resources, Inc. is an independent oil and gas exploration and development
company with active projects in the Rocky Mountain and Gulf Coast regions. The
common stock of HS Resources, Inc. is traded on the New York Stock Exchange
under the symbol "HSE".
Contact: Theodore Gazulis
Vice President - Treasury,
Capital Markets and Investor Relations
415-433-5795
[email protected]
<PAGE>
<TABLE>
<CAPTION>
HS Resources, Inc.
Summary of 1998 Operations
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except Per Share Data)
Quarter Ended Year Ended
December 31, December 31,
----------------------- -----------------------
1998 1997 1998 1997
----------- ---------- ---------- ----------
Revenues:
<S> <C> <C> <C> <C>
Oil & gas sales $ 33,488 $ 39,473 $150,087 $137,251
Trading and transportation 12,847 25,701 54,144 90,062
Other gas revenues 2,347 1,243 8,560 4,449
Other income 257 1,049 1,405 1,943
----------- ---------- ---------- ----------
Total revenues 48,939 67,466 214,196 233,705
----------- ---------- ---------- ----------
Expenses:
Production taxes 2,597 2,810 10,422 9,703
Lease operating 7,297 6,575 30,410 24,848
Cost of trading and transportation 11,541 25,037 50,451 88,402
DD&A 13,904 11,958 61,223 45,757
Exploratory and abandonment costs 12,412 8,052 15,420 13,438
Geological and geophysical costs 3,067 7,812 14,308 17,049
Impairment and gain/loss on sales of oil & gas properties 5,316 12,027 11,986 15,710
General and administrative 1,822 5,182 8,061 11,550
Interest 9,249 8,629 41,990 32,297
----------- ---------- ---------- ----------
Total expenses 67,205 88,082 244,271 258,754
----------- ---------- ---------- ----------
Loss before benefit
for income taxes (18,266) (20,616) (30,075) (25,049)
Benefit for income taxes (6,959) (7,855) (11,459) (9,544)
----------- ---------- ---------- ----------
Net loss $ (11,307) $(12,761) $(15,505) $ (18,616)
=========== ========== ========== ==========
Net loss per share - diluted $ (0.61) $ (0.73) $ (1.00) $ (0.91)
=========== ========== ========== ==========
Outstanding shares - diluted 18,577 17,503 18,609 17,119
=========== ========== ========== ==========
Operating cash flow (a) $ 16,432 $ 19,232 $ 72,862 $ 66,905
=========== ========== ========== ==========
Operating cash flow per share - diluted $ 0.88 $ 1.10 $ 3.92 $ 3.91
=========== ========== ========== ===========
</TABLE>
(a) Net income before geological and geophysical costs, exploratory and
abandonment costs, depreciation, depletion and amortization, impairment and
gain/loss on sale and income taxes. The Company recorded a current tax
provision of $5.3 million in the year ended December 31, 1998 for taxes
payable as a result of the Mid-Continent Sale.
<PAGE>
<TABLE>
<CAPTION>
HS Resources, Inc.
Summary of 1998 Operations
SUMMARY PRODUCTION, PRICE AND COST DATA
Quarter Ended Year Ended
December 31, December 31,
------------------------------------------- ----------------------------------
% %
1998 1997 Change 1998 1997 Change
----------------- ----------- ---------- ---------- ----------- -----------
Daily Production:
<S> <C> <C> <C> <C> <C> <C>
Oil (Bbl) 6,378 6,679 -5% 7,206 6,575 10%
Gas (Mcf) 141,336 117,589 20% 156,080 112,672 39%
Equivalent Barrels 29,934 26,277 14% 33,219 25,353 31%
(Boe)
Period Production:
Oil (MBbl) 587 614 -5% 2,630 2,400 10%
Gas (MMcf) 13,003 10,818 20% 56,969 41,125 39%
Equivalent Barrels (MBoe) 2,754 2,417 14% 12,125 9,254 31%
Average oil price (Bbl) $ 13.41 $ 19.04 -30% $ 14.58 $ 19.71 -26%
Average gas price (Mcf) $ 1.97 $ 2.57 -23% $ 1.96 $ 2.19 -11%
Average price (Boe) $ 12.16 $ 16.33 -26% $ 12.38 $ 14.83 -17%
Costs:
G&A per Boe $ 0.66 $ 2.14 -69% $ 0.66 $ 1.25 -47%
LOE per Boe $ 2.65 $ 2.72 -3% $ 2.51 $ 2.69 -7%
DD&A per Boe $ 5.05 $ 4.95 2% $ 5.05 $ 4.94 2%
(includes depreciation on
non oil and gas assets)
</TABLE>
<PAGE>
HS Resources, Inc.
Summary of 1998 Operations
CONDENSED CONSOLIDATED BALANCE SHEETS
(In Thousands)
<TABLE>
December 31, December 31,
1998 1997
----------- ------------
Assets
<S> <C> <C>
Current assets $ 60,265 $ 55,389
Oil & gas properties 924,663 1,028,897
Accumulated DD&A (175,729) (151,431)
Other assets 23,240 23,451
----------- ----------
$ 832,439 $ 956,306
=========== ==========
December 31, December 31,
1998 1997
----------- ------------
Liabilities and Stockholders' Equity
Current liabilities $ 79,164 $ 63,717
Bank debt 230,000 412,000
9 7/8% Subordinated notes, due 2003 74,712 74,654
9 1/4% Series A subordinated notes, due 149,388 149,310
9 1/4% Series B subordinated notes, due 80,817 -
Other long-term liabilities & deferred 21,359 21,214
Deferred taxes 44,138 61,933
Stockholders' equity 152,861 173,478
----------- ----------
$ 832,439 $ 956,306
=========== ===========
</TABLE>
<PAGE>
<TABLE>
HS Resources, Inc.
Summary of 1998 Operations
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
<CAPTION>
Year Ended
December 31,
----------------------------
1998 1997
---------- ----------
Cash flows from operating activities:
<S> <C> <C>
Net loss $(18,616) $(15,505)
Depreciation, depletion and amortization 61,223 45,757
Impairment and loss on sale of oil and gas properties 11,986 15,710
Amortization of deferred charges, debt issue costs
and deferred compensation 2,621 1,830
Transfer treasury stock to 401(k) plan 549 417
Gain on sale of fixed assets (235) ---
Deferred income tax benefit (14,106) (10,554)
Decrease (increase) in accounts receivable (1,186) 2,558
Increase in accounts payable and accrued expenses 10,069 7,947
Increase (decrease) in deferred revenue, net (965) 9,873
Other (1,257) 843
---------- ----------
Net cash provided by operating activities 50,083 58,876
---------- ----------
Net cash provided by (used in) investing activities 62,433 (294,076)
---------- ----------
Net cash (used in) provided by financing activities (109,765) 233,342
---------- ----------
Net increase (decrease) in cash and
cash equivalents 2,751 (1,858)
Cash and cash equivalents, beginning
of the period 6,907 8,765
---------- ----------
Cash and cash equivalents, end of
the period $ 9,658 $ 6,907
========== ==========
</TABLE>
Exhibit 99.2
FOR IMMEDIATE RELEASE
FEBRUARY 25, 1999
HS RESOURCES, INC. PROVIDES OPERATIONAL UPDATE
San Francisco, California - HS Resources, Inc. (NYSE:HSE) today provided an
update on the status of various field activities resulting from its 1998 capital
program. The Company operates domestically in three distinct geographic areas,
the D-J Basin of Northern Colorado, the onshore portion of the Texas-Louisiana
Gulf Coast, and the Northern Rocky Mountain region.
D-J BASIN
During 1998 the Company undertook more than 450 individual activities on its D-J
Basin properties. These activities ranged from refracs and recompletions of
existing wells to drilling new wells and deepening existing wellbores to new
formations. These activities resulted in the Company increasing its D-J Basin
daily gas production by 25% to more than 140 million cubic feet of gas (MMcf)
per day. Proved reserves in the D-J Basin increased by more than 4% to 165.6
million barrels of oil equivalent (MMBoe) after taking into account D-J Basin
production of 10.5 MMBoe during the year. The following is a brief summary of
the overall results for each major category of activity.
