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 - JULY 27, 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.
July 27, 1999
ITEM 5. OTHER EVENTS.
On July 27, 1999, HS Resources, Inc., a Delaware corporation ("HSR" or the
"Company"), issued its second 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 Thursday, July 27, 1999, as edited by the Company,
is attached as Exhibit 99.2.
ITEM 7(c). EXHIBITS FILED.
Exhibit Number Description
- -----------------------------
99.1 Earnings Press Release, dated July 27, 1999.
99.2 Edited Transcript of Earnings Conference Call held on
Thursday, July 27, 1999.
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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: August 5, 1999.
3
FOR IMMEDIATE RELEASE
July 27, 1999
HS RESOURCES ANNOUNCES SECOND QUARTER RESULTS
San Francisco, California - HS Resources, Inc. (NYSE:HSE) today announced its
operating and financial results for the quarter ended June 30, 1999. During the
quarter, the Company earned $118,974 ($0.01 per share) and reported operating
cash flow of $18.7 million ($0.99 per share). That compares to a loss of $3.3
million ($0.18 per share) and operating cash flow of $17.5 million ($0.94 per
share) for the comparable prior year period. During the quarter, the Company
produced 18.34 billion cubic feet of gas equivalent (Bcfe), which was a 6%
decrease from the 19.56 Bcfe produced during the prior year period. However,
after excluding 3.33 Bcfe of production attributable to certain Mid-Continent
properties that were sold effective September 1, 1998, production for the
current quarter was 13% higher than the prior year period. Approximately 81% of
the production was natural gas.
Quarterly production revenues, including the effects of product price hedging,
decreased 4% from the comparable prior year period, from $38.3 million to $36.7
million. This resulted from the combination of lower production, reflecting the
Mid-Continent property sale, and a 2% increase in average product prices. The
quarterly average gas price, including hedging activities, was $1.93 per
thousand cubic feet (Mcf), a 5% increase from $1.83 realized in the second
quarter of 1998, while realized oil prices declined 6%, to $13.78 from $14.63
per barrel (Bbl). Hedging activities decreased realized prices by $0.01 per Mcf
and $2.33 per Bbl in 1999. For the comparable prior year period, hedging
decreased the realized gas price by $0.06 per Mcf and increased the realized oil
price by $1.25 per Bbl.
Lease operating expense decreased by 9%, from $8.2 million to $7.5 million,
representing a 3% decline on a per-unit basis, from $0.42 to $0.41 per Mcfe
($2.51 and $2.44 per Boe, respectively). Overhead expense was reduced by 50%,
from $2.2 million to $1.1 million, a 47% reduction on a per-unit basis, from
$0.11 to $0.06 per Mcfe ($0.66 to $0.35 per Boe). The lower overhead reflects
the Mid-Continent sale, efficiencies resulting from the ongoing D-J Basin
consolidation program and offsetting revenue generated by an increase in the
operating rates the Company charges on the wells it operates. Depreciation,
depletion and amortization expense declined 20%, from $16.5 million to $13.2
million (14% on a per-unit basis) reflecting the Mid-Continent sale and the
impact of new reserve bookings at June 30, 1999. Interest expense declined 5%,
while per-unit interest expense was essentially flat. In addition, a charge of
$1.1 million was recorded during this quarter due largely to an adjustment to
the 1998 sale of the Mid-Continent properties.
HS Resources also announced the status of certain field operations.
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D-J Basin quarterly production increased to 16.5 Bcfe, a 3% gain compared to
1998. This increase is the result of the Company's ongoing exploitation and
development program. During the second quarter, the Company conducted ten Codell
refracs, bringing the program total to more than 370. Seven new J-Sand wells
were drilled and completed, and thirteen existing wells were deepened to the
J-Sand. The Company also deepened five wells to the Dakota formation.
In the Gulf Coast region, net production rates almost doubled from levels
recorded at the beginning of the quarter. During the quarter, the Company
drilled six wells (1.2 net), of which four (0.8 net) were successful, resulting
in a gross and net success rate of 67%. The most significant well was the
Larry D. Douget et al #1, the Company's second successful well in its Indian
Village project area, in which HS is the operator and has a 50% working interest
(WI). This well is currently testing, with preliminary gross reserves estimated
to be 12 Bcfe. At Caney Creek (25% WI), the Company drilled one successful well
(the Pierce Estate #2) and one dry hole. At Buhler (3% WI), two non-operated
wells were successfully completed, bringing the Buhler program total to fifteen
successful wells out of nineteen attempts. Also during the quarter, certain
previously completed wells were brought on-line. The most significant are the
Louis H. Adams #1 in the Indian Village project area and the M Half Circle #1 in
the Lox B project area. The Adams #1 went on line during the first week of April
and is producing almost 17 MMcfe per day. The M Half Circle #1 went on line
during the third week of April and is producing nearly 15 MMcfe per day. HS owns
a 50% WI and is the operator of both projects. Six additional wells are awaiting
pipeline hookup.
Chairman and Chief Executive Officer Nicholas J. Sutton stated, "Overall, we're
on track with our plans in all areas. Production is up, costs are down and
prices are firm to positive. Perhaps of greatest importance to our shareholders
is the strong positive movement in our stock price during the quarter."
Regarding the Gulf Coast program, HS Resources President P. Michael Highum
commented, "At year-end 1998 net Gulf Coast production was approximately 8.7
MMcfe per day. At the beginning of the second quarter, production had risen to
12.7 MMcfe per day, and at the end of the second quarter our net daily
production was almost 25 MMcfe. In addition, six wells have been completed but
are awaiting pipeline hookup, which will further increase our net Gulf
production."
