<PAGE> 1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 16, 2001
REGISTRATION NO. 333-47540
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------------------
AMENDMENT NO. 2
TO
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
----------------------
ENCORE ACQUISITION COMPANY
(Exact Name of Registrant as Specified in Its Charter)
<TABLE>
<S> <C> <C>
DELAWARE 1311 75-2759650
(State or Other Jurisdiction of (Primary standard industrial I.R.S. Employer
Incorporation or Organization) classification code number) (Identification Number)
</TABLE>
----------------------
777 MAIN STREET, SUITE 1400
FORT WORTH, TEXAS 76102
TELEPHONE: (817) 877-9955
(Address, Including Zip Code, and Telephone Number,
Including Area Code, of Registrant's Principal Executive Offices)
I. JON BRUMLEY
CHAIRMAN OF THE BOARD, PRESIDENT AND CHIEF EXECUTIVE OFFICER
ENCORE ACQUISITION COMPANY
777 MAIN STREET, SUITE 1400
FORT WORTH, TEXAS 76102
TELEPHONE: (817) 877-9955
(Name, Address, Including Zip Code, and Telephone Number,
Including Area Code, of Agent for Service)
----------------------
With a copy to:
<TABLE>
<S> <C>
F. RICHARD BERNASEK R. JOEL SWANSON
KELLY, HART & HALLMAN, P.C. BAKER BOTTS L.L.P.
201 MAIN STREET, SUITE 2500 910 LOUISIANA
FORT WORTH, TEXAS 76102 HOUSTON, TX 77002
TELEPHONE: (817) 332-2500 TELEPHONE: (713) 229-1330
FACSIMILE: (817) 878-9280 FACSIMILE: (713) 229-7730
</TABLE>
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable on or after the effective date of this Registration Statement.
If any of the securities being registered on this form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, check the following box. [ ]
If this form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]
------------------------------------
If this form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
------------------------------------
If this form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
------------------------------------
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933, AS AMENDED, OR UNTIL THE REGISTRATION STATEMENT
SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION,
ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.
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--------------------------------------------------------------------------------
<PAGE> 2
The information in this prospectus is not complete and may be changed.
These securities may not be sold until the registration statement filed
with the Securities and Exchange Commission is effective. This
preliminary prospectus is not an offer to sell these securities nor does
it seek an offer to buy these securities in any jurisdiction where the
offer or sale is not permitted.
SUBJECT TO COMPLETION. DATED JANUARY 16, 2001.
7,150,000 Shares
[ENCORE LOGO]
ENCORE ACQUISITION COMPANY
Common Stock
----------------------
This is an initial public offering of shares of common stock of Encore
Acquisition Company. All of the 7,150,000 shares of common stock are being sold
by Encore Acquisition Company.
Prior to this offering, there has been no public market for the common
stock. It currently is estimated that the initial public offering price per
share will be between $13.00 and $15.00. Encore has applied for the listing of
the common stock on the New York Stock Exchange under the symbol "EAC".
See "Risk Factors" beginning on page 8 to read about certain factors you
should consider before buying shares of the common stock.
----------------------
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY OTHER REGULATORY
BODY HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ACCURACY
OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL
OFFENSE.
----------------------
<TABLE>
<CAPTION>
Per Share Total
--------- -----
<S> <C> <C>
Initial public offering price............................... $ $
Underwriting discount....................................... $ $
Proceeds, before expenses, to Encore Acquisition Company.... $ $
</TABLE>
To the extent that the underwriters sell more than 7,150,000 shares of
common stock, the underwriters have the option to purchase up to an additional
1,072,500 shares from Encore at the initial public offering price less the
underwriting discount.
----------------------
The underwriters expect to deliver the shares against payment in New York,
New York on , 2001.
GOLDMAN, SACHS & CO. CREDIT SUISSE FIRST BOSTON
DAIN RAUSCHER WESSELS
PETRIE PARKMAN & CO.
----------------------
Prospectus dated , 2001.
<PAGE> 3
The following map shows the location of Encore's principal production
property.
[MAP]
i
<PAGE> 4
SUMMARY
This Section summarizes what we believe are the material aspects of our
offering. We encourage you to read this prospectus in its entirety before making
an investment decision. References to "Encore", "we", "our" or "us" refer to
Encore Acquisition Company and our subsidiaries. You will find definitions for
oil and natural gas industry terms used throughout our prospectus in "Glossary
of Certain Oil and Natural Gas Terms". The estimates included in our prospectus
of proved oil and natural gas reserves are based upon the reports of Miller and
Lents, Ltd., an independent engineering firm, rolled forward by Encore to
reflect reserve information as of September 30, 2000.
