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 - OCTOBER 26, 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.
October 26, 1999
ITEM 5. OTHER EVENTS.
On October 26, 1999, HS Resources, Inc., a Delaware corporation ("HSR"
or the "Company"), issued its third quarter earnings press release. A copy of
the earnings press release is attached hereto as Exhibit 99.1. The transcript of
the earnings conference call held Tuesday, October 26, 1999, as edited by the
Company, can be found on the Company's internet site at
http//www.hsresources.com. Click on Investor Info and then click on Quarterly
Earnings Conference Call to listen to the audio version or click on Transcript
to read the transcript. The transcript is also attached hereto as Exhibit 99.2.
ITEM 7(c). EXHIBITS FILED.
Exhibit Number Description
- -----------------------------
99.1 Earnings Press Release, dated October 26, 1999.
99.2 Transcript of Earnings Conference call
2
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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 9, 1999.
3
FOR IMMEDIATE RELEASE
October 26, 1999
HS RESOURCES ANNOUNCES THIRD QUARTER RESULTS
San Francisco, California - HS Resources, Inc. (NYSE:HSE) today announced its
operating and financial results for the quarter ended September 30, 1999. During
the quarter, the Company earned $4.8 million, or $0.25 per share, and reported
operating cash flow of $24.2 million, or $1.26 per share. That compares to a
loss of $8.1 million, or $0.43 per share, and operating cash flow of $13.7
million, or $0.73 per share, for the comparable prior year period. Excluding an
after-tax gain of $1.4 million in the current quarter and an after-tax loss of
$4.2 million in the prior year quarter resulting in each case from the sale of
certain non-core properties, earnings for the most recent quarter were $3.4
million, or $0.18 per share, compared to a loss of $4.0 million, or $0.21 per
share, for the third quarter of 1998.
During the quarter, the Company produced 18.33 billion cubic feet of gas
equivalent (Bcfe), slightly more than the 18.30 Bcfe produced during the prior
year period. However, after excluding 2.21 Bcfe of production attributable to
certain Mid-Continent properties that were sold effective September 1, 1998,
which resulted in the repayment of approximately $150 million of debt,
production for the current quarter was 14% higher than the prior year period.
Approximately 81% of the current quarter production was natural gas.
Quarterly production revenues, including the effects of product price hedging,
increased 32% from the comparable prior year period, from $32.9 million to $43.5
million, resulting primarily from increased average product prices. The
quarterly average gas price, including hedging activities, was $2.14 per
thousand cubic feet (Mcf), a 27% increase from $1.69 realized in the third
quarter of 1998, while realized oil prices increased 53%, to $20.04 from $13.07
per barrel (Bbl). Hedging activities decreased realized prices by $0.28 per Mcf
and $0.10 per Bbl in 1999. For the comparable prior year period, hedging
increased realized prices by $0.05 per Mcf and by $0.78 per Bbl.
Lease operating expense decreased by 13%, from $7.8 million to $6.8 million, and
from $0.43 to $0.37 per Mcfe ($2.56 and $2.22 per Boe, respectively). General
and administrative expense was reduced by 35%, from $2.2 million to $1.5
million, and from $0.12 to $0.08 per Mcfe ($0.74 to $0.48 per Boe). The lower
lease operating and overhead expenses reflect the effects of the Mid-Continent
sale and efficiencies resulting from the ongoing D-J Basin consolidation
program. Depreciation, depletion and amortization expense declined 15%, from
$15.4 million to $13.1 million ($0.84/Mcfe and $0.71/Mcfe, respectively)
reflecting the Mid-Continent sale and the impact of new reserve bookings at
June 30, 1999. Interest expense, both on an aggregate and per-unit basis,
declined 2%.
For the first nine months of 1999, the Company reported net income of $5.0
million, or $0.27 per share, compared to a loss of $7.3 million, or $0.39 per
share, in the prior year period. Excluding the effects of property sales during
the periods, the Company earned $4.3 million, or $0.23 per share, compared to a
loss of $3.2 million, or $0.17 per share, for the comparable 1998 period.
Production for the nine months decreased 4% to 54.2 Bcfe from 56.2 Bcfe in 1998,
which included eight months of production from Mid-Continent properties sold in
1998, or 8.9 Bcfe. Adjusted to reflect the sale of the Mid-Continent properties,
production increased by 15%. Production revenues were relatively flat at $116.3
million compared to $116.6 million in 1998, as realized prices for the first
nine months
<PAGE>
of 1999 increased 4% to $15.51 per Bbl and $2.04 per Mcf from $14.92 per Bbl and
$1.96 per Mcf in 1998. Aggregate operating cash flow increased 8%, from $56.4
million to $61.3 million, and per share cash flow increased from $3.03 to $3.26.
HS Resources also announced the status of certain field operations.
During the third quarter, in the D-J Basin the Company conducted 58 Codell
refracs, bringing the program total to nearly 450. Nine new J-Sand wells were
drilled and completed, and thirteen existing wells were deepened to the J-Sand.
The Company also performed eleven Dakota formation tests. As previously
announced, effective July 1, 1999, HS completed a D-J Basin property exchange
with Patina Oil & Gas in which HS further consolidated interests in company
operated wells, contributing to enhanced operating efficiencies. D-J Basin
capital expenditures for the nine months ended September 30, 1999, were $36.8
million compared to $60.3 million in the prior year period. Despite the lower
level of capital expenditures, the Company's D-J Basin net quarterly production
increased to 16.2 Bcfe, or 176 MMcfe per day.
In the Gulf Coast region, production increased to 2.2 Bcfe, a 15-fold increase
over the prior year quarter, and a 16% increase over the second quarter of 1999.
