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 - NOVEMBER 8, 2000
(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
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FORM 8-K
HS RESOURCES, INC.
November 8, 2000
ITEM 5. OTHER EVENTS
On November 8, 2000, we issued a press release announcing a
presentation by us at the Merrill Lynch Energy Conference on Thursday, November
9, 2000 at 4:00 PM Eastern Standard Time.
ITEM 9. REGULATION FD DISCLOSURE
In accordance with General Instruction B.2 of Form 8-K, the following
information shall not be deemed "filed" for purposes of Section 18 of the
Securities Exchange Act of 1934, nor shall it be deemed incorporated by
reference in any filing under the Securities Act of 1933, except as shall be
expressly set forth by specific reference in such a filing.
FINANCIAL OUTLOOK AS OF NOVEMBER 7, 2000
The following sets forth our current estimates of certain significant
operating and financial data for the fourth quarter of 2000, the first quarter
of 2001 and calendar year 2001. These forecasts are forward looking statements
under the Federal securities laws. Although we believe that the expectations
reflected in these forecasts are reasonable, such expectations are based upon
assumptions and anticipated results that are subject to numerous uncertainties.
Actual results may vary materially from these forward looking statements due to
a variety of factors, including drilling results, oil and gas prices, the effect
of variable factors on the net price realized by us under gas swap contracts,
changes in our hedge positions, industry conditions, the prices of goods and
services, the availability of drilling rigs and other support equipment and
services, the availability of capital resources, labor conditions, our
objectives, business judgment or strategies, and other factors both within and
outside of our control. The forward looking statements herein are qualified in
their entirety by the foregoing factors, the factors discussed below, and by the
factors set forth in our report on Form 10-K, filed March 24, 2000, and various
other filings with the Securities and Exchange Commission.
The following forecasts reflect our view of continuing operations only. We
do not forecast transactions or the effect of transactions and no implication
should be drawn from the information released herein as to such matters. We do
not assume any obligation to update any information contained herein. Where
appropriate for the fourth quarter of 2000 and the first quarter of 2001, the
primary drivers of financial and operating results are given in ranges.
Elsewhere, single point values are given. These single point estimates represent
approximately the midpoint of our estimates of the specified
information. Actual results may differ materially from these estimates.
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PRODUCTION AND PRICING
NATURAL GAS
We expect our natural gas production to be the following for the fourth
quarter of 2000 and first quarter of 2001:
Fourth Quarter 2000 First Quarter 2001
------------------- ------------------
Low Mid High Low Mid High
--- --- ---- --- --- ----
Bcf 17.0 17.6 18.0 17.9 18.9 19.3
MMcf/day 185 191 196 195 205 210
For calendar year 2001, total gas production should reach 78 Bcf, or an
average of 214 MMcf per day. For each of the periods indicated, the most
significant factors contributing to the difference between the lower and higher
ranges is the timing related to the online dates of new gathering and processing
facilities in the D-J Basin and initial production dates on recently drilled
wells in the Gulf Coast. Problems associated with gathering and processing
facilities generally could cause production to be less than forecast.
In order to accurately estimate our wellhead gas price, adjustments need
to be made when compared to the generally available NYMEX strip. Typically,
because of the higher Btu content of our gas, the price needs to be adjusted
upward. However, this upward adjustment must be offset by the location
difference (e.g., the D-J Basin rather than at the Henry Hub in Louisiana).
Overall, our average realized gas revenue per Mcf on unhedged volumes, including
the impact of our ownership of the Wattenberg Gathering System, is expected to
be approximately equal to the NYMEX Henry Hub Index for the fourth quarter of
2000 and the first quarter of 2001. For calendar year 2001, the basis
differential is estimated to be $0.05-$0.10 below the NYMEX Henry Hub Index.