ABOUT ENCORE
Encore is a recently organized, rapidly growing independent energy company
engaged in the acquisition, development and exploitation of North American oil
and natural gas reserves. Our oil and natural gas reserves are concentrated in
fields located in the Williston Basin of Montana and North Dakota, the Permian
Basin of Texas and New Mexico and the Anadarko Basin of Oklahoma.
Our Cedar Creek Anticline properties, which are located in Montana and
North Dakota, constitute our core asset, representing approximately 72% of our
total reserve value at September 30, 2000. These high quality properties, which
have produced for several years through waterflooding, are 97% oil by equivalent
volume. The reserves are long-lived, and production rates have declined at
relatively low rates from year to year over the past several years. Since
discovery, our Cedar Creek Anticline properties have produced 393 MMBbl of oil
and 89 Bcf of natural gas. These volumes reflect about 20% of the estimated
original in place reserves that can be recovered using primary and secondary
recovery methods. With gross proved remaining reserves of 119 MMBbl of oil and
24 Bcf of natural gas, the estimated ultimate recovery factor is approximately
26% of the original in place volumes. During June 1999, the first month of
Encore's ownership of the Cedar Creek Anticline, the properties produced 9,099
net barrels of oil equivalent per day, which consisted of 8,767 Bbls of oil and
1,994 Mcf of natural gas, and produced 53,660 barrels of water per day. The
average water cut, or the percentage of the total fluids produced that is water,
is 86%. During September 2000, 15 months after the initial acquisition, the
properties produced 10,733 net BOE/D, which consisted of 10,332 Bbls of oil and
2,466 Mcf of natural gas, and produced 65,506 barrels of water per day. Adjusted
for the additional acquired volumes, which represent 9% of the increase, Encore
has offset the natural field decline and increased production by an additional
9%. This increase resulted from an aggressive program of monitoring the
performance of, and repairing, refurbishing and recompleting, certain existing
wells, coupled with drilling additional wells. The Cedar Creek Anticline is
significant, not only because of its size, but also because of the quality of
its remaining development opportunities. Our technical studies have identified
over 200 prospective development locations in the Cedar Creek Anticline that we
plan to drill over the next four years.
Encore was organized in 1998 and made its first property acquisition in
June 1999. Although we have only been organized for a short time, our executive
officers average more than 23 years experience in the industry. Each of our
executive officers and key employees has made a significant cash investment in
our common stock.
Since our inception in April 1998, we have invested $298 million in
acquiring producing oil and natural gas properties. As of September 30, 2000, we
had estimated proved oil and natural gas reserves of 85 million Bbls of oil and
67 Bcf of natural gas, or a total of 96 MMBOE. Factoring in 5.7 MMBOE of
production and $29.3 million of capital investment in our acquired properties,
our total or "all-in" acquisition and development cost is $3.22 per BOE since
inception. Encore believes that we can acquire and exploit reserves at a cost
per BOE lower than reserves found and developed through exploration programs.
This is borne out by comparing the
1
<PAGE> 5
industry average three-year historical proved reserve acquisition cost of $4.26
per BOE to the industry average three-year historical finding and development
cost of $6.45 per BOE calculated on a comparable basis. The pretax present value
of future net revenues of our reserves, discounted at 10% per annum, or "PV-10
value", was $611 million at September 30, 2000. The standardized measure of our
reserves, calculated on an aftertax basis, was $448.5 million at that date.
Prevailing prices as of that date were $30.83 per Bbl of oil and $5.13 per Mcf
of natural gas. Our existing properties have substantial development potential,
including a significant tertiary recovery project that will use the injection of
carbon dioxide into the producing formations of our Williston Basin properties.
The following table shows, on a pro forma basis, information regarding net
production from our principal producing properties for September 2000 and
reserves of those properties at September 30, 2000.
PROPERTIES -- PRINCIPAL AREAS OF OPERATIONS
<TABLE>
<CAPTION>
NET
PRODUCTION
FOR SEPTEMBER PROVED RESERVE QUANTITIES PV-10
2000 AT SEPTEMBER 30, 2000 AT SEPTEMBER 30, 2000
---------------- -------------------------- ------------------------
NATURAL
OIL GAS TOTAL AMOUNT(1)
BOE/D PERCENT (MBBLS) (MMCF) (MBOE) (IN THOUSANDS) PERCENT
----- ------- ------- ------- ------ -------------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
Cedar Creek
Anticline............ 10,733 65% 82,083 12,641 84,190 $436,790 72%
Crockett County........ 1,542 9 121 35,216 5,990 79,456 13
Lodgepole.............. 2,659 16 2,179 914 2,331 50,859 8
Indian Basin/Verden.... 1,550 10 258 18,725 3,379 43,993 7
------ --- ------ ------ ------ -------- ---
Total........ 16,484 100% 84,641 67,496 95,890 $611,098 100%
====== === ====== ====== ====== ======== ===
</TABLE>
---------------
(1)Without deducting the discounted value of hedging transactions, which
aggregated $26.5 million based on prevailing prices at September 30, 2000.