Two wells were successfully drilled in the Indian Village project area, in which
HS is the operator and has a 50% working interest (WI). These two wells are a
continuing extension of the successful "rotated Hackberry" program in southern
Louisiana. Preliminary reserve estimates on those wells show gross reserves of
3-4 Bcfe per well. The Company is now five-for-five in Indian Village, including
a third well which was drilled at quarter-end and is currently being completed
as a producer. The Indian Village prospect has been highly successful, and one
well, the Louis Adams #1, has been on line for more than 200 days, producing at
a rate of 15 MMcf and 225 Bbl per day. Gross reserves for the Adams well are
estimated to be 13 to 16 Bcfe. Another three to four wells could be drilled in
the project area by year-end, with six to eight additional prospects identified.
At Caney Creek (25% WI) drilling commenced on the Pierce Estate #3 as a follow
up to the successful Pierce Estate #2, which is waiting on hookup. In Devillier
(25% WI), one dry hole was drilled, and in Big Creek (100% WI) three
unsuccessful wells were drilled; two tested the Yegua formation, the other
tested Miocene sands. Six wells drilled earlier in the year in various project
areas await pipeline hook-up. These wells could add another 7 to 10 MMcfe per
day of net production. Another six to eight wells could be drilled in the Gulf
Coast during the fourth quarter in addition to two wells currently drilling.
Interpretation of 3-D seismic is continuing on 18 projects.
Chairman and Chief Executive Officer Nicholas J. Sutton stated, "The strong
third quarter results reflect significant improvement in product prices, but,
perhaps more important, show the continuing benefits of our ongoing
exploitation, exploration and development programs. Total revenues were up 17%,
while total expenses were down 20%, resulting in dramatically improved earnings
and cash flow, both in the aggregate and, more importantly, per share. In less
than one year our drilling programs, funded solely out of cash flow, have
replaced 100% of the production from the Mid-Continent properties which were
sold last year. The result is that our production level continues to increase
even as we retire debt. Our substantial inventory of low-risk, high-return
drilling opportunities allows us to continue to grow through the drill bit."
HS Resources President P. Michael Highum added, "In the D-J Basin we have
generated $82.5 million in EBITDAX in the first nine months of the year. During
that time we spent less than half of that amount, $36.8 million, on capex while
increasing production by more than 5%. In the Gulf
2
<PAGE>
Coast, our success in the rotated Hackberry trend far exceeds original
expectations. We have drilled 30 successful wells in 39 attempts gross (6.7 for
8.8 net), adding approximately 36 Bcfe of reserves net to HS, and almost 20
MMcfe of net production per day. Although the Yegua and Miocene formations at
Big Creek were not successful, our overall success in the Gulf Coast remains on
track, and we have a very substantial Gulf Coast prospect inventory driven by
almost 1,000 square miles of 3-D seismic coverage, most of which is proprietary.
We continue to add to our seismic inventory, and look for additional growth in
reserves, production and cash flow as we continue our active Gulf Coast
program."
Chief Financial Officer James E. Duffy commented, "The operational benefits of
our consolidation program continue to flow through our financial results in a
meaningful way. Lease operating expense and general and administrative expenses
continue to decline in absolute and per-unit terms with significant benefits to
our financial results. Earlier in the year, when pricing was very much below
where it is now, the combination of cost-effective management and strong hedging
programs allowed us to protect our cash flow and by extension, our capital
program. Gas represents more than 80% of our production, and approximately 25%
of our November through March gas production is hedged at about $2.90 per Mcf at
the wellhead. On our proportionately smaller base of oil production,
approximately one-third of our production for the same period is hedged at
slightly less than $15.00 Bbl (NYMEX), representing the balance of a hedge
position put in place almost a year ago. Our effective product price hedging
program has provided strong and predictable cash flow with which to fund our
ongoing capital program and service our financial obligations."
Statements concerning drilling plans, expectations concerning production levels,
reserve potential 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. Drilling plans could change because of 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, company objectives and business judgment and other factors,
both within and outside of the Company's control. Production and reserves
estimates are estimates only based on incomplete information such as formation
pressure and characteristics; actual production may be materially different than
the estimates. The many factors that affect the accuracy of reserve estimates,
as well as other factors qualifying the forward looking statements made herein,
are set forth in the Company's report on Form 10-K filed March 31, 1999.
HS Resources, Inc. is an independent oil and gas exploration and development
company with active projects in the D-J Basin, Gulf Coast and Northern Rocky
Mountain 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
415-433-5795
[email protected]
3
<PAGE>
<TABLE>
<CAPTION>
HS Resources, Inc.