CODELL REFRACS. 214 refracs were performed. Average initial production is
approximately 7.5 times the pre-frac production. The average finding cost
for new reserves added by refracs was under $4.00 per Boe. Most of the gas
produced from Codell refracs also qualifies for Section 29 tight gas
production tax credits which are monetized by the Company under existing
facilities.
J-SAND NEW DRILLS. 29 new J-Sand wells were drilled. Average reserves were 750
MMcf, for an average finding cost of $2.64 per Boe.
J-SAND DEEPENINGS. 41 shallower producing wells were deepened to bring the
J-Sand on production. Production increased an average of 600 Mcfd per well, and
new reserves were added for an average cost of $1.60 per Boe.
DAKOTA DEEPENINGS. 52 wells were deepened to the Dakota formation. 26 were
considered successful, 6 were marginal, and 20 were unsuccessful. Overall, more
than 2 million Boe of new proved reserves were developed for an all-in finding
cost of approximately $2.41 per Boe.
GULF COAST
During 1998, the Company advanced several of its Gulf Coast projects to the
drilling stage. The Company drilled 24 wells (6.6 net) in 1998, 17 (4.9 net) of
which were successful, equating to a
<PAGE>
71% success rate and estimated average reserves of more than 600 MBoe per well.
These activities resulted in the booking of approximately 4.35 MMboe of reserves
at year-end 1998 compared with 600,000 Boe of reserves booked at year-end 1997.
All-in drilling and development costs were approximately $1.50 per Boe, and a
full cycle allocation of land, seismic and other geological and geophysical
costs will add an estimated $1.50-2.00 per Boe. Additional status information on
certain projects is detailed below.
BUHLER. During 1998, four out of six wells were successfully completed and
brought on line, bringing the program total to thirteen successes in seventeen
attempts. Average reserves are approximately 450 MBoe per well. Five additional
leads have been identified and could be drilled in 1999. HSE owns a 3-5% working
interest in this non-operated project.
DEVILLIER. During 1998, two wells were successfully drilled and completed. HS
has a partially carried working interest in these wells, resulting in an
aggregate of 2.1 Bcfe, net to the Company (11.2 Bcfe gross) for approximately
$500,000.
INDIAN VILLAGE. This is a 116 mi2 3-D program targeting the Hackberry formation.
The Company's first test well, drilled in December of 1998, appears to be
successful with estimated gross reserves of between 13 and 16 Bcfe. The gross
well cost was approximately $1.1 million. Six additional leads have been
identified with drilling continuing during 1999. HSE owns a 50% working interest
and is the project operator.
IOWA/WOODLAWN. This project targets the Hackberry formation. Two wells were
drilled during 1998 with one successfully completed and brought on-line in the
4th quarter at an IP of more than 5.1 MMcfd and 113 Bopd. Six additional
prospects have been identified thus far in this 120 mi2 3-D shoot, with
additional drilling planned in 1999. The Company owns a 25% working interest in
this project operated by Sonat Exploration.
NORTH GILLIS. This project targets the Hackberry formation, with secondary
potential in the Yegua. Nine Hackberry wells were drilled in 1998, seven of
which have been completed as producers. The average well cost in North Gillis
was $850,000 gross and resulted in average estimated reserves of 930 MBoe per
well. In addition, a successful Yegua test was drilled in this project area at a
cost of $1.7 million with estimated gross reserves in excess of 10 Bcfe. The
Company has a 37.5% working interest and is the project operator.
WELSH. During the 3rd quarter the Company completed the HSR Victory Financial et
al #1. The well tested at 890 Mcfd and 5 Bopd, and currently is waiting on
pipeline hookup. The Company has a 37.5% working interest and is the project
operator.
Elsewhere in the Gulf Coast, the Company is in various stages of 3-D seismic
acquisition, interpretation, and processing on more than a dozen other projects.
<PAGE>
NORTHERN ROCKIES
HS Resources also was active in its Northern Rockies area during 1998, reporting
three exploratory wells in Sweetwater County, Wyoming, that appear to be
productive based on data currently available.
GOLD COAST UNIT. Pipe was been set on the Company's HSR Gold Coast #16-6 well
during the 4th quarter. Logs and other data are encouraging, but a pressure
buildup analysis indicates possible formation damage. The well is shut-in for
the winter pursuant to Bureau of Land Management requirements. Evaluation will
continue in the spring. HSE owns a 100% working interest in this prospect,
subject to partial reduction after payout, and a 70% interest in approximately
44,000 gross acres in the project area.
SOUTH JONAH. Pipe was also run on the HSR-Holmes Federal #05-01, operated by
McMurray Oil Company on the Company's South Jonah project, after encountering
several sections of overpressured and normally pressured sands. The well has
been on production since January 29, 1999 averaging 1.0 MMcfg/d without
compression. This project area encompasses approximately 15,000 gross acres
potentially exploitable by the Company with a 60% working interest.
PINEDALE. Ultra Petroleum and Lance Oil and Gas Company have drilled two tests
on acreage farmed-out by the Company. The first well had encouraging shows but
tested low rates of gas. The second well encountered over 550 feet of
overpressured Lance sands but operations were suspended and the well shut-in for
the winter under Bureau of Land Management requirements.
During 1999 the Company expects that these and other select projects in the
region will be advanced.
Statements concerning drilling, exploration, development and other plans,
expectations of drilling activity, production or reserve estimates, number of
possible lead, prospect or well opportunities, expected success of uncompleted
wells, and all similar statements or implications are forward looking statements
within the meaning of Federal securities laws. Actual results or events may
differ materially from these forward looking statements, depending upon a
variety of factors, including commodity prices, availability of capital, results
of exploration and other drilling, cash flow from operations, costs of materials
and labor, availability of equipment, regulatory burdens, actual completions and
production success in uncompleted wells. Company objectives and business
judgment and other factors, both within and outside of the Company's control.
The Company's forward looking statements are qualified in their entirety by
these and other factors more fully set forth on the Company's report on Form 8-K
filed February 26, 1997.
HS Resources, Inc. is an independent oil and gas exploration and development
company with active projects in the Rocky Mountain and Gulf Coast regions. The
common stock of HS Resources, Inc. is traded on the New York Stock Exchange
under the symbol "HSE".
Contact: Theodore Gazulis
Vice President - Treasury,
Capital Markets and Investor Relations
415-433-5795
[email protected]
Exhibit 99.3
HS RESOURCES
MODERATOR: MIKE HIGHUM
FEBRUARY 25, 1999
1:00 P.M. CT
EDITED TRANSCRIPT
Operator: Good day everyone and welcome to this HS Resources Fourth Quarter and
full year 1998 conference call. Today's call is being recorded. A replay
will be available at 3:00 p.m. Central Time today. You can access the
replay by dialing 719-457-0820 and reference pass code 632934. Again, that
number is 719-457-0820, pass code 632934. At this time I would like to turn
the call over to the President of HS Resources, Mr. Mike Highum. Please go
ahead, Sir.
Mike Highum: Thank you and good afternoon everybody. This is Mike Highum, and
welcome to our 1998 year end and fourth quarter earnings conference call.
Well, as everyone knows we're facing one of the most difficult times I
think any of us of any age has seen in the oil and gas industry. Obviously,
as a result of low prices and the potential for additional weakness in gas
prices, cash flows of most companies have been hit hard and stock prices
have been decimated. Our stock price is no exception. If it's any
consolation to you out there, Senior Management owns about 15% of the
company so we also feel the pain. Ironically and in sharp contrast to the
state of the industry, we had a very strong 1998 and we're quite optimistic
about the future. Despite low product prices, as Jim Duffy will detail in a
minute, we posted what we consider to be some pretty good numbers for the
year adjusted for the Mid-Continent sale. Production was up about 30% over
1997. We replaced almost 200% of our production and would have been about
<PAGE>
300% if we'd been using the same product price deck we had at the end of
1997, and we showed meaningful reserve increases, all despite cash flow and
capital constraints. We believe that our success during this time was
achieved because we continued to emphasize what we consider to be the
fundamentals and to concentrate on our core strengths and competitive
advantages. Those include efficient operations, the execution of an
aggressive DJ Basin exploitation program, a technology-driven exploration
program in the Gulf Coast and aggressive balance sheet management.