STRATEGY
Our strategy is to grow our reserves and production using approximately
one-half of our internally generated cash flow. We intend to use our remaining
cash flow to repay debt, fund acquisitions and pursue additional development
opportunities. We intend to maximize internally generated cash flow and
shareholder value by continuing our development program on our existing
properties and by acquiring properties with similar potential. We intend to
pursue property acquisitions during periods of attractive acquisition values and
to emphasize development activities during periods of higher acquisition values.
We plan to dedicate one-half of our anticipated cash flow over the next four
years to drill over 200 development wells in the Cedar Creek Anticline and
additional development wells in our other areas of operation. We believe that
additional growth will come from acquisitions and other development projects not
yet identified. Based on our ability to grow our reserves with internally
generated cash flow, we expect our balance sheet to remain strong.
To execute our strategy, we plan to:
- pursue an active development and exploitation program on existing
properties;
- control costs through efficient operations of existing properties; and
- continue our successful acquisition program.
2
<PAGE> 6
DEVELOPMENT OF EXISTING PROPERTIES. Our properties generally have long
reserve lives and reasonably stable and predictable well production
characteristics. The pro forma Reserve-To-Production, or R/P, Index for our
proved reserves at September 30, 2000 was 16.5 years based on annualized nine
month production. The R/P Index, which is often used to compare productive lives
of oil and natural gas properties, is calculated by dividing total estimated
proved reserves by production for the past twelve months.
We expect to spend approximately 50% of our internally generated cash flow
to replace production through developing and exploiting our core properties. The
inventory of potential development drilling locations or major recompletion
opportunities on our existing properties is sufficient to sustain this program
for approximately four years. Longer term, we believe that there is significant
value to be created through a carbon dioxide tertiary oil recovery project in
the Cedar Creek Anticline. The prior owner of these properties conducted a
successful CO(2) pilot project in 1985. While it did not proceed with a
full-scale commercial project, we believe that a number of factors make such a
project more feasible in the present environment. First, prevailing commodity
prices are significantly higher today than in 1985. Moreover, there are now two
sources of CO(2) available in quantities and at prices we consider commercially
attractive. Commercial availability of CO(2), coupled with the industry's 15
years of accumulated successful experience with CO(2) tertiary recovery
projects, indicates that a CO(2) project in the Cedar Creek Anticline could be
commercially feasible in the next several years. Fully implemented, CO(2)
flooding in the Cedar Creek Anticline could significantly increase our proved
reserves. We believe that an incremental 16% of the original oil in place can be
recovered through CO(2) flooding. This estimate is based on internally prepared
computer models that have been calibrated to match both the historical Cedar
Creek Anticline waterflood performance and the 1985 CO(2) pilot results. There
are inherent risks in estimates based upon computer models and those estimates
may ultimately be inaccurate. Encore's technical staff, which includes
professionals with CO(2) experience with major oil companies starting in the
1970s, anticipates that approximately 60% of the Cedar Creek Anticline
properties will be suitable for CO(2) flooding.
EFFICIENT OPERATIONS. We operate properties representing 81% of the PV-10
value of our proved reserves, which allows us to control capital allocation and
expenses. For the nine months ended September 30, 2000, our pro forma lease
operating expenses consisted of direct lifting costs of $3.33 per BOE produced
and production, ad valorem and severance tax payments of $2.69 per BOE produced.
Our general and administrative costs averaged $0.88 per BOE produced.
CONTINUED SUCCESSFUL ACQUISITION PROGRAM. Encore, using the experience of
our senior management team, has developed and refined an acquisition program
designed to increase our reserves and to complement our core properties. We have
a total of 24 engineering and geoscience professionals who manage our core
properties and use their experience and expertise to target attractive
acquisition opportunities. Following acquisition, our technical professionals
seek to enhance the value of the new assets through a proven development and
exploitation program. Through September 30, 2000, Encore has completed four
acquisitions, at a total initial acquisition cost of $298 million, representing
96 million BOE of proved reserves at September 30, 2000.
CHALLENGES TO IMPLEMENTING OUR STRATEGY. We face a number of challenges in
implementing our strategy and achieving our goals. We are recently organized and
experienced losses in our organizational and start-up periods. Achieving our
goals is dependent upon continued strong commodity prices and the availability
of capital. We will face strong competition for acquisitions, capital and
employees from major oil companies and independents. Other risks that we will
face are described in "Risk Factors," beginning on page 8.