Chief Financial Officer James E. Duffy added, "We continue to be in a strong
financial position. For the past several years HS has had an effective product
price hedging program in place. Gas represents more than 80% of our production,
and approximately 67% of our third quarter gas production is hedged at $2.01 per
Mcf, a good price for these typically weaker months. About 30% of our fourth
quarter gas is hedged at $2.20 per Mcf. These hedges are "back to the wellhead,"
incorporating basis differentials and other considerations. At this point we are
relatively unhedged for the winter production, although if the market continues
to strengthen, we will begin hedging winter gas and summer 2000 gas as
appropriate. On our proportionately smaller base of oil production,
approximately 75% of our production for the second half of the year is hedged at
slightly more than $15.00 Bbl (NYMEX). In addition, we were able to book 67 Bcfe
of new proved reserves based on our June 30, 1999, internal engineering
evaluation. This,
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combined with the effects of the Mid-Continent sale, allowed us to reduce our
per-unit depletion rate by 15% to $0.69 per Mcfe ($4.16 per Boe). Equally
important, while there was no single item which stands out, during the quarter
we made significant progress in further reducing general and administrative
expenses."
Statements concerning drilling, exploitation, development and other plans,
expectations concerning production levels, strength, expected future operating
efficiencies, hedging plans 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,
opportunities to secure favorable hedges, 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
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, Northern 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
415-433-5795
[email protected]
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<TABLE>
<CAPTION>
HS Resources, Inc.
Summary of 1999 Operations
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except Per Share Data)
Quarter Ended Six Months Ended
June 30, June 30,
-------------------- ---------------------
1999 1998 1999 1998
------- -------- ------- ---------
<S> <C> <C> <C> <C>
Revenues:
Oil & gas sales $36,720 $ 38,341 $72,808 $ 83,712
Trading and transportation 11,978 11,142 21,278 27,466
Other gas revenues 2,518 2,276 5,042 4,145
Interest and other income 113 439 270 643
------- -------- ------- ---------
Total revenues 51,329 52,198 99,398 115,966
------- -------- ------- ---------
Expenses:
Production taxes 2,137 2,759 4,285 5,757
Lease operating 7,470 8,169 14,160 15,314
Cost of trading and transportation 11,464 10,563 20,446 26,360
DD&A 13,203 16,450 27,402 31,932
Exploratory and abandonment 2,722 1,157 4,739 1,673
Geological and geophysical 1,465 5,212 3,487 7,830
Impairment and loss/(gain) on sales
of oil and gas properties 1,100 (73) 1,100 (73)
General and administrative 1,066 2,152 2,475 3,990
Interest 10,510 11,071 20,940 21,852
------- -------- ------- ---------
Total expenses 51,137 57,460 99,034 114,635
------- -------- ------- ---------
Income (loss) before provision
(benefit) for income taxes 192 (5,262) 364 1,331
Provision (benefit) for income taxes 73 (2,005) 139 507
------- -------- ------- ---------
Net income (loss) $ 119 $ (3,257) $ 225 $ 824
======= ======== ======= =========
Net income (loss) per share - diluted $ 0.01 $ (0.18) $ 0.01 $ 0.04
======= ======== ======= =========
Outstanding shares - diluted 18,895 18,590 18,657 18,649
======= ======== ======= =========
Operating cash flow (a) $18,682 $ 17,484 $37,092 $ 42,693
======= ======== ======= =========
Operating cash flow per share - diluted $ 0.99 $ 0.94 $ 1.99 $ 2.29
======= ======== ======= =========
</TABLE>
(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.
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<TABLE>
<CAPTION>
HS Resources, Inc.
Summary of 1999 Operations
SUMMARY PRODUCTION, PRICE AND COST DATA
Quarter Ended Six Months Ended
June 30, June 30,
------------------------------ -----------------------------
% %
1999 1998 Change 1999 1998 Change
------- ------- ------ ------- ------- ------
<S> <C> <C> <C> <C> <C> <C>
Production by district (MMcfe):
D-J Basin and Northern Rockies 16,487 15,993 3% 32,978 30,685 7%
Gulf Coast 1,854 234 692% 2,890 516 460%
Mid-Continent 3 3,330 -100% 7 6,726 -100%
Total production (MMcfe) 18,344 19,557 -6% 35,875 37,927 -5%
Period Production:
Oil (MBbl) 594 699 -15% 1,188 1,390 -15%
Gas (MMcf) 14,782 15,363 -4% 28,748 29,588 -3%
Equivalent Gas (MMcfe) 18,344 19,557 -6% 35,875 37,927 -5%
Equivalent Barrels (MBoe) 3,057 3,259 -6% 5,979 6,321 -5%
Daily Production:
Oil (Bbl) 6,523 7,681 -15% 6,562 7,679 -15%
Gas (Mcf) 162,437 168,822 -4% 158,831 163,468 -3%
Equivalent Gas (Mcfe) 201,577 214,910 -6% 198,203 209,541 -5%
Equivalent Barrels (Boe) 33,596 35,818 -6 33,034 34,924 -5%
Average oil price (Bbl) $ 13.78 $ 14.63 -6% $ 13.29 $ 15.79 -16%
Average gas price (Mcf) $ 1.93 $ 1.83 5% $ 1.98 $ 2.09 -5%
Average price (Mcfe) $ 2.00 $ 1.96 2% $ 2.03 $ 2.21 -8%
Average price (Boe) $ 12.01 $ 11.76 2% $ 12.18 $ 13.24 -8%
Costs:
G&A per Mcfe $ 0.06 $ 0.11 -45% $ 0.07 $ 0.11 -36%
LOE per Mcfe $ 0.41 $ 0.42 -2% $ 0.39 $ 0.40 -3%
DD&A per Mcfe $ 0.72 $ 0.84 -14% $ 0.76 $ 0.84 -10%
G&A per Boe $ 0.35 $ 0.66 -47% $ 0.41 $ 0.63 -35%
LOE per Boe $ 2.44 $ 2.51 -3% $ 2.37 $ 2.42 -2%
DD&A per Boe $ 4.32 $ 5.05 -14% $ 4.58 $ 5.05 -9%
(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)
June 30, December 31,
1999 1998
--------- ------------
<S> <C> <C>
Assets
Current assets $ 60,878 $ 60,265
Oil & gas properties 952,398 924,663
Accumulated DD&A (201,884) (175,729)
Other assets 20,371 23,240
--------- ---------
Total assets $831,763 $832,439
========= =========
June 30, December 31,
1999 1998
--------- ------------
Liabilities and Stockholders' Equity
Current liabilities $ 65,924 $ 79,164
Bank debt 247,000 230,000
9-7/8% Subordinated notes, due 2003 74,742 74,712
9-1/4% Subordinated notes, due 2006 230,509 230,205
Other long-term liabilities & deferred revenue 11,390 21,359
Deferred taxes 46,376 44,138
Stockholders' equity 155,822 152,861
--------- ---------
Total liabilities and stockholders' equity $831,763 $832,439
========= =========
</TABLE>
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<TABLE>
<CAPTION>
HS Resources, Inc.