Summary of 1999 Operations
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except Per Share Data)
Quarter Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Revenues:
Oil & gas sales $ 43,473 $ 32,887 $116,280 $116,599
Trading and transportation 11,596 13,831 32,874 41,297
Other gas revenues 2,281 2,068 7,323 6,214
Interest and other income 141 504 411 1,147
-------- -------- -------- --------
Total revenues 57,491 49,290 156,888 165,257
-------- -------- -------- --------
Expenses:
Production taxes 3,372 2,068 7,657 7,825
Lease operating 6,776 7,799 20,936 23,113
Cost of trading and transportation 10,997 12,550 31,442 38,910
DD&A 13,070 15,387 40,472 47,320
Exploratory and abandonment 4,359 1,335 9,098 3,008
Geological and geophysical 1,293 3,412 4,780 11,241
Impairment and (gain)/loss on sales
of oil and gas properties (2,328) 6,742 (1,228) 6,670
General and administrative 1,467 2,248 3,942 6,238
Interest 10,717 10,889 31,657 32,741
-------- -------- -------- --------
Total expenses 49,723 62,430 148,756 177,066
-------- -------- -------- --------
Income (loss) before provision
(benefit) for income taxes 7,768 (13,140) 8,132 (11,809)
Provision (benefit) for income taxes 2,959 (5,006) 3,098 (4,499)
-------- -------- -------- --------
Net income (loss) $ 4,809 $ (8,134) $ 5,034 $ (7,310)
======== ======== ======== ========
Net income (loss) per share - diluted $ 0.25 $ (0.43) $ 0.27 $ (0.39)
======== ======== ======== ========
Outstanding shares - diluted 19,131 18,796 18,815 18,619
======== ======== ======== ========
Operating cash flow (a) $ 24,162 $ 13,737 $ 61,254 $ 56,430
======== ======== ======== ========
Operating cash flow per share - diluted $ 1.26 $ 0.73 $ 3.26 $ 3.03
======== ======== ======== ========
(a) Net income before geological and geophysical, exploratory and abandonment, depreciation,
depletion and amortization, impairment and (gain)/loss on sales of oil and gas properties
and income taxes.
</TABLE>
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<PAGE>
<TABLE>
<CAPTION>
HS Resources, Inc.
Summary of 1999 Operations
SUMMARY PRODUCTION, PRICE AND COST DATA
Quarter Ended Nine Months Ended
September 30, September 30,
----------------------------- -----------------------------
% %
1999 1998 Change 1999 1998 Change
------- ------- ------ ------- ------- ------
<S> <C> <C> <C> <C> <C> <C>
Production by district (MMcfe):
D-J Basin and Northern Rockies 16,169 15,947 1% 49,148 46,632 5%
Gulf Coast 2,153 144 1395% 5,043 660 664%
Mid-Continent 5 2,208 -100% 11 8,934 -100%
Total production (MMcfe) 18,327 18,299 0% 54,202 56,226 -4%
Period Production:
Oil (MBbl) 582 653 -11% 1,770 2,043 -13%
Gas (MMcf) 14,836 14,378 3% 43,585 43,966 -1%
Equivalent Gas (MMcfe) 18,327 18,299 0% 54,202 56,226 -4%
Equivalent Barrels (MBoe) 3,054 3,050 0% 9,034 9,371 -4%
Daily Production:
Oil (Bbl) 6,324 7,102 -11% 6,482 7,484 -13%
Gas (Mcf) 161,263 156,288 3% 159,650 161,048 -1%
Equivalent Gas (Mcfe) 199,206 198,901 0% 198,541 205,955 -4%
Equivalent Barrels (Boe) 33,201 33,150 0% 33,090 34,326 -4%
Average oil price (Bbl) $ 20.04 $ 13.07 53% $ 15.51 $ 14.92 4%
Average gas price (Mcf) $ 2.14 $ 1.69 27% $ 2.04 $ 1.96 4%
Average price (Mcfe) $ 2.37 $ 1.80 32% $ 2.15 $ 2.07 4%
Average price (Boe) $ 14.23 $ 10.78 32% $ 12.87 $ 12.44 3%
Costs:
G&A per Mcfe $ 0.08 $ 0.12 -33% $ 0.07 $ 0.11 -36%
LOE per Mcfe $ 0.37 $ 0.43 -14% $ 0.39 $ 0.41 -5%
DD&A per Mcfe $ 0.71 $ 0.84 -15% $ 0.75 $ 0.84 -11%
G&A per Boe $ 0.48 $ 0.74 -35% $ 0.44 $ 0.67 -34%
LOE per Boe $ 2.22 $ 2.56 -13% $ 2.32 $ 2.47 -6%
DD&A per Boe $ 4.28 $ 5.05 -15% $ 4.48 $ 5.05 -11%
(DD&A includes depreciation
on non oil and gas assets)
</TABLE>
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<TABLE>
<CAPTION>
HS Resources, Inc.
Summary of 1999 Operations
CONDENSED CONSOLIDATED BALANCE SHEETS
(In Thousands)
September 30, December 31,
1999 1998
------------- ------------
<S> <C> <C>
Assets
Current assets $ 77,553 $ 60,265
Oil & gas properties 967,943 924,663
Accumulated DD&A (214,298) (175,729)
Other assets 20,464 23,240
--------- ---------
Total assets $ 851,662 $ 832,439
========= =========
September 30, December 31,
1999 1998
------------- ------------
Liabilities and Stockholders' Equity
Current liabilities $ 89,070 $ 79,164
Bank debt 234,000 230,000
9 7/8% Subordinated notes, due 2003 74,756 74,712
9 1/4% Subordinated notes, due 2006 230,661 230,205
Other long-term liabilities & deferred revenue 13,148 21,359
Deferred taxes 49,276 44,138
Stockholders' equity 160,751 152,861
--------- ---------
Total liabilities and stockholders' equity $ 851,662 $ 832,439
========= =========
</TABLE>
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<TABLE>
<CAPTION>
HS Resources, Inc.