Before turning it over to Jim, I'd like to highlight a few of what we
consider to be the primary achievements of the company for 1998. I'll
discuss some of these in a bit more detail after Jim reviews the financial
information. First, I think and one of the most important accomplishments
in 1998 was the operational integration of the DJ properties that we
acquired from Amoco in February. By March, over 800 wells were fully
integrated into our operational base. As we expected, we were able to wring
additional efficiencies out of these wells and as a result, our per unit
operating costs in the DJ decreased by about 40 cents per BOE, or about
14%. I mentioned just a minute ago that one of our core competencies is our
efficient operations. Our combined LOE and G&A for 1998 was $3.17 per BOE
which has to be among the very best in the industry. Obviously, it's
important in times like this to have low operating costs. I should also
point out that we increased production from the existing Amoco wells during
the year by about 10%. That does not include the new activities that we
undertook in existing wells. That was just the PDP production.
The second achievement that I'd like to note was the execution of our
aggressive exploitation program in the DJ Basin. During the year, we
undertook about 450 activities which included such activities as infill J
Sand drillings and deepenings, Codell deepenings and refracs. Again, these
activities all generate almost immediate cash flow because the
infrastructure is already in place. These are
<PAGE>
very critical components in a time of low product prices. As a result of
these activities, we increased our DJ Basin production by about 20%,
comparing daily exit rates at the beginning of the year to the end of the
year. We now produce about 45% of the gases produced from the Greater
Wattenberg area and that's an amount equivalent to about 25% of all the gas
consumed in the state of Colorado.
The third thing that we did that I think was very important is that we
successfully executed our 3-D seismic exploration program in the Gulf
Coast. We drilled 24 wells and had 17 discoveries. Based on our drilling
costs alone, our finding costs in the Gulf Coast was about $1.50 per BOE.
We believe that in the aggregate when these projects are fully developed
that land and seismic cost will add about another $1.00 to $1.50. So, as
you can see, we're achieving very strong results in the Gulf Coast.
Finally, as Jim will discuss here in just a minute, we undertook a
number of steps to solidify our balance sheet we jumped through a very
small opening in the capital markets to term out $85 million worth of debt.
We sold our Mid-Continent properties and paid down our debt and we
profitably hedged product prices and locked in interest rates. As a result
of focusing on these core competencies and emphasizing the fundamentals, we
believe that HS is in very good shape going forward. With that, I'm going
to turn it over to Jim to discuss our financial results. Then I'll come
back and provide and little more detail on our operational results. Jim.
Jim Duffy: Thanks Mike. I'd like to begin today by briefly discussing our
decision to change our accounting method from full cost to successful
efforts because the change affects many of the numbers that we're going to
be discussing today and the numbers that you're going to see from us in the
future. As many of you know, prior to 1996, the majority of our activities
were concentrated in the Rocky
<PAGE>
Mountains and in particular, the DJ Basin. Because the majority of our
costs were attributable to a single field, namely Wattenberg where we
didn't have any exploration or dry hole expenditures, the full cost and
successful efforts methods would have generated very similar results. So we
were frankly somewhat indifferent as to the method that we used. However,
as we've moved into new areas and increased our exploration activities we
believe that the size and the scope of the company's business now lends
itself more appropriately to successful efforts and thus the change. Some
of the specific effects of this change include: first, we have accumulated
inception-to-date charge to retained earnings as result of converting to
successful efforts of about $35 million compared to our September 30, 1998
retained earnings balance under full cost. Second, we have a fourth quarter
1998 impairment charge under successful efforts of about $5.3 million pre
tax. This amount is attributable to certain costs on a number of non-core
activities, all of which have now been fully written off. More importantly
though, in the DJ area under successful efforts we have a ceiling cushion
of nearly $400 million at December 31st, approximately $40 million in the
Gulf Coast at December 1998. To put this in perspective, we've run some
calculations and assuming a $10 barrel oil price, gas prices in the DJ have
to go well below $1.30 per MCF and under $0.50 in MCF in the Gulf Coast
before we would begin to experience impairment charges in those areas. As
far as financial presentation is concerned, because all of the G&G and
non-productive . . . . [somebody's got their phone on. Maybe they can check
their microphone and mute it if they could please]. As far as financial
presentation is concerned, because all G&G and non-productive exploration
expenditures are deducted from income under successful efforts we will now
add back these charges along with non-cash charges for DD&A impairments and
deferred taxes to calculate operating cash flow with the same treatment for
EBITDAX to essentially correlate with our prior calculation of EBITDA. One
additional difference under successful efforts is that no internal overhead
charges can be capitalized. Under full cost in 1997 and 1996, we
capitalized approximately $3.5 million in each year for internal costs
attributable
<PAGE>
to our acquisition activities. This represented about 1% of the acquisition
transaction values in those two years. These amounts have now been expensed
in the restated P&Ls. Lastly, we've now received approval for the
accounting change from our bank group and have amended the appropriate
section of our credit agreement to recalibrate covenants under the
successful efforts method. We are now a successful efforts company with all
the appropriate bank covenants properly corrected.
Turning now to our operating results including the Mid-Continent, in 1998
we had total production of approximately 12.1 million BOE compared to 9.3
million in 1997 which is an increase of more than 30%. Excluding the
Mid-Continent 1998 production was 10.7 million BOE versus 6.2 million in
1997, which was an increase of 73%. Because these numbers include the Amoco
acquisition for all of 1998 but not 1997, a more important measure, and I
believe that Mike alluded to this earlier, is that our daily production
rates at the end of the fourth quarter grew by more than 20% over the end
of 1997. This production growth primarily reflects the significant
incremental production we've achieved through production enhancements on
the Amoco properties and from ongoing development activities.
I should point out however, that due to the timing of new production in the
Gulf Coast area, the fourth quarter of 1998 was only moderately impacted by
new Gulf Coast production. In fact, we believe that we will see net daily
production nearly triple from the end of this past quarter to the end of
the first quarter of 1999 from a little over 6 million a day to nearly 20
million a day. So those activities are just now beginning to really come on
line and affect our production.
With respect to product prices in the fourth quarter, we realized a net gas
price of $1.97 per MCF versus $2.57 last year. Fortunately, in the 1998
quarter, our price included hedging benefits of $0.17 per MCF. For oil, we
realized a net price of
<PAGE>
$13.41 including hedge benefits on $2.23 a barrel, which obviously had a
significant impact on our overall price. That compares to a net realized
price of $19.04 in the fourth quarter of 1997. Fortunately, our hedging
gains added meaningfully to our cash flow which combined with the higher
production levels and lower operating and overhead cost resulted in cash
flow per share of $0.88 in the fourth quarter of 1998 versus $1.10 in the
fourth quarter of 1997. This is despite the significantly lower net product
price realization. For the full year, our net realized gas price in 1998
was $1.96 with hedging, compared to $2.19 in 1997 with oil at $14.58
compared to $19.71 in the 1997 year. For the full year, cash flow per share
was $3.92 in 1998 compared to $3.91 and 1997 reflecting the higher
production and improved operating efficiencies against the lower product
prices.
With respect to our continuing program to maximize operating efficiencies,
as Mike mentioned earlier, we achieved substantially lower cost in 1998
with a combined LOE and G&A rate per BOE of $3.17 compared to $3.94 in
1997. I think it's important to note that we have always focused on
maximizing our operating efficiencies and we believe that we'll be able to
achieve an even lower rate in 1999 where we anticipate a combined rate of
less than $3.00 per BOE. There really are not many in the industry who can
say that.