Summary of 1999 Operations
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
Six Months
June 30,
----------------------
1999 1998
-------- --------
<S> <C> <C>
Cash flows from operating activities:
Net income $ 225 $ 824
Depreciation, depletion and amortization 27,402 31,933
Impairment and loss/(gain) on sales of oil and gas properties 1,100 (73)
Amortization of deferred charges, debt issue costs
and deferred compensation 2,246 1,225
Surrendered and expired acreage 1,905 --
Transfer treasury stock to 401(k) plan 763 549
Deferred income tax provision 138 371
Decrease (increase) in accounts receivable (7,350) (4,022)
Increase (decrease) in accounts payable and accrued expenses (4,084) 264
Decrease in deferred revenue, net (5,480) (2,506)
Other (7) (603)
-------- --------
Net cash provided by operating activities 16,858 27,962
-------- --------
Cash flows from investing activities:
Exploration, development and leasehold costs (30,184) (56,932)
Purchase of unproved and proved properties -- (3,499)
Gas gathering and transportation facilities additions (177) (26)
Other property additions (233) (524)
Adjusted proceeds from the sale of oil and gas properties (808) 1,552
Increase (decrease) in property related payables (11,545) 11,946
-------- --------
Net cash used in investing activities (42,947) (47,483)
-------- --------
Cash flows from financing activities:
Proceeds from debt 40,000 39,000
Repayments of debt (23,000) (18,000)
Exercise of options 6 631
Issuance of common stock 611 --
Purchase of treasury stock (34) (1,605)
Other -- (613)
-------- --------
Net cash (used in) provided by financing activities 17,583 19,413
-------- --------
Net decrease in cash and
cash equivalents (8,506) (108)
Cash and cash equivalents, beginning
of the period 9,658 6,908
-------- --------
Cash and cash equivalents, end of
the period $ 1,152 $ 6,800
======== ========
</TABLE>
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<TABLE>
<CAPTION>
HS Resources, Inc.
Summary of 1999 Operations
1999 DEVELOPMENT, EXPLOITATION AND EXPLORATION COSTS
(In Thousands)
Six Months Ended 6/30/99
-----------------------------------------------------
D-J Gulf Northern
Basin Coast Rockies Other Total
------- ------- -------- ----- -------
<S> <C> <C> <C> <C> <C>
Capitalized Costs
Land $ 43 $ 2,170 $ 56 $ 82 $ 2,351
Exploration Drilling -- 4,943 842 -- 5,785
Development Drilling 2,931 -- -- -- 2,931
Recompletions and Refracs 15,297 228 (30) -- 15,495
Acquisitions -- 6 -- 17 23
Capitalized Interest & Other 3,013 460 99 27 3,599
------- ------- ------- ---- -------
Total Capitalized Costs 21,284 7,807 967 126 30,184
------- ------- ------- ---- -------
Costs Charged to Income Statement
Geological & Geophysical 103 2,928 236 220 3,487
Exploratory Dryholes 231 1,000 -- -- 1,231
Surrendered & Expired Acreage (1) 15 1,822 68 -- 1,905
Other Exploratory 318 1,095 163 27 1,603
------- ------- ------- ---- -------
Total G&G and Exploration Costs 667 6,845 467 247 8,226
------- ------- ------- ---- -------
Total Development, Exploitation
and Exploration Costs $21,951 $14,652 $ 1,434 $373 $38,410
======= ======= ======= ==== =======
</TABLE>
(1) Includes non-cash charges in the current period for certain previously
capitalized leasehold costs attributable to expired acreage and associated
capitalized interest.
8
HS RESOURCES
MODERATOR: MIKE HIGHUM
JULY 27, 1999
Operator: Good day, everyone. Welcome to this HS Resources second quarter
1999 financial results conference call. Today's call is being recorded. A
replay will be available on the HS Resources web site for the next 90 days.
You can listen to that replay at www.HSResources.com. Again, the web site:
www.HSResources.com. Or you may dial an audio text number at 719-457-0820.
Again, that number: 719-457-0820. That replay will be available starting
today at 4 o'clock central time, running through August 2nd at midnight.
At this time, I'd like to turn the call over to the president of HS
Resources, Mr. Mike Highum. Please go ahead, sir.
Mike Highum: Thank you, and welcome to HS Resources second quarter 1999
earnings conference call.
We were going to include a video component on that on our web site, but that's
just a little bit too scary at this point.
As usual, what I'm going to do is highlight a couple of items at the outset
concerning the operations and financial results for the quarter, and then I'm
going to turn it over to Jim Duffy, our CFO, to discuss in a little bit more
detail -- although we provided a great amount of detail in our press release --
a little more detail on our financial results for the quarter. And then he'll
turn it back over to me, and I'll talk a bit about our operational results in
the Northern Rockies, D-J, and in the Gulf Coast.
But first, we need to hear from our General Counsel. Before we do that, I'd like
to say that I'm here; Nick Sutton, the CEO is here; along with all the members
of our senior management team, including our V.P. of Exploration, who was
thought to be inaccessible, but it turns out he is here. So we're all here,
we're willing and happy to answer any questions that you might have when we're
all done. With that, I'll turn it over to Jim Piccone, who will recite the safe
harbor language. Jim.