Summary of 1999 Operations
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
Nine Months
September 30,
-------------------------
1999 1998
-------- ---------
<S> <C> <C>
Cash flows from operating activities:
Net income (loss) $ 5,034 $ (7,310)
Depreciation, depletion and amortization 40,472 47,320
Impairment and (gain)/loss on sales of oil and gas properties (1,228) 6,670
Amortization of deferred charges, debt issue costs
and deferred compensation 3,308 1,848
Surrendered and expired acreage 2,960 --
Transfer treasury stock to 401(k) plan 763 549
Gain on sale of fixed assets -- (239)
Deferred income tax provision (benefit) 3,038 (4,635)
(Increase) decrease in accounts receivable (19,172) 3,908
Increase in accounts payable and accrued expenses 17,458 3,741
Decrease in deferred revenue, net (7,436) (4,379)
Other (2,914) 26
-------- ---------
Net cash provided by operating activities 42,283 47,499
-------- ---------
Cash flows from investing activities:
Exploration, development and leasehold costs (48,856) (79,762)
Purchase of unproved and proved properties -- (4,637)
Purchase of workover equipment (862) --
Gas gathering and transportation facilities additions (460) (28)
Other property additions (286) (519)
Net proceeds from the sale of oil and gas properties 3,384 152,525
Proceeds from the sale of fixed assets -- 1,232
(Decrease) increase in property related payables (6,227) 6,633
-------- ---------
Net cash (used in) provided by investing activities (53,307) 75,444
-------- ---------
Cash flows from financing activities:
Proceeds from debt 52,000 55,000
Repayments of debt (48,000) (174,000)
Exercise of options 641 468
Issuance of common stock 611 --
Purchase of treasury stock (767) (4,506)
Payment of officer note and interest 823 --
-------- ---------
Net cash provided by (used in) financing activities 5,308 (123,038)
-------- ---------
Net decrease in cash and
cash equivalents (5,716) (95)
Cash and cash equivalents, beginning
of the period 9,659 6,908
-------- ---------
Cash and cash equivalents, end of
the period $ 3,943 $ 6,813
======== =========
</TABLE>
7
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<TABLE>
<CAPTION>
HS Resources, Inc.
Summary of 1999 Operations
1999 DEVELOPMENT, EXPLOITATION AND EXPLORATION COSTS
(In Thousands)
Nine Months Ended 9/30/99
------------------------------------------------------
Northern
D-J Basin Gulf Coast Rockies Other Total
--------- ---------- ------- -------- -------
<S> <C> <C> <C> <C> <C>
Capitalized Costs
Land $ 47 $ 3,651 $ 100 $190 $ 3,988
Exploration Drilling -- 6,530 1,129 -- 7,659
Development Drilling 7,269 -- -- -- 7,269
Recompletions and Refracs 24,334 342 (9) -- 24,667
Acquisitions 16 6 -- 124 146
Capitalized Interest & Other 4,252 685 148 42 5,127
------- ------- ------- ---- -------
Total Capitalized Costs 35,918 11,214 1,368 356 48,856
------- ------- ------- ---- -------
Costs Charged to Income Statement
Geological & Geophysical 221 3,907 324 328 4,780
Exploratory Dryholes 197 3,391 -- -- 3,588
Surrendered & Expired Acreage (1) 61 2,753 146 -- 2,960
Other Exploratory 398 1,852 254 46 2,550
------- ------- ------- ---- -------
Total G&G and Exploration Costs 877 11,903 724 374 13,878
------- ------- ------- ---- -------
Total Development, Exploitation
and Exploration Costs $36,795 $23,117 $ 2,092 $730 $62,734
======= ======= ======= ==== =======
(1) Includes non-cash charges in the current period for certain previously capitalized
leasehold costs attributable to expired acreage and associated capitalized interest.
</TABLE>
8
HS RESOURCES
MODERATOR: NICK SUTTON
OCTOBER 26, 1999
Operator: Good day, everyone, and welcome to this HS Resources (HSE;
http://www.hsresources.com/) third quarter 1999 financial results conference
call. Today's call is being recorded. At this time, I would like to turn the
call over to the chief executive officer of HS Resources, Mr. Nick Sutton.
Please go ahead, sir.
Nick Sutton: Good morning ladies and gentlemen. We appreciate your taking the
time to join us at this conference call today where we're going to discuss the
third quarter 1999 financial and operating results.
Before we get underway with that, I'm required to read the safe harbor language
which you are all very familiar with. In this call, we're going to be discussing
several matters which should be considered forward-looking statements under the
Federal Securities Laws. This 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 is contained in our report on Form 10-K, filed on
March 31, 1999.
So now we can get down to the meat of the presentation. I'd like to say
preliminarily that we have, in addition to me, many of the senior managers and
key managers of HS Resources on the call from our various offices, and they will
be available to answer any questions when we get to the Q&A.
By now you've seen our press release, and I think you will note that we had a
very strong quarter. If we look at our production, excluding the Mid-Continent
production which was sold on September 1, 1998, we had a 14% increase in our
production. Basically, our production over the quarter averaged 199 million
cubic feet of gas per day equivalent MMcfe. We went from 16.09 Bcfe in the third
quarter of 1998, to 18.33 Bcfe in the third quarter of 1999. The majority of the
increase was in natural gas. Our gas production went from 12.52 Bcfe to 14.84
Bcfe. That's an increase of 19% from the comparable prior year period.
As we look at product pricing, I think that's clearly the one item that's made a
huge difference over this last year. We've seen both our oil price and our gas
price increase rather significantly. For the third quarter, our average oil
price was $20.04 per barrel. That's up 53% from $13.07 in the prior period. That
$20.04 includes the impact of our product-pricing program.
From a gas price standpoint, we went from a $1.69 per Mcf in the prior period to
$2.14 per Mcf, up 27%. That number, too, includes the impact of our gas-hedging
program. Looking at it on an Mcfe basis, we increased 32% from $1.80 per Mcfe to
$2.37 per Mcfe.