Turning to our proved reserves position, at December 1998 gross new reserve
additions replaced production by more than 300% before giving effect to
losing approximately 16 million BOE due to lower prices. However, even with
the effect of lower prices, our net production replacement was nearly 200%
with net reserves increasing by roughly 6% after giving effect to the 32
million of BOE reserves sold in the Mid-Continent. Overall, our proved
reserves position grew to 170 million BOE, or more than 1 TCF equivalent
with nearly 80% of our total reserves in natural gas. Using year end prices
of $1.94 per MCF and $9.99 a barrel (hard prices to say actually), our PV
10 value was $532 million compared
<PAGE>
to $823 million in December 1997, which reflected prices of $16.38 and
$2.31 per MCF. However, if we apply those 1997 prices to our year end 1998
reserves, our PV 10 value would have been $762 million. You should keep in
mind, that's after realizing $158 million from the Mid-Continent
divestiture. During 1998, our net cap ex program totaled approximately $92
million. Of this amount, $64 million was in the DJ, $3.5 million in the
Northern Rockies, and $24 million in the Gulf Coast. As a result, we
realized single year book finding cost of approximately $4.40 per BOE in
total and about $3.43 per BOE when we exclude land and seismic which really
need to be spread out over future projects as well.
Looking at our current hedging position, we currently have nearly 60% of
our 1999 gas production hedged at just under $2.00 per MCF net to the
wellhead and more than 40% of our expected oil production hedged at nearly
$15. We think these significant hedge positions will provide more than $13
million of additional cash flow in 1999 compared to current strip prices.
When you look at our anticipated capital program this year of $65 million
to $75 million, these hedge positions will provide very important cash flow
support as we fund our ongoing activities.
Turning now to our financial position during 1998, we successfully
completed a number of transactions, which significantly strengthened our
balance sheet. First, as Mike mentioned, we sold our Mid-Continent
properties and applied the $158 million of proceeds to repayment of bank
debt. I should point out that the sale of these properties not only
provided us with meaningful capital with which to repay debt but also
resulted in a very excellent return on the investment over the roughly two
years we held them. After taking into account all the costs associated with
acquiring developing and producing the Tide West properties the proceeds
from production of property sales resulted in an overall 27% return on
equity. That's after giving affect to all interest and taxes that were paid
on the
<PAGE>
sale. So, great return. We think that the timing and execution of our
purchase, the ultimate disposition of the properties, the value we
generated, and strong product prices during the period we held them,
resulted in a great investment and terrific return for our shareholders.
Secondly, in December we successfully completed an $85 million add on
financing to our 9-1/4% subordinated notes which are due in 2006. This
transaction allowed us to term out a significant amount of bank debt and
bring additional stability to our balance sheet at a good rate,
particularly in today's market. HS was one of the very few companies in our
peer group to complete a subordinated debt transaction in 1998. It was
really very gratifying to us that our bond investors repeatedly told us
that our long-lived gas reserves, stable predictable production, along with
our hedging programs, low operating costs, and the substantial inventory of
existing growth projects provides them significant comfort in making a long
term debt investment in HS. This is particularly true compared to many of
our peer group companies that don't have the same fortunate circumstances.
The other element of our program in 1998 was the hedging activities we
undertook for both product prices and interest rates. I've already
discussed product price hedges, but we also locked in long-term, record low
interest rates on a substantial portion of our bank debt. In a single
transaction, for example, we locked in an interest rate of 5.8% for the
next seven years on $80 million of debt or more than one-third of our
current bank debt. We believe that as a result of stabilizing interest
rates, protecting product prices and appropriately managing our costs we
will generate excellent operating margins, particularly in the current low
price environment which will provide cash flow for both debt service and to
fund our ongoing cap ex program. At the current time we have approximately
$230 million of bank debt outstanding against a borrowing base of $280
million which, given that we intend to fund our cap ex program out of cash
<PAGE>
flow for the foreseeable future, provides us with meaningful liquidity and
plenty of financial flexibility. At December 31, 1998, we had total debt of
$3.14 per BOE down from $3.31 per BOE at December 1997. Our goal is to
reduce our debt per BOE to less than $2.75 by the end of 1999. We believe
we'll do that as a result of adding reserves through our ongoing projects
and to a lesser extent some selective, non-core property divestitures and
monetizations. Overall, we believe that we significantly improved our
financial position during 1998 and that our capital structure is now
efficiently aligned with our strategic initiatives to support our on going
growth activities. With that I'll turn it back over to Mike.
Mike Highum: Thanks, Jim. I've just been told that I should recite the safe
harbor language, and it goes as follows. In this call we have been and will
be discussing several matters which should be considered forward-looking
statements under the federal securities laws. These may include statements
regarding project plans, capital expenditures, product prices, or similar
statements. Obviously, actual results may differ from any of our current
projections or plans. Additional information concerning the factors that
could cause actual results to differ materially from our statements are
contained in our press release and in our report on form 8-K filed February
26, 1997.
I'm going talk a little bit about our operational results, although I hope
that all of you have had a chance to look at the additional press release
that we issued. It provided more information about our operational results
than we have generally provided in the past, primarily because we've been
so active and there's been a lot going on. I'm going to hit some of the
highlights of the DJ, Gulf Coast, and a little bit in the Northern Rockies.
As I mentioned, we did over 450 activities in the DJ, including 214
refracs. The results from these refracs continue to be in line with what we
have stated previously. The initial production post frac is approximately
7.5 times the pre-frac production level. Our year end 1998 engineering
shows an average reserve increase of about 137 million cubic feet in
<PAGE>
5,000 to 6,000 barrels of oil and a finding cost of about $3.35 on the
refracs. During the year, we also drilled 29 new J sand wells at an average
cost of about $360,000 per well. We added just about .75 BCF per well and
over 5,000 barrels of oil. Again, our finding costs in these new J sand
wells was under $3 per BOE. Additionally, we did 41 J sand deepenings.
These are cheaper. We were able to do them at about $216,000 per well with
a production increase on average of about 400,000 cubic feet of gas per
day. We added about 23.5 BCF of new reserves with a finding cost of about
$1.60 per BOE. Finally, importantly, we deepened a number of wells to the
Dakota. As you may recall, this is a slightly riskier channel formation
which lies just below the J sand. We deepened 52 wells, 26 were successful,
six were marginal and 20 were unsuccessful. This is a riskier play. You
wouldn't really want to drill these wells stand alone to the Dakota, but to
deepen them from the J Sand or Codell is relatively inexpensive. We were
able to add about 12 BCF of new reserves for a little over $4 million for a
finding cost of about $2.40 per BOE. So we did quite well there.
Turning to the Gulf Coast, we have a large number of project areas there.
We have over 20 project areas now, rights to over 250,000 acres and over
770 square miles of 3 D seismic. There's a lot going on. During 1998 in
Buhler which was kind of our kick off program we drilled an additional four
wells successfully out of 6 attempts and those were brought on line. Buhler
reserves are running at about 450 thousand BOE per well as you may recall
we have a small interest on Buhler we used it to set up the program in
North Gillis and (Iowa/Woodlawn) and Indian Village. The results from the
wells in Buhler, in which we have about a 3% interest, allowed us to
perfect the application of 3D seismic to the Hackberry. In DeVillier we
drilled two wells during the year. We had a partial interest in these. They
had an aggregate of about 2.1 BCFE net to the company which cost us
approximately $500,000, so we had a strong finding cost there also.
<PAGE>
As you recall the next project that we drilled after Buhler was North
Gillis. In North Gillis we have a 37.5% interest. The primary target is the
Hackberry formation. During 1998, we drilled nine wells, seven of which
were completed as producers. The average well cost about $850,000 to drill
and complete, and our average estimated reserves on these wells is about
930,000 BOE per well. We also drilled a Yegua test in the North Gillis
area. It was successful and cost about $1.7 million with gross reserves in
excess of 10 BCF so we're doing quite well there. In Indian Village (this
is a 116 square mile 3 D program that targets the Hackberry formation) we
drilled our first well in December. It appears to be successful with gross
reserves estimated at between 13 and 16 BCF. The well cost approximately
$1.1 million. We've identified six additional leads that we will be
drilling and have about 50% interest in the project area. We're the
operator. In Welsh during the third quarter, the company completed a well
called the HSR Victory Financial. In that well we have a 37.5% interest and
it's come on production at just under a million cubic feet of gas per day.