Jim Piccone: Yes, hello, everybody. As usual, in this call, we'll be discussing
several matters which should be considered forward-looking statements under the
federal securities laws -- and these will include things like project plans,
capital expenditures, product prices, and similar statements. Obviously, the
actual results may differ from 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 report on Form 10K, filed
March 31, 1999.
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Mike Highum: Thank you, Jim. As I mentioned, I will highlight a couple of items
from the second quarter. I kind of like doing this, because I get to pick all
the good stuff that Duffy has to talk about, and I get to talk about it before
he does.
But first, I think, as you can tell, we were right in line with or exceeding
virtually all of the analysts' projections. Our production was up 5% from the
first quarter. We were down a little bit from the second quarter of 1998, but if
you excluded our Mid-Continent production, we were up about 13%. Similarly, our
operating cash flow is up 7% from the second quarter of 1998, and our cash flow
per share, on a fully diluted basis, was up about 5%. So these were, as I said,
along with our net income numbers, in line with or exceeded analysts'
projections.
Second, one of the things I'd like to highlight is that our D-J production, on
an Mcfe basis, was up about 3% from the second quarter of 1998 and although we
were somewhat throughput constrained -- and I will talk about that in just a
minute -- we think this is important, because it really demonstrates that while
the D-J is a mature basin, with our inventory - as I believe most of you know we
have over 5,000 different exploitation opportunities there -- we cannot only
offset our declines in the D-J, but actually increase production.
It also highlights one of the unique aspects of this asset, as we consider it to
be -- and that is, it is a concentrated base of production, situated right at
the city gate of a dynamic and growing front-range market, and we have a
dominant position. As you may know, we produce about 50% of the gas in the D-J;
about 25% of all the gas that is consumed in Colorado annually comes from our
production, and about 44% of the average daily throughput on the Public Service
Company system, system-wide, comes from our production.
I mentioned the throughput constraints. I want to step back a little bit and
tell you that we make our capital allocations on an annual basis, based on a
Monte Carlo simulation and then a linear programming model, which allows us to
build in various constraints including capital, operational, pipeline,
inventory, and by and large, in the D-J, what we always bump up against, really,
is a throughput constraint, relating to pipeline capacity and compression. If we
didn't, we would be able to spend more capex in the D-J, and increase our
production there to a greater extent. I can tell you that we're working on this,
and we would expect in the next quarter or two to be able to announce something
that would address this issue.
The third highlight that I'd like to make is that our combined LOE and G&A,
again, on a per-Boe or Mcfe basis, was not only down meaningfully from the
second quarter of 1998, but was a low $2.79 per Boe, a very attractive number.
This ranks us, I believe, second among all of the independents in operating
efficiencies -- combined G&A and LOE -- behind only, I think Newfield, and they,
of course, have low operating costs, being an offshore producer.
We are, I will tell you, continuing to work on our costs. During the quarter, we
acquired a little well-servicing company called Gunther Well Servicing, pursuant
to which we now own five service rigs, three workover units, and two swab units.
These we acquired purely for our own use -- it's not intended that the servicing
company becomes a stand-alone profit center. We will
2
<PAGE>
be using them because we have such an extensive inventory and such an aggressive
exploitation program out there.
We are also in the process of purchasing and operating eight water trucks. And
we really feel that through these two things, we will be able to reduce our
workover and operating costs by up to almost $1,000,000 a year. So what this
really demonstrates is that we have an ongoing emphasis of reducing costs
through our operations.
And with that, I think I'll turn it over to Jim Duffy to talk about our
financial results for the quarter. Jim.
Jim Duffy: Yes, thanks, Mike. I'll be just touching first, briefly, on our
production results. As Mike indicated, we reported a 13% increase in gas
equivalent production compared to last year. And that, of course, is after
giving effect to the sale of the Mid-Continent properties, which were sold in
September.
However, I think, importantly, on a sequential basis, our production increased
by more than 5% over the last quarter, and the majority of that increase is
attributable to our Gulf Coast project area, where daily production increased
nearly 80 % from the first quarter, to more than 20 million cubic feet
equivalent per day at the end of the quarter. I think also important to note
here is that the Gulf Coast production does not reflect nearly 10 million cubic
feet a day of additional net production on six wells that are currently waiting
on pipeline hook-up. Those wells are expected to be connected sometime later
this year. So we've had significant growth in production in the Gulf Coast.
In the D-J Basin, oil production -- you may have noted this in the press release
- -- but our oil production has actually declined somewhat on a year-over-year
basis. But at the same time, the much more important production figure for us --
gas -- has actually increased fairly significantly. That situation is due to
greater emphasis on our J-Sand development activities, which have a much higher
gas/oil ratio -- it's actually almost seven times as high -- relative to the
Codell/Niobrara formation, which was our existing base of production, prior to
our J-Sand activities. The J-Sand represents an increasing portion of our total
D-J production, and therefore our gas/oil ratio in the D-J is increasing as a
result.
As far as product prices are concerned during the quarter -- you know, prices
were obviously somewhat better than last year. We're continuing to see
relatively strong regional gas prices in the D-J Basin, with summertime prices
currently in the $2.15 per Mcf range. We've hedged about two-thirds of our gas
at over $2.00 per Mcf during the third quarter to take advantage of these high
summertime prices.
Oil prices, of course, have rebounded somewhat in recent weeks. As noted in our
press release, about 75% of our oil production is hedged at over $15.00 per
barrel on a NYMEX basis for the second half of the year. The oil position is a
continuation of the hedge that we executed late last year, and when you combine
that with our gas hedge position, we have a very, very stable cash flow platform
from which to fund our ongoing activities. But at the same time, we think we
have
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good exposure to product price upsides, particularly in the coming winter
months, where prices have moved up considerably.
Turning to our operating measures -- Mike touched on this -- we've continued to
realize some substantial efficiencies as the result of the sale of our
Mid-Continent properties. As you may recall, when we sold those properties, one
of the reasons for our decision to do so was we had a significantly higher
overhead cost per Boe and per Mcfe in the Mid-Continent than we did elsewhere.