<PAGE>
Obviously, when we look at increased production along with increased product
prices, our oil and gas revenues are up significantly. We had $43.5 million of
oil and gas revenues for the third quarter 1999. That translates into a very
strong net income. We had net income of $4.8 million, or 25 cents per share for
the third quarter. Operating cash flow was $24 million. Cash flow per share,
fully diluted, was $1.26 a share. EBITDAX was $35 million. So obviously it was a
good quarter for us financially.
Next let's look at how we did on a district basis. Our D-J district did a
bang-up job, as did our other districts. But one of the reasons I want to focus
on the D-J district is that this area contributes a substantial majority of our
production at the present time. During the third quarter of 1999, production
there was about 176 MMcfe per day. That is up 1% from the comparable prior year
period.
In the Gulf Coast, our production went up very dramatically. During the third
quarter of 1999, we produced about 23.4 MMcfe per day in the Gulf Coast. That's
up over 15-fold from the prior year, and it's up 16% from the prior quarter, the
second quarter of 1999.
Operating efficiencies continue to be a focus for us, and you will have noticed
by now that translates into very strong results for the third quarter. Our lease
operating expenses, on an Mcfe basis, dropped from 43 cents to 37 cents. That's
a 13% decline from the prior period. G&A also improved significantly from 12
cents per Mcfe to eight cents per Mcfe. That's a 35% decline.
And we always take a look at it in terms of LOE and G&A together, because it
pretty much captures everything, we saw a decrease from 55 cents to 45 cents per
Mcfe. That's an 18% decline. We're also happy to note that our DD&A rate went
down from 84 cents per Mcfe to 71 cents an Mcfe, a 15% decline. You put all that
together, and look at operating cash flow on a per-unit basis, and our operating
cash flow went from 75 cents per Mcfe to $1.32 per Mcfe. That's a 76% increase.
To look out into the future, the question always is, what's our outlook for
commodity prices? We don't pretend to have a crystal ball, and we take our cues
from a number of different sources. But for the moment we'll just focus on our
hedging program, combined with where the current strips are. What we see on our
gas price for the fourth quarter is a corporate price of $2.84 per Mcf, with 46%
hedged at a hedge price of $2.52 per Mcf. As we look out into the first quarter
of the year 2000, right now the corporate price would be $3.02, that's 24%
hedged at $2.89 at the wellhead. In the second quarter of 2000, our corporate
price is $2.47, where we're 15% hedged at $2.49.
Now, if we look at our oil price position for the fourth quarter, we're 72%
hedged at a net wellhead price of about $14 per barrel. So, our weighted average
oil price would be about $16.25. And we'll remind everyone that we look at
hedges as an insurance program. The oil hedge, right now, doesn't look as good
as it did a while ago, but we've made a lot of money on that hedge in the first
part of the year, and it was the intelligent thing to do. As we look out into
the first quarter of 2000 and through the year 2000, our oil hedge position
drops off rather dramatically.
2
<PAGE>
From a seasonal basis, looking at the November to March period, we're about 28%
hedged at an average net wellhead price of $2.88 per Mcf. If you look at the
summer months, April-October, we're 18% hedged at a net wellhead price of $2.49.
And we're going to continue to layer in hedges as we see the advantage to do so.
We're going to talk a little bit about how each of the districts did
operationally, and I want to set the stage in terms of the D-J by going back to
something I said before. I noted that the production in the D-J is up 1% from
the prior period. The D-J represents about 90% of our production, because the
Gulf Coast is coming on strong, and I'll touch on that in a minute.
If we look back a year ago, the D-J represented virtually 100% of our
production. As we were able to increase production over time, note that we spent
in the four quarters leading up to the third quarter of 1999, approximately
$42.7 million dollars in drilling and completion costs. That represents about
30% of our estimated EBITDAX for the current calendar year. So, in other words,
we were able to hold 100% of our production flat using just 30% of our EBITDAX.
I think that's a pretty strong indicator of the economic success in the D-J, and
the magnitude and the benefits of our ongoing consolidation program.
We talk about individual activities. Through the first nine months of 1999, the
D-J district completed about 250 different well operations, and we're going to
average about 25 to 30 activities per month through the rest of the year.
The J-infill project, which came about largely because of the Amoco transaction,
is right on track. During the quarter, we worked on 22 J-infill project wells.
Nine of them were new drills and 13 were deepenings. What we're finding as we go
forward with this program is that we're continuing to accumulate additional
geologic and reservoir engineering data. This added information is going into
our models and databases, and is proving extremely valuable in predicting
pre-drill reservoir pressure, anticipated productivity and reserves for each
completion attempt.
The average J-Sand completion is adding about eight tenths of a Bcfe of reserves
(or 800 MMcfe). It's about 650 MMcfe net to the company, and our average initial
flow rates are from about 500,000 to 1.5 million cubic feet of gas a day. And a
very important number is that, as we have gone forward with our scientific work,
as we have refined our frac designs and technology used in these activities, we
are getting performance that is roughly 25% better than what we anticipated when
we ran our economics on the Amoco purchase. So, we are substantially ahead of
what we anticipated when we made that major acquisition at the end of 1997.
Historical finding costs for the J-infill on whole have averaged less than 50
cents per Mcfe.
We've talked before about our Codell refrac program. That's continuing to go
along very smoothly. During the third quarter we refraced 58 wells, and thus far
for this year, the total number is 175, or about 450 refracs from inception
to-date for that program. The economics consistently are achieving high rates of
return, over 60%, with a finding cost of less that 67 cents per Mcfe. Now when
we talk about our economics in these refrac programs, we generally don't
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factor in the impact of tax credits. Many of these are tax credit wells, and we
have, through our refrac program, targeted the tax credit wells as primary
sectors, or primary groupings. Over a third of the Codell refracs performed this
year qualify for this tax credit monetization. As we go into the fourth quarter,
we will probably do about 100 refracs.