There are a number of other areas that we've been active in. I'll run
through them really very quickly. We are interpreting 3 D seismic in our
Bayou Choupique area, are interpreting 3D seismic in our Bayou Shafer-Ramos
area. We're interpreting 3D seismic in our Edgerly project area. St Mary's
is a partner in that area and they are publicly saying they've identified a
couple of prospects already. We are preparing seismic in our Hathaway
project area and we have begun to drill the shot holes for the seismic in
our Starks project area. In Roanoke we will be spudding our second well
probably by the beginning of April and we're interpreting 3D seismic in Big
Creek and Port Barre.
To bring you up to date, really since the beginning of the year, we have
drilled or are in the course of drilling four additional wells. We drilled
the M Half Circle on our Lox B project area and that looks like its going
have and excess of about 10 BCF of reserves. We drilled an additional well
in North Gillis. It is a Struma
<PAGE>
discovery and looks like it will be a 2 to 3 BCF type well. We are drilling
a well on our DeVillier prospect right now. It is drilling as we talk. We
are also drilling on our Big Creek prospect. We have some shows in the
Vicksburg and the Yegua. So there's a lot going on. We have a lot of
project areas and we're getting good results. As I mentioned, overall we're
17 for 24 for the year. We've now drilled over 50 wells and we've really
developed a significant expertise in the 3D applications here.
Quickly, in the Northern Rockies, as you know, there are three main project
areas that we had activity in. You may recall that our approach to the
Northern Rockies since our capital is being allocated primarily to the DJ
and the Gulf Coast was to bring in partners and allow them to spend some of
the risk money. One exception to that was our Gold Coast well which we
drilled during the fourth quarter. That well has encouraging log data. It's
shut in for the winter. We're going to be evaluating in the spring. We have
a large acreage position here. On South Jonah about four miles south of the
Jonah field, we participated in a well that was drilled by the McMurray Oil
Company. We ran pipe on the HSR Holmes Federal after encountering a number
of sections that seem potentially productive in both the overly pressured
and normally pressured sands. Again this is a large project area, and we
expect to be doing further testing as we go forward. The third project area
is Pinedale where Ultra Petroleum and Lance Oil And Gas drilled two tests
on our acreage that we farmed out. Operations on these wells have been
suspended and the wells are shut in for the winter under a Bureau Of Land
Management requirement. So in each of these areas we have significant
acreage positions. We have some remaining upside. By and large we're
letting other people spend the risk dollars there. That summarizes the
operational results.
You know, to summarize overall, as I mentioned at the outset, despite what
is really but a bleak landscape, we feel that we have a number of reasons
to be
<PAGE>
optimistic. We have the highest quality combined exploration and
exploitation inventory in our history. As a result of the various steps
that we have taken to consolidate in the DJ and because of the
reaggregation of the producing horizons that was made possible by the Amoco
acquisition, we now have about 5,000 low risk, high rate of return projects
in the DJ. In the Gulf Coast we have amassed, as I mentioned, about 20
major project areas, over 700 square miles of 3D seismic, and rights to
about 250,000 acres. The last couple of years have been devoted to
acquiring acreage and processing and interpreting the seismic. We're now
beginning to harvest an ever increasing inventory of drill sites. As a
result of the over 50 wells that we have drilled in the area and as a
result of the interpretation of over 700 square miles of seismic, we've
developed a real strong 3D technical expertise, particularly as it applies
to the Hackberry, the Yegua, Vicksburg and Wilcox formations. As Jim
mentioned, as we look forward to 1999, we anticipate a cap ex budget of
between $65 and $75 million depending on prices. Drilling expenditures will
be split fairly evenly between the DJ Basin and the Gulf Coast, and while
plans are subject to adjustment depending on results, in the DJ we expect
to undertake about 150 refracs, 15 to 20 new J sand drills, 20 to 30 J sand
deepenings, and about 20 Dakota deepenings. In the Gulf Coast we expect to
drill between 20 and 40 wells, development of previously drilled prospects
will continue, and we anticipate new tests will occur in a number of
prospects including Port Barre, Big Creek and Anuhvac, Bayou Choupique and
Bayou Shafer-Ramos. We will be shooting at least another 200 square miles
of additional 3D seismic during the year also. Finally, despite low product
prices and limiting spending to our cash flow, we believe that our defined
projects will allow us to increase our production by at least 20% during
1999, and provide meaningful reserve growth. And with that I would like to
open it up for questions.
Operator: Thank you Sir. The question and answer session will be conducted
electronically. If you would like to ask a question you may do so by
pressing the
<PAGE>
star key followed by the digit one on your phone. Our first questions from
Ellen Hannon-with Bear Stearns.
Man: Hi gentlemen. This is Lasan Johong actually. Ellen couldn't make it, but
congratulations on a great, excellent operational performance.
Unfortunately, the pricing seems to have been pretty cloudy. Couple
questions on going from your accounting decision to go from your full cost
to successful efforts. Your DD&A seems to have gone from about $5.50 per
BOE to about $5 per BOE. Kind of wondering why that is, even giving some
way to the f$5 million ((inaudible)) write down it doesn't seem like it
should go down that much. And so therefore, going forward, I'm wondering
what the rate should be and, also, could you go over your Gulf Coast plan
again for 1999? I missed it because you went through it really fast. So,
that's the two questions I have right now.
Jim Duffy: Okay, first with respect to DD&A, without getting into a lot of
detail, the calculations are really quite different under full cost and
successful efforts because you do it on a field-by- field method. In any
event, we anticipate that for 1999 and beyond we will have a DD&A rate of
right around $5 per BOE and that includes more than just depletion. That
also includes non-oil and gas properties. So our rate is definitely lower
under successful efforts which is typically the case. We would expect it to
continue in the low $5 range at least for the foreseeable future. With
respect to the plans for the Gulf Coast, as I mentioned the cap ex budget
in total will be between $65 and $75 million. Some will be allocated to
acreage in seismic but on the drilling dollars, we expect that to be split
pretty evenly between the DJ and the Gulf Coast. What that means for the
Gulf Coast is that we expect to be drilling between 20 and 40 wells. These
will include both follow up drilling on prospects where we already had
discoveries and some tests on a number of new prospects. We also expect to
shoot about 200 square miles of additional 3D seismic during the year.
<PAGE>
Man: Okay, great, thank you.
Operator: Our next question comes from Bill Dezellem with Financial Aims
Corporation.
Bill Dezellem: Thank you. Following up on the last question would you please
remind me of what you're looking for in terms of production in 1999 total
BOE. What I'm looking for is total DD&A for 1999.
Jim Duffy: Well, as you know, we tend not to provide projections particularly
in these kinds of calls. I will tell you that in working with the analysts
and providing them with the information about our programs, most of the
analysts currently have us at a little over 13 million BOE for 1999.
Bill Dezellem: So it's a very simple. 13 times five gets you to about $65
million DD&A next year plus or minus.
Jim Duffy: That's right.
Bill Dezellem: That's fair. Second question for you. Relative to the Amoco
properties, you have reduced operating costs I believe you said in the call
by 14%. Is there any additional reduction in operating costs that you
anticipate getting out of those properties that would be part of your
initial push with them as opposed to the ongoing efforts you would have
with any particular property.
Mike Highum: Actually, Bill, I may have misstated that just slightly, 14% was a
reduction that we have experienced in our DJ Basin operations by
integrating the Amoco properties into our existing operations and by
building in additional efficiencies basically. So that is not just on the
Amoco properties. Overall in our DJ operations, we've reduced the operating
cost by $0.40 per BOE. There are
<PAGE>
a number of different reasons for that. One is that obviously consolidation
brings out efficiencies. The second reason is that, and it gets back to
this--one of the reasons that we pursued the consolidation strategy and
that is the reaggregation of these different producing horizons. As you can
imagine, by recompleting or deepening wells we were adding significant
production to well bores which effectively reduces your leasehold operating
cost on a per unit basis. Since our plan for this next year is to continue
doing the same kinds of activities, as you heard we have hundreds of them
set up that include refracs, deepenings to the J sand, and deepenings to
the Dakota, we would expect to have ongoing reductions in our leasehold
operating expense per unit costs.
Bill Dezellem: Let me then come at it from a little different direction. If we
were to isolate the Amoco properties for Amoco wells as the case may be,
what did you see specifically in terms of a reduction in operating costs
for those properties alone? And do you anticipate getting more out that
would be part of the initial piece. It sounds like the answer is yes
because you had a multi-year program as opposed to this being part of any
ongoing business.