By virtue of divesting those properties, we've managed to realize the continuing
efficiencies in our ongoing D-J Basin consolidation program, and continuation of
consolidation in our two core areas.
The combined LOE and G&A -- as Mike said -- is currently under 50 cents per
Mcfe, making us one of the most efficient operators in the business. Also,
during the quarter, DD&A expense decreased 14% to $0.72 per Mcfe, from $0.84 in
the prior year. That is the result of booking an additional 65 Bcfe of reserves
at July 1. That then results in total reserves at July 1 of about 1.05 Tcfe. Of
those amounts, roughly 75% are attributable to D-J Basin, and 25% to the Gulf
Coast. And in both cases, the additional reserves reflect the impact of our
ongoing development program, as well as some impact from higher product prices.
Capital expenditures for the quarter pretty much follow the program we laid out
earlier this year for funding our 1999 capex out of cash flow, and that process
continued during the quarter. We incurred capex of approximately $14.5 million,
of which about $7.5 million was allocated to the D-J Basin, a little over $6.0
million to the Gulf Coast, and the remainder to the Northern Rockies. Through
the six months ended June 30, our total capex of $38 million has essentially all
been funded out of cash flow.
With respect to our financial position, we had net borrowings during the quarter
of approximately $20 million. These were used to fund short-term working capital
requirements. In particular, we had a number of annual and semi-annual payments
that were made particularly for ad valorem and other taxes. And those resulted
in a short-term draw-down of our facility. We do expect to repay those amounts
in the coming year. We currently have outstanding borrowings of about $247
million, against a $280 million facility. That leaves us considerable financial
flexibility to fund our ongoing programs. We do anticipate a number of smaller
divestitures of non-core properties in the second half of the year, and the
proceeds from these will also be applied to our outstanding bank debt.
With that, I'll turn it back over to you, Mike.
Mike Highum: Thanks, Jim.
I'm going to now touch on the operational results, district by district.
First, in the D-J Basin, during the year, the D-J district is going to undertake
about 300 to 350 individual activities in the Wattenberg area, consisting of new
drills, recompletions, refracs, and
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the deepening of existing well bores. Through the first six months of the year,
we've done about 160 of these activities, and we expect to average 15 to 30 per
month through the rest of the year.
In particular, during the quarter, we did ten Codell refracs. From inception to
date in that program, we've now refraced more than 370 Codell wells, virtually
all of which have qualified for tax credits. These refracs continue to achieve
about a 7.5x average increase in production per well, a sub-$4.00 finding cost,
and about a 67% rate of return. We will continue our refrac program during 1999,
and we expect to do between 200 and 270 total during the year, including 65 or
so in the third quarter, and about a hundred in the fourth quarter.
In the second quarter, we also continued with our J-Sand new drill and deepening
program. We drilled seven new J-Sand stand-alone wells. They were completed and
brought on line, and 13 were deepened from existing well bores from previously
producing shallow formations. To date, our average reserves added by these new
J-Sand wells is about 840MMcfe. These are -- as Jim mentioned -- primarily or
almost entirely gas wells. So we're achieving just under a Bcf per well on these
deepenings and stand-alone new drills -- which gives us, of course, as you would
imagine, a very attractive finding cost of about a $1.60 per Boe for the
deepenings and about $2.60 per Boe for the new drills. For the year, we'll drill
as many as 24 new wells and deepen 45 existing wells in the J-Sand.
One of the things that we have done, just as a part of our ongoing effort to
enhance recoverable reserves through technology, is that we performed on one of
our J-Sand wells the biggest frac done in the Basin in about the last 15 years
with some new fluid technology, which is really designed to drain reserves from
a larger area. And while it wouldn't be applicable to use this everywhere,
preliminary results are very encouraging, and we believe that it'll lead to the
recovery of additional reserves in certain areas of our holdings. This is an
ongoing commitment to the technological improvement and enhancement of the
reserves that we control in the D-J Basin.
Taking a look now at the Gulf Coast -- during the second quarter of 1999, we
participated six wells, four of which were successful. The most notable of these
wells was the Douget #1, which is on our Indian Village project area in
Jefferson Davis Parish, Louisiana.
This is our second successful well in Indian Village, which, like our other
areas, targets the Hackberry. Remember that Indian Village is the extension of
the play that we initially developed in our successful Buhler project area, and
then moved into the North Gillis project area. This is a continuation of the
application of the technology that we have perfected. We are the operator here,
and we own a 50% working interest. This well was logged on June 25, and it's
currently being tested, but preliminary gross estimated reserves are about 12
Bcfe, and could be even greater. We expect that this well will be going online
before the end of the year. We are also currently drilling our third well in
this project area, and have another four potential locations that could be
drilled during the latter part of this year, depending on the results that we
achieve.
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In the other areas where we drilled during the quarter, we drilled two more
successful wells in our Buhler project area, bringing our total there in the
program to 15 successes in 19 attempts. Our average reserves are continuing to
run there about 450,000 Boe per well.
In Caney Creek, during the second quarter we drilled our first two wells on this
project area in Matagorda County, Texas. Our partner, Aspect, is the operator
there, and we have about a 25% interest. One of these wells, Pierce Estate #2,
was successful and is currently being completed in the Frio formation, and
preliminary reserve estimates look to be about two Bcfe. We have another three
to four potential drilling locations that we've identified that we could drill
before the end of the year, depending on results.
As Jim mentioned, during the second quarter we brought a number of wells online
in the Gulf Coast area, including some very healthy producers. Our Adams #1 well
in the Indian Village area went online the first week of April, and it's
producing more than 17 million cubic feet of gas per day. And our M Half Circle
#1 in the Lox B project area went online in the third week of April, and it's
producing almost 15 million cubic feet of gas per day. We have a 50% working
interest in each of these wells, and we're the operator.