(For example, if the Henry Hub Index is $4.00/MMBtu, our realized wellhead
revenue before hedges would be $3.90-$3.95 per Mcf.) Our natural gas hedge
position is fully disclosed in our most recent Quarterly Report on Form 10-Q. We
have not added any new positions since that time, but we may change our
positions in the future.
CRUDE OIL
We expect our oil production to be the following for the fourth quarter of
2000 and first quarter of 2001:
Fourth Quarter 2000 First Quarter 2001
------------------- ------------------
Low Mid High Low Mid High
--- --- ---- --- --- ----
MBbl 675 700 725 715 750 775
MBbl/day 7.3 7.6 7.9 7.8 8.2 8.4
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For calendar year 2001, total oil production should reach 3 MMBbl, or an
average of 8.2 MBbl per day. Since most of our oil is produced with our gas, the
factors discussed above that affect gas production also affect our oil
production. In order to accurately estimate our wellhead oil price, adjustments
need to be made when compared to the generally available NYMEX strip. Typically,
to reflect transportation and energy content per barrel, the price needs to be
adjusted downward. As a result, our average realized oil price on unhedged
volumes is expected to average between $1.25-1.50 below the NYMEX WTI Index. Our
oil hedge position is fully disclosed in our most recent Quarterly Report on
Form 10-Q. We have not added any new positions since that time, but we may
change our positions in the future.
Overall, for calendar year 2001, we believe that we can achieve 15%
production growth over full year 2000 volumes and that the ratio of oil to gas
will remain relatively constant. With respect to all of the above periods, we
anticipate that approximately 80% of total production will come from the D-J
Basin and the remainder from the Gulf Coast.
OTHER REVENUES
Gathering and transmission system revenues from third parties should be
approximately $3.3 million in the fourth quarter of 2000 and first quarter of
2001. For the full year 2001, such revenues should be approximately $14 million.
Note that these third party revenues reflect approximately 45% of total
gathering and transmission revenues. The remaining 55% arise from the revenue
stream attributable to our own gas production. That amount (net of related
expenses) is reflected in our net wellhead gas revenue per Mcf, as discussed
above.
Other gas revenues are expected to be approximately $2.0 million in the
fourth quarter of 2000 and first quarter of 2001, and approximately $8 million
for full-year 2001. Net income from trading and transportation before taxes is
expected to be approximately $0.5 million in the fourth quarter of 2000 and
first quarter of 2001, and approximately $2.0 million for full-year 2001.
EXPENSES
PRODUCTION TAXES
Production taxes are expected to be approximately 9% of oil and gas
revenue, including the effects of hedging, for the fourth quarter of 2000 and
approximately 8% for all of calendar year 2001. In addition to the factors
discussed above, actual production taxes may vary from our estimates as the
result of varying production volumes, commodity prices and tax rates.
LEASE OPERATING EXPENSE (LOE)
Our lease operating expense is expected to be approximately $0.35 per Mcfe
in the fourth quarter of 2000 and the first quarter of 2001, and
approximately $0.33 per Mcfe for the remainder of all of calendar year 2001.
Actual LOE may vary from our estimates as the result of varying levels of
productivity in new and existing wells or as a result of changes in the cost of
goods or services.
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DEPRECIATION, DEPLETION, AND AMORTIZATION (DD&A)
We record DD&A (a non-cash charge) as an expense in order to flow
through the income statement charges which have been capitalized on our balance
sheet. The midpoint of the range for DD&A is $0.72 per Mcfe for fourth quarter
2000, first quarter 2001 and calendar year 2001. DD&A is calculated based on a
number of different factors, the major one of which is our booked proved
reserves at any given point. When new proved reserves are calculated at year-end
2000, DD&A rates are likely to change. However, the direction and magnitude of
such a change or of future changes are not presently determinable.