Mike Highum: Well, it really isn't possible for us to answer your question
because we don't know what Amoco's operating costs were before we took over
the wells. Therefore the threshold point is the operating cost that we had
at the beginning point of acquiring their wells which is our operating
cost. But we do expect to continue to be able to wring additional
efficiency out. I don't know of any other company that has a lower combined
LOE and G&A per BOE. There might be someone out there, but I don't know who
they are. Nonetheless, I do think that we'll be able to get additional
efficiency out of these wells.
Bill Dezellem: The reason I ask the question, you know, I'll drop it after this,
that if we go back almost a year ago, you folks were talking about, at
least to the best of my recollection, a 20% reduction in the operating cost
of the Amoco properties.
<PAGE>
I'm simply trying to collaborate whether that was a goal which was achieved
or whether that was illusive in 1998.
Mike Highum: No, I'm not sure I remember exactly what you are talking about. I
can tell you that we operate those properties for well below 20% of what
Amoco operated them at. That was part of our analysis when we acquired the
properties. In our hands they're cheaper to operate. We also thought
building into that, now that I think about it, that did include the fact
that we were anticipating utilizing existing wellbores to conduct
activities and thereby increasing production through them. As you can see,
we already got a majority of that during this year and we will experience
more next year. So I think that 20% number is achievable, even beginning
with our operating costs. And, bear in mind, we're not just talking solely
about the Amoco properties here but the number I gave you is for all our DJ
properties.
Bill Dezellem: So it sounds as though if we were to go Amoco only, that yes, you
have achieved that and there's still more to come. If we're looking at all
the properties combined there in the DJ, that it's very well on its way and
with additional work in 1999 you'll most likely be there.
Mike Highum: Yes, I think that's most likely true.
Bill Dezellem: Thank you.
Operator: We'll now move to Charles Wyman with Morgan Stanley.
Charles Wyman: Good afternoon. Quick question. What was your current cash
balance at year-end? I know on your disclosed is current assets and current
liabilities. I was wondering if you could break out for us the amount the
current
<PAGE>
assets that were cash and the amount of the current liabilities that were
short term debt.
Jim Duffy: We had just right at $10 million in cash, and there is virtually no
long-term debt included in current liabilities.
Charles Wyman: What is your current borrowing base and availability?
Jim Duffy: $280 million is the base. We have $230 million out so we have
availability of $50 million.
Charles Wyman: Could you go through your current hedges?
Jim Duffy: Do you want them by bases Charles, or you just want them overall?
Charles Wyman: Overall, how much of your production you have, and if you can
give us roughly what price they would average out to be hedged at.
Jim Duffy: I think I gave that a minute ago. Let me just get to it here. On a
going forward basis, we have real close to 60% of our 1999 production and
1999 gas production hedged at just under $2 per MCF. We have a little over
40% of our oil production and we're adding to that even today. So probably
closer to 45% of our oil production is hedged at just under $15 net both of
those are net back to the wellhead prices.
Charles Wyman: One last question. Your cap ex budget of $65 to $75 million--how
much of that, roughly, do you anticipate spending on exploration?
Mike Highum: Do you include seismic and land in exploration?
<PAGE>
Charles Wyman: Well, if you want to break that out, too, that would be great.
Mike Highum: I would say about half of it. But bear in mind that when I say half
of it that means I'm really allocating half to the Gulf Coast and calling
all costs there exploration even though a number of those wells will be
follow up wells in project areas where we've had discoveries and we are
running at about a 70% success rate there.
Charles Wyman: So that cap ex budget is $60 to $75 million. How much of that
will be land and seismic and how much of that will be drilling?
Mike Highum: No more than $10 million would be land and seismic and the rest
would be drilling.
Charles Wyman: Would that land and seismic be almost entirely in Gulf Coast or
would you have some of that in the DJ, too?
Mike Highum: Most entirely in the Gulf Coast. We might do a little bit on DJ and
a little bit in the Northern Rockies.
Charles Wyman: Wonderful, thank you very much.
Operator: The next question comes from Chris Sheehen with John S Herold
Research.
Chris Sheehen: Yes, gentlemen, of the 38.4 million BOE reserve adds how much was
attributable to the new field spacing rules in the DJ. Was it the 29
million BOE talked about in the second quarter?
Mike Highum: Boy, Dale, are you on the phone?
<PAGE>
Dale: Yes I am, Mike. Approximately half of that was as a result of the field
rule change in the J sand down spacing and about half of that was as a
result of reserves we booked related to Codell refracs.
Chris Sheehen: Okay, so when you spoke about, I believe it was the second
quarter ((inaudible)), about the 29 million BOE of additional bookings,
were there some revisions downward from that?
Dale: We've had 16 million BOE of reserves that were essentially unbooked as a
result of year end product prices.
Mike Highum: Let me clarify that a little bit for you. About 30 million of the
38 million were attributable to the DJ. The remaining were basically
attributable to Gulf Coast and of the 30 million attributable to the DJ
approximately half was down spacing of the J sand.
Dale: I should also point out that we haven't booked all of the reserves out
there. I mean it isn't like we went in and booked everything that was
available.
Man: Mike I think one of Chris's questions is how does that relate to what we
said in the second quarter and I think that ratio is about the same in the
second quarter. Half of that was from J sand down spacing new reserves and
half from Codell refracs.
Chris Sheehen: Okay, thanks very much.
Operator: John Selser from Lehman Brothers now has the next question.
John Selser: Jim, the hedging that you gave out on the yearly basis, how's that
on a quarterly basis? Is it spread pretty evenly or--?
<PAGE>
Jim Duffy: It is, actually. It's very even although we have, at the moment,
less gas hedges in the November-December months this year. We're beginning
to add to those currently, but most of our gas hedge position runs out
through the end October pretty evenly quarter to quarter. We're a little
more heavily hedged in the first quarter. We have about 60% of our gas
production hedged in the April-October period during different months and
then oil is pretty even from April and beyond and a little heavier in the
first quarter. At some point I can give you specific quantities by quarter
if you want them, John.
John Selser: Yeah, I'll follow up on that on another call. The other things I
mean you covered so much very thoroughly, but at the M. Half Circle, do you
think you have some follow up wells there?
Mike Highum: Tony, are you on?
Tony Church: Yes. We've got an additional deeper target there, but in terms of
specific development as in PUD offsets, there would be none on this well.
In terms of prospects in the area with a similar look, we do have two
additional follow up potentials.
John Selser: And what's the status of the well at Big Creek and then when might
you think you could spot a well at Point Barre?
<PAGE>
Tony Church: The status of the well at Big Creek is that we're drilling right
now. We would hope to be at TD probably early next week, logging
thereafter. In terms of Port Barre, we've had a little bit of trouble with
a land piece that we're trying to get into place right now. So I'm guessing
that we're probably still 6 weeks away at least, maybe 2 months away from a
spud at Port Barre.
John Selser: But possible this year then?
Tony Church: Oh absolutely.
Operator: Our next question comes from Bruce Mahood with Mahood Investments.
Bruce Mahood: Yes, when is the borrowing base schedule to be reviewed?
Mike Highum: We'll begin the process within the next 60 days and we'll have a
formally predetermined volume base, Ted, by when?
Ted: I would say by the beginning of April.
Bruce Mahood: Okay, with the long term debt now exceeding the PV 10, do you
anticipate the borrowing base being lowered?
Jim Duffy: I don't anticipate it being lowered or at least not significantly.
The long term debt exceeds the PV 10 using December 31 prices only; it
doesn't exceed the future strip prices and some other. . .. I mean,
depending upon the price deck you use, you get very different results,
obviously, so we don't I mean we actually have on a sort of bank debt to PV
10 basis using the bank's price deck we have significantly more PV 10 per
outstanding bank debt this year than we did last year. We do not anticipate
there being a boring base issue.
Bruce Mahood: Okay, thank you very much.
Operator: Evan Templeton with Bank Boston Robertson has the next question.