As Jim mentioned, I think it's important to kind of highlight what's happened to
our production. At the end of the year, our net production in the Gulf Coast --
not average for the quarter, but right at the end of the year -- was about 8.7
million cubic feet of gas a day. By the end of the first quarter, it was about
almost 13 million a day. By the end of the second quarter, it's almost 25
million a day. And we still are waiting on pipeline hookups on six wells, which
we believe will bring our net Gulf Coast daily production to approximately 35
million a day. We also expect to drill between 15 and 20 wells in the Gulf
during the remainder of the year, which obviously, if successful, could increase
our daily production meaningfully above that.
In the Northern Rockies, I think that it's fair to summarize that much of the
activity in the second quarter was directed toward consolidating operations in
the Greater Green River gas projects. We believe we have a viable project that's
ongoing at South Jonah, where, structurally, we may be able to repeat a
look-alike to some of the aspects that you see in Jonah. We took over operations
on the Holmes well from McMurray, have stabilized our production, and we now are
more effectively able to evaluate the economic viability of this area. We will
be seeking a partner to drill a second well in this area this summer. Similarly,
in our North Pinedale area, we took over the Steele wellbore from Ultra at no
cost. This is a low-rate producer, but it does add to our acreage position,
offsetting our Sherlock well, and we're currently evaluating pipeline
alternatives, and waiting on partners to complete the Sherlock well.
In the Mid-Continent, during the second quarter, the district continued to
evaluate its two regional projects in the Greater Anadarko Basin. These are the
Upper Red Fork Valley play, and the Overturned Springer play along the Wichita
Mountain Front. In both of these areas, we've continued to lease, and will be
leasing as the year progresses. We anticipate being able to drill on our
Mountain Front prospect during the third quarter of the year.
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Touching on a couple other activities -- Jim mentioned some smaller divestitures
that we have had, or will have. Shortly after the close of the quarter, we
entered into two divestiture agreements.
The first was to sell our Blue Forest unit in Wyoming. We're not at liberty to
disclose the buyer or terms at this point. There's effectively, a
confidentiality agreement until the deal has been closed and we can agree upon a
press release. But this is an attractive sale of a non-core asset for us, and
it's at a meaningful premium for the value that's carried in our reserve
engineering. It's a very attractive price on a per-book Boe basis. The purchase
and sale agreement was signed on July 20th, and we expect it to close on August
10th.
We also sold, to Southwestern Production, some interests in the D-J Basin --
primarily royalty and overriding royalty interests in non-operated wells in the
D-J, for about $1.5 million.
We have another two to four of these type of projects in the D-J that we're
working on that I think it would be most accurate to describe as rationalizing
the assets in the D-J that we're currently holding. Some of these might be
sales, some might be the swap of formations and wellbores to more efficiently
recover the reserves that we have out there. A couple of those two to four may
be a little more meaningful in size, and we would expect to be able to announce
them in the third or fourth quarter.
And that's about it. With that, I'd like to turn it over to questions and
answers -- or Nick, if you have anything you'd like to add?
Nick Sutton: No, let's just entertain questions.
Operator: And thank you, gentlemen. Today's question and answer session will be
conducted electronically. If you'd like to ask a question, you may do so by
pressing the star button, followed by the digit one on your touch-tone
telephone. Again, to ask a question, press the star, one buttons on your
telephone. We'll go first to Bob Morris with PaineWebber.
Bob Morris: Good afternoon. Had three questions, actually. First question was on
the additional reserves you booked at year end, you mentioned that some of that
was attributable to higher oil and gas prices. Can you tell me how much of the
67 Bcf adds were attributable to higher commodity prices?
Jim Duffy: It's somewhere around 60%, Rob.
Bob Morris: OK. On the throughput constraints, you mentioned that impact of
production versus a year ago second quarter. Have you incurred some abnormal
constraints, apart from what you would have incurred last year, or just seasonal
during this time of year? Is there anything different than what you would
normally incur here?
Mike Highum: No, Rob, actually, compared to the second quarter of last year,
we're up -- our production is up. The throughput constraints are really system
constraints. If we push our capex
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too aggressively, we reach the capacity -- the throughput capacity on the
pipeline and the compression.
Bob Morris: OK. And wasn't there supposed to be about a 20 million a day
expansion by Duke Energy this month, or the pipeline system up there, is that
still on schedule?
Mike Highum: It still is on schedule. In fact, Nick and I just had an
opportunity to talk to the Duke guys about that a couple days ago, and Dale
Cantwell works with it on a day to day basis -- but they're bringing the Roggen
plant back online, and it is ...
Dale Cantwell: Tomorrow.
Mike Highum: It's online tomorrow. So that will alleviate some of it, but there
are constraints that we run to; depending on how aggressive we get on our capex
program, we run into constraints not only on the Duke system, but also on the KN
system.
Bob Morris: OK. And the last question I had was -- in drilling some of
these Hackberry wells, have you thought about or done anything with regard to
potentially drilling some of those to the deeper Yegua or Vicksburg?
Mike Highum: As a matter of fact, when we look at the seismic, Yegua and
Vicksburg are part of what our overall program is there. And on North Gillis we
drilled one Yegua well that was a really good well -- it was about 16 Bcf, I
think -- is that right? 13 Bcf. The Yegua is definitely a target in all these
places where we have the Hackberry. We have a number of projects and prospects
where the deeper formations are targeted.
Nick Sutton: If I could jump in there. The nature of these prospects is such
that you don't always have these formations lining up so that it's a matter of
just going deeper. But as we go through our geological and geophysical analysis,
we're always looking for potential in the deeper formations.
Bob Morris: OK. Great. Thank you.
Operator: Chris Sheehan, John S. Herold.
Chris Sheehan: Hello, gentlemen. My question on the reserve adds was asked
and answered. Thank you.
Operator: Ellen Hannan, Bear Stearns.