We're continuing with our Dakota evaluation. We've talked to many of you about
that. Essentially what we're doing at the present time is using our J-infill
project to deepen into the Dakota, and we've discussed before how efficient this
is. In many cases, it's really only about $15,000 of additional cost to go down
and take a look. During the third quarter, seven of the 12 wells that we took
down to the Dakota established production, and five did not. But to give you an
idea of what this could really mean to us, the Cannon Land well averaged 1.3
million cubic feet of gas a day over the first 30 days of production into the
pipeline and the Kuersteiner averaged over 300 Mmcf per day for the first 30
days. So, we're getting significant production out of some of these Dakota
wells, and perhaps, most importantly, we're continuing to add to our database
and the future opportunity there.
If you look at the Gulf Coast, again we were very active in that area. From a
production standpoint, I mentioned that we're up over 15-fold from the prior
period, and 16% just from second quarter '99 to third quarter '99. During the
third quarter, we drilled six wells. Two of them were successful. The Indian
Village project area has been very good to us. We had two more successful wells
there in the rotated Hackberry trend that we're targeting. These two successful
wells were the Rice Acres #1 and the Bel Estate #21-1.
Very preliminary gross reserve estimates on these wells are in the three to five
Bcfe range. We had a well called the Walker Properties well drilling at the end
of the third quarter, and since that time, it's in the process of being
completed and hooked up. So far, we're five-for-five in Indian Village, with
average reserves of seven to eight Bcfe per well. We have another three to four
locations ready for drilling and we expect some of these are going to come in
during the fourth quarter of '99, with the remainder in the first quarter of
2000. We've got an additional six to eight prospects identified that we're going
to be further working on as we get additional data from each well that we drill.
Our Big Creek project area was a little bit of a disappointment, although that's
not the entire story at this stage. We drilled three wells, which were dry
holes. One was a very shallow well on the crest of the salt dome feature. The
other two targeted the Yegua, the George Foundation well, and the Lingnau well,
were unsuccessful. So what we're doing now is we're taking all the information
that we got out of the logs, and that is going to be re-calibrated back into our
seismic to further unlock the keys to this project area.
In Devillier we had the Vivian Rogers #1 which targeted the Nodosaria at 9,200
feet. That was a dry hole. In Caney Creek, the Pierce Estate #2 was completed in
the Frio, and reserves are estimated at about 2 Bcfe. It's waiting on pipeline
hookup. The Pierce Estate #3 was drilling at the end of the quarter. We have
another two to three potential location in the Caney Creek project area, and
we'll be evaluating those as we incorporate further data.
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If we step back a minute, and just look at where we are from all of our project
areas, our interpretation on 3-D seismic is continuing on 18 major project
areas. To give you an example; on our Starks project, we have a 41% working
interest in an 88 square mile shoot about 10 miles west of Buhler, which was one
of our first project areas. Our initial interpretations there show that we've
got five very good Hackberry prospects and two good Yegua prospects, plus six to
eight prospects which we would call tier two at this stage. We'll look to
calibrate those based on the tier one drilling.
On Hathaway we have a 37.5% working interest. That's a 59 square mile shoot,
directly east of Indian Village project area. And our preliminary interpretation
has been completed, with one very pronounced Hackberry prospect identified, and
another four to six leads. We're continuing to work with that.
In addition, during the quarter, we entered into a formal agreement to shoot a
minimum of 100 square miles of 3-D, north of the North Gillis project, where
we're targeting updip Yegua channel sands. The shooting there's going to begin
in the fourth quarter. We've got about a 20% working interest in that project
which Cox & Perkins will be operating.
During the third quarter, we had three wells that we're previously completed and
brought on line. Noteworthy was the Douget #1 in the Indian Village project area
that went on line the second week of September. Is currently producing at about
four million a day, and we're going to be stepping that up over time.
Again, as I mentioned earlier, daily production during the quarter was 23.4
MMcfe per day, net to the company. We've got six wells waiting pipeline hookup,
and when those are hooked up, we figure that will bring our Gulf Coast
production up into the range of 30 MMcfe to 40 MMcfe per day net to the company.
We've got another eight to 10 wells that we're expecting to drill in the fourth
quarter. Two are currently drilling. And depending on success, that could
increase the production to between 40 and 60 MMcfe per day. A lot of it depends
on hookups and timing of hookups. I think it would be better to say that instead
of production will or could be 40 to 60 MMcfe per day, it would be more accurate
to say that productive capacity would be expected to be 40 to 60 MMcfe per day.
Whether it's on line by the end of the year remains to be seen.
Our Northern Rockies group was active as well. We took over operations on the
Holmes well in our South Jonah project. We've stabilized production. We're
getting lot of data out of that well that will help us evaluate further
potential in that area. We also took over operations on the Steele well in our
North Pinedale project area. We're selling production from that well, and again,
that's providing additional data and further consolidating our acreage position
in the North Pinedale project area.
We have active projects in the Mid-Continent. I suppose the most noteworthy one
would be our activity in the Mountain Front area. We've got several projects
underway there, incorporating a lot of seismic data, a lot of very complex
structural geology, and we'll probably spud our first well in the Mountain Front
sometime in the fourth quarter of this year.
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So, I think that about summarizes the financial and operating information. I
think we've had a great quarter. Certainly, product prices being where they are
creates a different dynamic throughout the industry. Fortunately, we were in a
position where we've got so many different activities underway that we can take
the cash flow that we've got and apply it to some very excellent project areas.