<PAGE>
Evan Templeton: Just two quick questions. First of all, can you give the current
production rates and also you mentioned the possibility of non-core asset
sales. Just how can you give us an idea of what magnitude and from where.
Jim Duffy: I'll answer the second one first. We still have a few packages in
the DJ that we're working on that are sort of part of our ongoing project
where we are continuing to divest the non-core parts of that. It could be
as much as $10 to $15 million of divestitures over the course of the year.
When you say production rates, are you looking for end of quarter exit
rates by area, is that what you want?
Evan Templeton: Yeah, if you can give that actually and current rates that
you're producing it by area, that would be helpful.
Jim Duffy: I don't have them as of today but I suspect they're not terribly
different than this. Do you want them by BOE, oil, gas or how?
Evan Templeton: BOE is fine.
Jim Duffy: Okay. BOE in the DJ--we're currently producing right around 21,000
BOE a day--that's just DJ, non-Amoco. The Amoco piece is about 9,000 and on
the Gulf we're close to 11 hundred BOE per day.
Evan Templeton: Great, thank you.
Operator: Seth Appel with Wexford Management has the next question.
Seth Appel: My questions have already been answered thank you.
Operator: Jeff Robertson from Salomon Smith Barney has a question.
<PAGE>
Jeff Robertson: Good afternoon. A number of my questions have been answered, but
Mike, can you talk about the reserves that you've found and the successful
Dakota wells? Were there any surprises in what you drilled there?
Mike Highum: Dale, do you want to talk about that?
Dale: Sure. The Dakota has been a really great program as Mike mentioned in the
press release. We had finding costs of about $2.40. The reserves were
pretty close to what we were expecting. If you really went into this and
you look back in time a year ago we were expecting slightly better finding
costs. It really was cost driven as a result of problems and really getting
up the learning curve and where we think we...depending how best to get the
gas out of the ground. But really the reserve area is pretty much on
projection--the cost you know. We were hoping for better than $2.40 a
barrel, even though $2.40 is a very good number.
Seth Appel: Okay. Are you, what kind of cost trends are you seeing service wise
in the DJ?
Dale: They're down. We're seeing from a drilling standpoint . . . as you know
steel prices are down. That's helping our pipe prices. We have seen some
small reductions in our frac cost as well as various other vendors. Rigs
are slightly down. Service units are down a little bit more. So we have
seen slight decreases. Keep in mind that the DJ doesn't exactly follow the
national trend of the big ups and big downs. We haven't seen that big of
swings. We saw a fairly sizable decrease, I would say, last April-May in
our frac costs and quite honestly, we're continually doing that as a result
of both. Optimizing our design as well as seeing some small reductions in
vendor pricing.
<PAGE>
Mike Highum: Seth, this is Mike. Just to elaborate on a couple of things there
real quickly. The results we're achieving from the Dakota, as Dale says,
overall are consistent with what we expected. It's a very complex channel
system and with different types of sands. In different areas, the results
are pretty variable. We can go from no production to a couple million a
day. Fortunately, these are deepenings, so the cost is a lot less than a
stand-alone well. What Dale said--the costs were a little bit higher
because of some problems that he referred to. What he's really talking
about is most of these deepenings are in wells we took over from Amoco and
we're finding at times that Amoco left things in the bottom of the hole and
other issues like that which complicate our ability to deepen them. So
where we don't have Amoco putting stuff in the bottom of the wellbore,
we're able to complete these relatively easy and cheaply.
Seth Appel: Mike, do the 38 Dakota data points that you have now change your
interpretation much where the success rate ought to improve over time?
Mike Highum: Dale, what do you think?
Tony Church: This is Tony actually. Our sub surface stratigraphic interpretation
is excellent and there's no question that we have more data incorporated
into our understanding than anybody else. But with that said, we've clearly
identified and worked our way out from the sweet spots and the background
statistics are not changing, all that dramatically, as to where the overall
program is going. That is internal to us at least, not relative to industry
wide statistics.
Seth Appel: Okay, and then lastly, Mike, are you doing any thing on either
exchanges with the other operators out there to kind of consolidate more of
the interest in wellbores?
<PAGE>
Mike Highum: Well, as you know, we did one deal this year and there are, its
fair to say that there are continuing conversations all the time. I think
that you'll see more consolidation. I actually think that you're going to
see consolidation go beyond just the property level. Ultimately this field
needs to be consolidated from a pipe and processing standpoint also.
Seth Appel: Have the BP/Amoco or the Sempra/KN Energy deals changed much as far
as the pipe and processing?
Mike Highum: It hasn't changed much yet.
Seth Appel: Okay do you foresee that?
Mike Highum: Actually, to tell you the truth, I think that both of those
transactions provide additional opportunities.
Seth Appel: Okay, all right, thanks.
Operator: If you have a question that has already been answered you may remove
yourself from the que by pressing the pound key. Our next question comes
from Bernie Casey excuse me with Fort Washington Investments.
Bernie Casey: What was your cap ex in the fourth quarter?
Jim Duffy: Hang on, in the fourth quarter it was approximately $20 million.
Bernie Casey: And the line exploratory and abandonment costs is that something
that was previously capitalized or?
<PAGE>
Jim Duffy: Yes, well, the abandonment costs are part of the successful efforts
method and on a continuing basis we will be expensing that in
non-successful as well as non-productive drilling cost on our exploration
projects. That's the other piece that's in there.
Bernie Casey: So you had $20 million that was capitalized and then there was
another $9.5 million that was expensed but it was kind of. . ..
Jim Duffy: Yeah, that was a non-cash charge.
Bernie Casey: That was a non-cash charge.
Jim Duffy: Right, that was an impairment or a write-off of costs that were
previously on the books.
Bernie Casey: Okay, so that's not something that will be a much lower number
going forward?
Jim Duffy: It shouldn't be anything because basically, as I said earlier, the
only two ongoing cost centers we have at this point under successful
efforts are the DJ and the Gulf Coast. And at the present time we have a
very significant cushion for any further impairment. We've written off
virtually all the cost on other project areas. So we don't anticipate there
being, at least in the near future, any additional impairment charges.
Bernie Casey: Okay, now, how do your reserves break down by region?
Jim Duffy: Well, we have just a little over 4 million BOE of reserves in the
Gulf Coast at year end and the balance is in the DJ.
<PAGE>
Bernie Casey: How much capital have you guys invested in the Gulf Coast to date?
Mike Highum: Well most of the capital we've invested in the Gulf Coast to date
has been in land and seismic. So you wouldn't expect to see any of that
reflected in year-end reserves. We've spent about $50 million total in the
Gulf Coast and about $12 million of that to date has been in drilling.
Bernie Casey: Okay, that's been what I'm trying to . . ..
Mike Highum: But that number is converting. We've spent a couple years putting
together all of the prospects, the seismic and the acreage. As we go
forward, more and more of it will be spent on drilling. The discounted
future net cash flow from wells drilled is running about 3.5 to 1 on
drilling dollars spent.
Bernie Casey: Okay, now, with regards to any future bank adjustment, is there a
formula, I mean I would assume that there will be a downward revision in
that--is there a formula that they go by based on PV 10, or I mean. . . .
Jim Duffy: There is a formula. Obviously, it's not one they share widely but I
will tell you that in our discussions with the bank, our calculations show
that using their current prices, primarily because we really did not have a
stretch borrowing base at all--based on last year's reserves that when you
take into account the debt that was repaid as result of the sale of the
Mid-Continent properties, the bank debt that was repaid as a result of the
subordinated notes, and you compare that to the reserves in the PV 10 to
even lower prices at December 1998, you could actually make a pretty good
case that the borrowing base should be increased. We don't need it; we
don't intend to do that at this point in time, and obviously its up to the
bank or the bank group, so you know anything can happen. But we do not
anticipate there being any particular issues at all in our borrowing base.
<PAGE>
Bernie Casey: Thank you.
Operator: Our next question comes from Paul Leibman with Petrie, Parkman and
Company.
Paul Leibman: Good afternoon.
Man: Hey, Paul.
Paul Leibman: If I'm not mistaken, DJ gas production is getting back to the peak
it hit back in the early 1990s. I'm just curious, is there a market locally
for all of the DJ gas that's being developed, and how are you currently
marketing your DJ gas? And might you comment on where you see
differentials.