Ellen Hannan: Good afternoon. Or good morning, I guess, wherever you are. A
question about the constraints out in the D-J -- do you think that the merger of
KN with Kinder Morgan -- will that do anything for you, will it hold you back,
will it accelerate things, or what's your take on that?
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Nick Sutton: I think it's fair to say that it adds an element of uncertainty in
terms of the overall direction of the new organization. Nonetheless, from the
field standpoint, it's sort of business goes on as usual. I think the thing that
I would like to emphasize is that we believe that there are several different
alternatives that we have available to us to deal with our ability to take our
production into the processing plants and downstream. And so we're actively
working all of those options, and the KN/Kinder Morgan situation is just sort of
the top of the wave, with some action on it, but we're really working a lot
deeper than that.
Mike Highum: Yes, Nick, I think it's OK to just briefly mention one of the
things. We are actively looking at, and we've done the leasing and the right of
way, and we're actively looking at our own bypass system. And whether or not we
pursue that finally -- but we're well into the FERC process with it, and it's
pretty much known out here. That would alleviate a significant amount of the
constraint that's there. There are alternatives to us doing that, which we are
pursuing.
Ellen Hannan: Now, in addition to that, then, do you need still further
expansion by the Duke line, to be able to hook into that as well, or would that
solve your problem?
Mike Highum: No, the steps they're taking with the plant would solve that.
Ellen Hannan: Thanks.
Nick Sutton: We should also make the point, Mike, that the work we're doing with
respect to a bypass system is not just to enhance the capacity of the system,
but it also would substantially reduce our gathering rate, which is also
something that we're currently talking about with KN and others in the area. So
it goes beyond just capacity.
Mike Highum: Yes, it's strong economics, too.
Ellen Hannan: Just one other question, if I may. What are your thoughts on
the terms of your exit rate for the Gulf Coast in terms of production for
this year?
Mike Highum: I'm just going to check this one, because Tony Church sitting here
with me and being the explorationist, every time I start to come up with an exit
rate, Tony starts to get a little uncomfortable, because it requires successful
drilling of exploratory wells that are in the future.
Ellen Hannan: OK. Well, so -- let me rephrase the question. Is 35 million
going forward a good number, assuming that the six wells get hooked up? The
35 million a day ...
Mike Highum: 35 million is good, assuming the six wells get hooked up, and
Tony tells me that he's relatively comfortable with 45 million by the end of
the year.
Ellen Hannan: Great. Thanks very much.
Operator: Tom Parker, Chase Securities.
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Tom Parker: Hi. Any expectation on how much of those wells will hit the
third quarter, versus the fourth?
Jim Duffy: Majority will be in the fourth.
Tom Parker: Majority in the fourth. OK. And then, in terms of -- any rough
idea on -- on what your kind of expected size of divestiture program from
here on is?
Mike Highum: Yeah, no, the divestitures that we're talking about are not
big, Tom. These are more, as I said, along the lines of rationalization.
Enhancing the efficiency of what we have out there.
Tom Parker: So less than $5 million, or something like that?
Mike Highum: And some of them will actually probably be swaps.
Tom Parker: Yes. OK.
Mike Highum: And incidentally, on the wells being hooked up in the Gulf Coast,
what you should understand is the primary issue that we have run into here is
that there are some wetlands-related issues that came up when the pipeline was
going to build their pipeline to gather the production. And it's just something
that's taken some time to work through the various agencies that are required to
approve it.
And we believe that we have the issue solved on a going-forward basis, it just
is affecting a small handful of these wells that are drilled in a particular
area that are nice wells that should meaningfully contribute to our production.
Tom Parker: OK. And then in terms of the G&A level, is this now a pretty
good level, or was there something unusual, or are we running at a good run
rate right now?
Jim Duffy: Well, the current quarter rate, Tom, I think is probably below where
we will be on a continuing basis. But you know, we've indicated earlier that we
wanted to be below 50 cents per Mcfe on a continuing basis, and from what we can
see -- that's a combination of LOE and G&A -- and right now, everything we see
would suggest that we'll do better than that. The distinction between LOE and
G&A is a little harder, but certainly on a combined basis, we're very
comfortable with that level on a go-forward basis. And we think, we may well do
better than that.
Tom Parker: OK. And then, finally, on the use of debt this quarter, on the
working capital -- will that reverse itself in the rest of the year, or is
that kind of a permanent.
Jim Duffy: Yes, for the most part, that will be reversed by the end of the
year.
Tom Parker: OK. That's great. Thank you very much.
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Operator: Ray Deacon, Southcoast Capital.
Ray Deacon: Yeah, hi, good afternoon. I just wanted to make sure I understand
the reserve additions in the first half. Is it 65 Bcfe were added during the
first half, and is it -- that's after taking out production, is what you're
saying? I'm trying to back into a reserve replacement rate for the first half.
Jim Duffy: That's gross reserve additions for the first half. Gross meaning
before production, net to us, obviously.
Ray Deacon: Net to you guys, after taking out production. OK. I see.
Great. How would the addition of a bypass system affect -- I guess it would
show up in your differentials? I mean, much better would you do on
realizations by building this system, and what type of cost would be
associated with it?
Jim Duffy: That's a good question. The thing I would say right now, Ray, is that
we are in the various stages of engineering refinement of the overall system.
Obviously, we won't undertake this if we don't feel that we will get significant
financial returns. To quantify it at this stage in terms of actual dollars, I
think, is a little bit premature.
Ray Deacon: OK. And just one more quick one is, have you been able to
replace the inventory of what you're drilling in the Gulf Coast this year
with new prospects for 2000 drilling?
Mike Highum: Yes, though we don't really talk about it too much, while we're
drilling these, we are actively working on a number of other project areas. And
we're actually quite excited about some of the other things that our exploration
staff is concocting in the Gulf Coast area.
Ray Deacon: OK. All right, good. Well, thank you.
Operator: Breege Farrell, Bank One.
Breege Farrell: Most of my questions have been answered, but I was wondering if
you could give us just a little more understanding of the differences in the
kind of frac you did when you did your major frac in the D-J, what you were
talking about as far as improved technology.