GENERAL AND ADMINISTRATIVE EXPENSE (G&A)
For fourth quarter 2000, we anticipate that G&A will be approximately
$0.10 per Mcfe. During the first quarter of 2001 and calendar year 2001 we
anticipate the G&A will be approximately $0.09 per Mcfe. The difference in G&A
expenses for fourth quarter 2000 versus 2001 results largely from spreading
relatively fixed costs over a larger production volume anticipated during 2001.
G&A can also change as a result of changes in the cost of goods and services.
GATHERING AND TRANSMISSION EXPENSES
Third party gathering and transmission expenses for the fourth quarter
of 2000 should be approximately $1.4 million. Many of the expenses associated
with our gathering and transmission are relatively fixed. This estimate of costs
reflects expectation of incremental throughput in the fourth quarter above that
of the third quarter. For calendar year 2001 total gathering and transmission
expenses attributable to third party volumes should be approximately $5.0
million, split relatively evenly across all four quarters, again reflecting our
anticipation of incremental throughput on the system. Expenses could be lower if
incremental throughput is not achieved.
EXPLORATORY AND ABANDONMENT EXPENSE
Exploratory and abandonment expense is a value which can fluctuate
dramatically quarter to quarter, depending on the timing of exploratory
expenditures, the abandonment of leases, and the recognition of productive or
dry holes. No forecast of these expenses can be expected to be accurate. For
fourth quarter 2000 we are utilizing for planning purposes exploratory and
abandonment expense of approximately $4.5 million. For calendar year 2001, a
total exploratory and abandonment cost assumption of $20.0 million is
appropriate. For modeling purposes it is probably appropriate to assume that the
expenses are made in equal amounts across all four quarters, although it is
highly unlikely that actual results will be consistent from quarter to quarter.
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GEOLOGICAL AND GEOPHYSICAL COSTS (G&G)
G&G costs are largely discretionary, and typically are a function of how
much pre-drilling exploratory work is undertaken. We expect G&G to be
approximately $5.0 million in the fourth quarter of 2000, with a total G&G
expenditure of approximately $25 million in 2001. For modeling purposes, it is
probably appropriate to assume that the expenditures are spread equally across
the four quarters of 2001, although such expenditures
are typically more sporadic and less consistent than that. G&G costs can change
materially from the current forecast as results of drilling projects are
obtained and as our exploration plans and strategies change throughout the year.
INTEREST COSTS
Income statement interest costs for the fourth quarter should be
approximately $11.7 million. In addition, we expect to record
capitalized interest of $1.6 million for that period. For 2001, aggregate
interest costs expensed should be approximately $43 million, with an additional
full year capitalized interest of $6.0 million. The lower quarterly interest
costs result largely from the anticipated continuing reduction of debt.
LEASE COSTS
We expect to enter into an operating lease for certain gas gathering,
compression and processing assets. The effective date of this lease should be
approximately the end of the first quarter 2001. Therefore no lease expenses
will be recognized in the fourth quarter of 2000 or the first quarter of 2001.
Aggregate lease expenses for the balance of 2001 will be approximately $2.1
million spread equally across the remaining three quarters.
TAXES
We expect to record income tax liability at a rate of approximately
38.5%.
SHARES OUTSTANDING
For the fourth quarter of 2000, we expect to have weighted outstanding
number of shares, assuming dilution, equaling 18.9 million shares. For calendar
year 2001 that number should be 18.7 million shares.
CAPITAL EXPENDITURES
We expect our base level capital expenditures to total approximately $30
million in the fourth quarter of 2000, $40 million in the first quarter of 2001
and $125 million for calendar year 2001. The full year 2001 amount could vary
materially depending on the result of initial exploration and the scope and
timing of other exploratory projects. With respect to all of the above periods,
we anticipate that approximately 55-60% of total capital will be spent in the
D-J Basin, 35-40% in the Gulf Coast and the remainder in other areas. In
addition, approximately 70-80% of these expenditures will be for drilling
(exploration and development) with the remaining 20-30% spent on land, and other
seismic activities.
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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: November 8, 2000.
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