With that, I'd like to turn it over to all of you for questions and answers.
Operator: Thank you, gentlemen. Today's question and answer session will be
conducted electronically. If you would like to ask a question today, simply
press the star or asterisk key followed by the digit one on your telephone's
keypad. We will proceed in the order that you signal us, and we will take as
many questions as time permits. Once again, to ask a question today, please
press star-one.
Our first question comes from John Selser of Lehman Brothers.
John Selser: Yes. Good afternoon. Looking at my model and the projected cash
flow for next year, it looks like you're going to be generating some free cash,
or, I guess that's my question. How do you see capital spending next year, or
are you going to tie it into cash flow, or maybe apply some of that excess cash
to debt? How do you see that, Nick?
Nick Sutton: We're going through that evaluation right now, John. I concur with
your model that as we look out, subject to a lot things that could happen in
product prices and successes out into the year, but if we look at it right now
from a probabilistic standpoint and apply the current strip, we will be
generating a substantial amount of EBITDAX. I think you know from prior
discussions with us, we tend to moderate our activities. We feel that companies
that swing their capital programs up and down dramatically tend to be under a
lot of pressure, and often get less than optimal results. As we go through our
process, we rank all of our projects. We look for cutoffs, we look for
operational constraints and things of that nature. And I can say right now that
we will not exceed our cash flow, and to the extent that we generate additional
cash flow, it remains to be seen where we put it. But right now, I think that my
personal cut is that we can significantly increase production, while still
paying down a substantial amount of debt.
John Selser: Right. And looking at last year's reserve numbers, there were some
revisions in there. I'm sure that some of that was due to price. How do you feel
about those reserves, adding those back this year, or any other comments you
might have on reserve replacement?
Nick Sutton: Let's turn that over to Ted Gazulis who, along with Dale Cantwell,
and David Howell, and a number of other people who are very directly involved in
that process.
Theodore Gazulis: Clearly, a significant component of the revision last year was
due to pricing. We have not done our year-end engineering because it's not
year-end, but we anticipate that the pricing related component will - I can't
see any reason why that would not come back. That's what happens with pricing
swings. As far as looking to what we have done that is new and different, I
don't think we're in a position to really comment on that. We clearly have done
a lot
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of activities in the D-J and elsewhere, and those will be reflected at year-end,
but I don't think we can quantify that currently.
John Selser: OK. And one last one Nick, I might have missed it, but did you
mention the Port Barre project? What is your status on that?
Nick Sutton: The Port Barre project is moving forward. No drilling results to
announce.
John Selser: You still think we might spud that by the end of the year possibly?
Nick Sutton: Well, there are a number of different individual well projects down
on Port Barre, and I would say that it's likely that we'll spud at least one of
the prospects before the end of the year.
John Selser: OK. Great. Thanks.
Jim Duffy: Before we move on to the next question, let me just supplement real
quickly, one of the things Nick said. This goes to the question, John, of cash
flow relative to capex. If you look at our current quarter, the September
quarter, which I think is indicative of where we see things going, we actually
repaid $13 million worth of bank debt during the quarter, while we continued to
fund our capital program out of cash flow. I think you know that we have nearly
$50 million of availability under the line, and we'd like to see that grow as a
result of additional repayments. But I think one thing that's really interesting
to note, as we see what happens with debt repayments out of cash flow, is that a
year ago, for 1998, we were looking at debt-to-EBITDAX of about 5.3 times, and
right now we're looking at something in the 3.8 to 3.9 range, and that's for
this year. It obviously continues to improve dramatically as we move into next
year. So, one of the things that we've contemplated all along is that as we
continue our production growth from our project activities, and funding these
activities out of cash flow, we will generate excess cash flow, some of which
may go to debt repayment. But whether it does or it doesn't, the debt-to-EBITDAX
ratio is improving considerably, as we had anticipated.
John Selser: Thanks, Jim. Nice job.
Operator: Our next question will come from Tom Parker of Chase Securities.
Tom Parker: Hi. I was wondering if you could give us a little status update on
bottlenecks in the D-J and where we stand. Can you spend a lot more there next
year, given production constraints, or would you want to spend a lot more there
next year?
Nick Sutton: Good question, Tom. I would say that we certainly can spend a lot
more. The bottlenecks are something that we are working with to resolve on an
ongoing basis, and we would expect to get those under control. So, we can spend
significantly more on the D-J. I would say we will probably, as I look at sort
of the crystal ball for 2000, be spending more on the D-J next year than we did
this year.
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Tom Parker: I think last time, you discussed some projects that you guys were
starting to engage on in terms of kind of eliminating some of the bottlenecks,
including you guys looking at gathering. Are we kind of in the same place we
were, or is there any progress there?
Nick Sutton: Right now we're still in the same place we were.
Tom Parker: OK. Thanks.
Operator: Our next question will come from Ellen Hannan of Bear Stearns.
Ellen Hannan: Good afternoon. Just a quick question, Nick, on the Devillier and
the Big Creek wells that were drilled. Does what you found or didn't find there
say anything about your inventory in the Gulf Coast?
Nick Sutton: I would say no, particularly as to the Devillier project area. We
have a number of wells that we drilled there where we had somebody drill, and
give us a promoted interest. And we've pretty much gone through the project area
of Devillier, where we have some decent wells, and then the most recent one was
a dry hole, and that pretty much wraps up Devillier. For Big Creek, I would say
it doesn't really impact our project inventory. We have taken a very measured
approach to each of these project areas, and where we have the bulk of our
inventory is over in the various Hackberry project areas in south Louisiana,
where we've got a lot of data to draw on, a lot of historical success that
allows us to calibrate the seismic to the drilling results. Whereas Big Creek
was more of a measured thing. We're taking what we've learned on those first two
Yegua wells, and we're re-calibrating the seismic. But it does not really impact
what we see as our inventory in the Gulf.