Mike Highum: Dale, or Jim, do you guys--?
Dale Cantwell: As far as the market goes, the front range is a very big,
dynamic, growing market. If nothing else, we see it getting bigger and
bigger, particularly with a lot of the announced co-gen and generation
activities that are forthcoming here fairly shortly. That's the first
thing. We're selling a lot to both the electrical market as well as into
typical industrial commercial sources. How we market it really has not
changed a lot. We're out there as usual looking for the highest prices and
selling it both long term and short term trying to optimize our portfolio.
Jim Kincaid: This is Jim. One of the biggest things over the course of the last
year has been HS willingness to make sure the quantity moves by taking
certain spread risks among pipelines as well as willingness to trade basis
into the forward months to make sure we realize our corporate goals.
Regarding your comment on basis going forward, there's been a continuing
trend to narrowing basis in the Rocky Mountains versus the Gulf Coast. This
past winter, Rockies was indeed
<PAGE>
the strongest area in the country. Going forward we see basis about $0.10
narrower for the April-October timeframe versus last year. So we've been
commenting for the last two years that we see a narrowing difference
between Wyoming production and Mid-Continent production and the current
marketplace gas produced in Denver is as much like Mid-Continent gas as
it's ever been. I mean it's trading virtually flat, if not over the
Mid-Continent ten months out of the year.
Mike Highum: For those of you who don't know who that is that's Jim Kincaid
who's head of HS Energy Services that handles all of our marketing and
trading activity.
Man: You know, Paul, one of the--I mean, this is sort of embedded in what both
Jim and Dale were saying, but one of the really key differences now in the
DJ versus the way things were earlier in the 1990s is that the amount of
additional pipeline capacity in the DJ is significantly greater now than it
was a few years ago. So we have access to pipelines for the purpose of
exporting gas, particularly in the non-winter months. We basically keep
most of our gas on the local markets in the winter. But we now have a great
deal of relatively low cost transportation out of the basin to move gas
into these other markets in the non-winter period.
Jim Kincaid: And I would say that we ((inaudible)) into two ways. Number one:
we seek to hold the transportation in our name with a low fixed cost
obligation so if we use it that's great; if we don't, it doesn't cost as
much. Then there are also financial tools available now that weren't there
before. It's very easy to trade certain financial and swap instruments.
They give us huge flexibility in what we do literally everyday, with how
our gas is sold. So flexibility in terms of physical transport, as well as
the financial options, help us tremendously.
<PAGE>
Paul Leibman: So again, you're not running into any gathering or marketing
bottlenecks in terms of your ability to move growing volumes of gas out of
the DJ.
Man: NO.
Mike Highum: Well let me qualify that on the marketing side. Paul, if we
undertook an unlimited program, we would run into some constraints and we
have built that into our cap ex planning. We would run into some pipeline
constraints if we unleashed a sort of unlimited exploitation program above
what we've talked about and laid out as our plan for this next year. There
are a number of different issues associated with this including compression
on the line, and our cap ex program is built around that. Nick, would you
care to elaborate on that at all.
Nick Sutton: That's a fair statement. We're also working with the various third
parties that facilitate the movement of our gas and identifying and
eliminating any bottlenecks that we might see.
Man: We're well aware of what constraints are and they are built into a nifty
program that Nick developed that does a linear programming and portfolio
analysis and determines the weighting of and types of the projects that we
do in the DJ.
Paul Leibman: Well, I'm glad somebody's tracking all the molecules. Thanks a
lot.
Operator: We'll now move to Tuan Pham with Morgan Stanley.
Tuan Pham: Yeah, just a couple questions. What were the net tax benefits from
property impairments and sales for the fourth quarter of 1998 and fourth
quarter of 1997? And secondly, do you have a net income number for the
quarter? Being the fourth quarter of 1998 using the full cost method?
<PAGE>
Jim Duffy: We don't have that, although we could probably get something for
you. But we don't have it; we have not calculated it as yet. Does anybody
in San Francisco have the tax benefit number from the impairments.
Tuan Pham: As well as sales.
Woman: No, Jim.
Jim Duffy: We will get back to you with that.
Tuan Pham: Okay, thank you.
Operator: We have a follow up question from Jeff Robertson with Salomon Smith
Barney.
Jeff Robinson: Hi Jim. Can you give me the capitalized interest number for the
fourth quarter?
Jim Duffy: Yes, it was $2.3 million.
Jeff Robertson: Will that change much going forward now under successful
efforts?
Jim Duffy: Well, it will be less than it has been in the past just because we
no longer have to capitalize interest on some of the G&G and other costs
that are accumulated in the undeveloped account. Under the accounting
rules, we don't have any choice but to capitalize this interest. It's not
because we want to obviously. So that account has been significantly
reduced as a result of writing-off all the G&G and some of the other costs
that have come out of the undeveloped accounts. So the number will be
smaller going forward and that
<PAGE>
probably represents a reasonable quarterly estimate on a going forward
basis for at least the next couple of quarters.
Jeff Robertson: Okay and did you all file an 8-K with the other quarters
restated last year? Have you done that yet?
Jim Duffy: We've not, no. This is the first time we've released these numbers
but we definitely will amend all the previous years and quarters.
Jeff Robertson: Okay, thanks.
Operator: Ellen Hannon-with Sterns has another question.
Lasan: Hey guys this is Lasan again. Just a quick, back of the envelope
calculation tells me that if you're going from about $3.14 per BOE on your
debt cost to about $2.75, that implies rough debt to total capital ratio of
about 65, 66%, is that right?
Jim Duffy: Well, you've got to build into the equation some reserve growth.
too. So the $2.75 is sort of our estimate of what we think we can do to
bring down some debt and our estimate of what we can do to increase
reserves.
Lasan: So, you're attacking it from both directions.
Jim Duffy: Yeah.
Lasan: And a follow up question on one of the other questions that were asked.
Kind of alluded to the fact that there's some opportunities in the
marketplace to do some consolidation in the DJ and in the Gulf Coast. Are
you guys looking at anything specific or is it just something that you are
speculating on?
<PAGE>
Nick Sutton: I'll answer that, Mike. We are always in the market. We are always
looking at opportunities. We don't comment on whether it's general
investigation or whether there's any thing specific. Mike talked earlier
about core competencies, and we think one of our core competencies is the
ability to move quickly and intelligently on opportunities when they arise
so its just part of what we're doing. We do believe that there are
opportunities out there and there will continue to be opportunities.
Lasan: Okay, thank you.
Operator: We have a follow up question from John Selser with Lehman Brother.
John Selser: Yeah, Jim ,you gave the current production and equivalent. Do you
have that in oil and gas broken out?
Jim : Yeah, I've got the DJ as I said in two pieces. It's with and without
Amoco so I'll give you without Amoco first. Oil is 4,800, gas about 99
million. Amoco is 1,000 barrels of oil a day and about 48 million in gas.
The Gulf Coast is just under 6 million a day in gas. And a couple hundred
barrels of oil.
John Selser: Alright, thank you.
Operator: Again if you have a question you may ask your question by pressing the
star key followed by the digit one on your phone.
Nick Sutton: While we're waiting for that, I might ask a question of Jeff
Robertson. I see where today Jeff and Tom and his other colleagues raised
their call on 2000 gas to $2.75 and if he would comment on that I'd be
happy to provide him time on the mike. Yeah, he might be blocked out from
commenting right now.
<PAGE>
Operator: Are you speaking of Mr. Church?
Man: No, Jeff Robertson.
Man: From Salomon Smith Barney.
Operator: Mr. Robertson, if you would like que back up please. I appears that
are there more questions, Mr. Highum, I will turn the call back over to you
for any additional or closing remarks.
Mike Highum: I just want to thank everybody for listening in. As I said, I think
that despite the fact that it is a pretty tough environment right now we
had a good year and we expect to have an even better year in 1999. If you
have any additional questions or you'd like any additional information,
please feel free to contact any of us here and we'll get to you. Thank you
very much.
Operator: That concludes today's conference. Thank you for your participation
and have a good day.
END