Mike Highum: Yes, Dale Cantwell is here -- he's the V.P. of our D-J
District, and he can address that.
Dale Cantwell: What we did is two things. Number one is the fracs that we
normally do on the J-Sand are about a half million pounds of sand and about
5,000 barrels of fluid. And what we have done is really almost doubled the size
of that frac -- it was slightly over a million pounds of sand. And, a doubling
of the fluid volumes. What we have done is with that we saw a lot of further
extension of the reservoir, a lot bigger frac, and we expect in the particular
area where we
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did the frac that we will see a significantly larger drainage area, and probably
about a 30% increase in the reserves -- at least that's kind of what we're
predicting.
The results are encouraging, but we're still not able to absolutely quantify it
at this point in time, because it's still so early. But the difference is, it's
just a lot bigger frac. And historically, if you look at things that have been
done in the D-J, it's also a lot more fluid, and the fluid is what generally
creates the fracture in the rock. The sand really just holds that fracture open.
Breege Farrell: So there are there significant numbers of other areas where this
would be applicable in the D-J, or it's too early to even tell?
Dale Cantwell: We certainly believe there's a lot of other areas that it's
applicable within the J-Sand formation. We have probably almost 500 sites in
inventory within the J-Sand, and so it's extremely important to understand all
the possible potential out there, and that's why we undertook this activity.
Breege Farrell: OK, great. Thank you.
Operator: John Herrlin, Merrill Lynch.
John Herrlin: Yes, hi, guys. Couple questions. One, on the gathering
system, volume-wise, how much throughput are you kind of targeting?
Mike Highum: John, this is Mike. How are you doing, John?
John Herrlin: Fine, you?
Mike Highum: Good. Which system are you talking about?
John Herrlin: In the D-J, you were talking about possibly building your own
gathering system. I was wondering, incrementally, how much volume you were
looking at in throughput for what you were thinking about doing?
Mike Highum: It would be about 50 million a day.
John Herrlin: OK. And then, next question's on the Gulf Coast. You're
having good success. Will this change your capital budgeting plans for, say,
2000, going forward?
Mike Highum: Well, as a general matter, John as you know from being around our
company as long as you have, one of the nice things about the D-J is that it's
all held by production. So to the extent that we are having a great deal of
success in the Gulf Coast, we have the ability to increase our capital spending
there.
Of course, we're sensitive to various matters of risk and those things. But I
will say this, as I mentioned earlier, the way we do our capital allocation is
through this LP model, which really
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ranks our projects. And if the Gulf Coast continues to have the amount of
success that it's had, and we see an increasing number of projects that fall
into those categories, I think it would be not at all unlikely to see us shift
some. But we're always cognizant of risk, and we like the balance that we have
between the exploratory projects in the Gulf Coast, and the low-risk
exploitation stuff in the D-J.
John Herrlin: OK, thanks.
Nick Sutton: Hey, Mike.
Mike Highum: Yes, sir.
Nick Sutton: I'm going to jump in here and address the pipeline situation a
little bit more.
Mike Highum: OK.
Nick Sutton: One of the things I'd like to emphasize is that as we are looking
at a potential bypass, one of the reasons we're doing that is that we have a
contract for some of our gas that's due to expire in roughly June of this coming
year. That gives us a lot of leverage as to how we are going to deal with the
transportation of that gas. In other words, it may well be that the best
alternative we have for moving our gas is with a new pipeline. At the same time,
it gives us a lot of leverage to deal with other gatherers in the area, because
we have a lot of volumes which we now can swing to the best alternative -- which
currently and for the next roughly nine months are contractually committed to a
particularly pipe.
So it's really a broad strategic initiative that we're dealing with, in terms of
looking into a bypass.
Jim Duffy: And just to add to that, under virtually all of the alternatives that
we're looking at, whether it's to stay where we are in terms of the existing
arrangement with some expanded capacity on that system, or to do our own -- in
each case, it represents a reduction, or at least an anticipated reduction,
potentially fairly meaningful, compared to our current gathering rates. So we're
going to lower our gathering rate across the board, while we expanding our
capacity.
Mike Highum: We have a lot of leverage here because we have a big chunk of
gas that we can do what we want to do with it, it's committed.
Nick Sutton: As I put it frequently, a pipe with no gas to go through it is
not an asset, it's a liability.
Operator: Once again, to ask a question press the star, one, buttons on your
telephone.
We'll go next to Andy Parr, Loomis Sayles.
Andy Parr: Hi, guys. Forgive me if I missed it already, but could you give
me some idea where you see production exiting at this year -- what rate?
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Jim Duffy: We addressed the Gulf component. You mean total?
Andy Parr: Yes. Total, please.
Mike Highum: Why don't you provide that off-line?
Jim Duffy: Yes, we generally don't give actual production forecasts. I
guess probably the best way to do it is we can talk to you off-line, we can
work through some of the analysts to help you get that.
Andy Parr: All right. Thanks.
Operator: Tom Parker, Chase Securities.
Tom Parker: Yes, I was curious if when you did your mid-year reserves, you did a
PV calculation, and where that came out relative to what it was at year end?
Jim Duffy: Yes, we did. Do you have that, Ted? We'll get it while we
continue here, Tom. We did do one, yes.
Tom Parker: OK.
Nick Sutton: Ted just went to get it, so, if there's any other questions, we
can get to that in a minute.
Tom Parker: OK.
Mike Highum: Are there other questions?
Operator: There are no more questions at this time.
Mike Highum: That of course would be the case. You can get that to Tom.
Jim Duffy: Yes, we'll get that to you, and if there's anybody else who would
like that information, feel free to call us -- either Ted or myself.
Mike Highum: OK. With that, I guess we're done. Thank you very much for
joining us. If you have any additional questions, you can call either here
in Denver or San Francisco.
Thank you very much. Bye.
Operator: And ladies and gentlemen, this concludes our conference today. We
do thank you for your participation. You may disconnect at this time.
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