Ellen Hannan: Great, and just one other question while we're in the Gulf Coast.
I had to hop off. I may have missed it, but I know you mentioned, or Jim
mentioned, that you thought the potential existed for you to be producing 40 to
60 Mmcfe per day out of the Gulf Coast by the end of the year. Is this largely
resting on the timing of well hookups, and what do you see is standing in your
way there?
Nick Sutton: What we said was that we have about a half a dozen wells that are
waiting on hookup. When added to the 23.4 MMcfe per day we produced during the
third quarter, those six wells would take us more to the 35 to 40 Mmcfe per day,
and then the jump to the 40 to 60 Mmcfe per day depends on the results and
hookup schedules and success of fourth quarter activities.
Ellen Hannan: One final quick question. Are you seeing any pressure on day rates
or service costs for this area yet?
Nick Sutton: Not to my knowledge.
Ellen Hannan: Great. Thank you very much.
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Operator: Just a reminder. If you have a question today, please press star-one
on your telephone.
Our next question will come from Glori Holtzman-Graziano of SG Cowen.
Glori Holtzman-Graziano: It's Glori Holtzman-Graziano of SG Cowen.
Two questions. One is with regard to the free cash flow you're anticipating in
the year 2000. Could you update us as to what your current thoughts are with
regard to acquisition-related activity? And the second question is, a little bit
of guidance on your run-rate for G&A.
Nick Sutton: OK. In terms of acquisition activity, of course, we are always -
this sounds like such a platitude, but you know, we're always looking at
acquisition potential. One of the things, for example, that we're kicking off in
the D-J is an effort to take out all the small working and royalty interest
owners, and that's a type of an acquisition. But as a general matter, while we
never say never, I don't see acquisitions being very high on our list. We think
the best time to acquire is when product prices are down, not when product
prices are very robust. And so I would not anticipate that we will earmark any
of our cash flow through acquisitions per se, again with the caveat that we
never say never.
In terms of the run rate of the G&A, I'm not sure what you're looking for.
Glori Holtzman-Graziano: I guess I was a little surprised at looking at third
quarter level relative to second quarter, and I was just wondering if the third
quarter is sort of a good benchmark to use going forward?
Jim Duffy: Yes, we see the absolute level next year coming up somewhat,
obviously, as our production continues to grow. But the current rate for the
third quarter is probably a pretty good indication of where we will be as we go
into next year. Quarter to quarter we see some ups and downs. But certainly, if
you take the nine month rate to date, that's, I think, going to be very
indicative of where we'll be going forward.
Glori Holtzman-Graziano: Thank you.
Operator: As a reminder, if you have a question today, please press star-one on
your touch-tone telephone. We have a question from Jeff Robertson of Salomon
Smith Barney
Jeff Robertson: Good afternoon. Nick, could you talk a little bit about the
production performance, now that you've got a little bit of history on some of
these Gulf Coast wells, and how they're tracking, as well as the original
expectations?
Nick Sutton: Yes, but I think I'd rather turn that over to Tony Church or Wayne
Williams, who live with those wells on a daily basis. But, overall, I don't
think we're seeing anything unexpected. But Tony, why don't you jump in and give
us your feedback.
Tony Church: Sure. Hi, Jeff. How you doing?
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Jeff Robertson: Hey, Tony.
Tony Church: Yes, at this point we don't have any feedback, either way, frankly.
The well performance looks right in line in general with what they test at, and
what one would expect them to come on. Our intent has been to pull them
relatively aggressively to maximize the PV value on these things. But at this
stage of the game, we don't see anything to cause us to change our model.
Jeff Robertson: OK. Thanks.
Operator: The next question comes from Philip Kehl of Morgan Stanley.
Philip Kehl: Yes. Hi. Good afternoon. It's Phil Kehl. Nick, I'm just wondering
about this exchange you did with Patina. Did that just kind of clean up all the
easy stuff with Patina, or is there anything else that you could do with them,
in terms of getting some of these orphan wells back to their natural parents?
Nick Sutton: I would say that it wouldn't be doing it any justice to say that it
just sort of picked off the easy things. Our staff, principally George Solich in
the A&D group, Greg Way, Ken Ortmann, really scrubbed the database very
carefully, and worked very closely with the Patina people. So, I would not
classify that as just picking off the easy orphans. Nonetheless, I think there's
room for ongoing working together to maximize the efficiency in the D-J.
Philip Kehl: Do you have an ongoing dialogue with Patina?
Nick Sutton: Oh yes. Both of us are in the Denver community from a field
standpoint, and from management's standpoint, there's just ongoing dialogue
interaction.
Philip Kehl: OK. Thanks.
Nick Sutton: Sure.
Operator: If you have a question today, please press star-one. We'll pause for
just a moment. Mr. Sutton, it appears that we have no further questions at this
time. I'll turn the conference back over to you.
Nick Sutton: Thank you very much. Again, we appreciate everybody participating
in this call. We know that time is precious. We think we had great quarter. We
think we're going to have a great fourth quarter, and we're very excited about
how 2000 is stacking up. As always, if you have any questions, give us a call,
and we'll be happy to make sure that you've got all the information you need in
order to run your models and make informed decisions.
Again, thank you very much.
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Operator: That concludes today's conference call. Thank you, everyone, for your
participation.
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