RECENT DEVELOPMENTS. Effective October 1, 2000, we acquired producing
properties in Powder River and Carter Counties, Montana, known as the Bell Creek
Field for a total purchase amount of $7.3 million, of which $5.8 million is
attributable to the properties and $1.5 million is
3
<PAGE> 7
attributable to an escrow account to cover the anticipated costs of plugging and
abandoning wells.
OUR EXECUTIVE OFFICES
Our headquarters are located at 777 Main Street, Suite 1400, Fort Worth,
Texas, 76102, and our telephone number is (817) 877-9955.
THE OFFERING
Common stock offered by Encore............ 7,150,000 shares
Common stock to be outstanding after this
offering.................................. 30,030,000 shares (1)
Use of proceeds........................... We intend to use the net proceeds
from the offering to repay a
portion of the debt under our
credit agreement. We will use the
increased borrowing capacity under
our credit agreement, along with
internally generated cash flow, to
pursue development, exploitation
and acquisition activities and for
general corporate purposes.
Proposed New York Stock Exchange Symbol... EAC.
---------------
(1) Assuming no exercise of the underwriters' overallotment option. Excludes
1,802,000 shares of common stock reserved for issuance under our incentive
stock plan. No restricted stock awards have been made and no options have
been granted under the plan.
4
<PAGE> 8
SUMMARY CONSOLIDATED HISTORICAL AND PRO FORMA FINANCIAL DATA
The following table presents summary consolidated historical financial data
for the years ended December 31, 1998 and 1999 and for the nine months ended
September 30, 1999 and 2000, in each case derived from the consolidated
financial statements of Encore Acquisition Company, and pro forma information
prepared as if the acquisitions of oil and natural gas properties referred to as
Cedar Creek Anticline, Crockett County, Lodgepole and Indian Basin/ Verden had
taken place on January 1, 1999 with respect to the statement of operations data.
You should read the following data along with "Selected Consolidated
Financial Data", "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the consolidated financial statements and related
notes, each of which is included in this prospectus. You should also read the
pro forma information together with the unaudited pro forma combined financial
statements and related notes included in this prospectus.
<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
----------------------------------------------------------- ----------------------------
PERIOD FROM
INCEPTION
(APRIL 22, 1998) NINE MONTHS ENDED NINE MONTHS
THROUGH YEAR ENDED SEPTEMBER 30, YEAR ENDED ENDED
DECEMBER 31, DECEMBER 31, ------------------------- DECEMBER 31, SEPTEMBER 30,
1998 1999 1999 2000 1999 2000
---------------- ------------ ----------- ----------- ------------ -------------
(UNAUDITED) (UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues(1)........................... $ -- $ 31,264 $ 16,268 $ 74,911 $ 86,379 $ 90,763
-------- --------- --------- -------- ----------- -----------
Operating expenses:
Direct lifting costs................. -- 8,408 4,430 12,373 19,325 14,505
Production, ad valorem and severance
taxes.............................. -- 5,427 2,824 10,675 11,161 11,732
General and administrative........... 1,066 4,047 2,511 3,845 5,281 3,845
Depletion, depreciation and
amortization....................... 18 5,283 2,966 14,856 26,692 19,130
-------- --------- --------- -------- ----------- -----------
Total operating expenses....... 1,084 23,165 12,731 41,749 62,459 49,212
-------- --------- --------- -------- ----------- -----------
Income (loss) from operations......... (1,084) 8,099 3,537 33,162 23,920 41,551
-------- --------- --------- -------- ----------- -----------
Other income (expenses):
Interest expense..................... -- (4,037) (2,148) (7,358) (11,043) (8,717)
Other................................ 74 202 129 416 202 416
-------- --------- --------- -------- ----------- -----------
Total other income (expense)... 74 (3,835) (2,019) (6,942) (10,841) (8,301)
-------- --------- --------- -------- ----------- -----------
Income (loss) before income taxes..... (1,010) 4,264 1,518 26,220 13,079 33,250
Provision for income taxes............ -- (1,259) (1,067) (10,113) (4,658) (12,824)
-------- --------- --------- -------- ----------- -----------
Net income (loss)..................... $ (1,010) $ 3,005 $ 451 $ 16,107 $ 8,421 $ 20,426
======== ========= ========= ======== =========== ===========
Net income (loss) per common share:
Basic and diluted.................... $ (5.18) $ 8.20 $ 1.24 $ 43.88 $ .28(2) $ .68(2)
Weighted average number of common
shares outstanding................. 195,036 366,631 366,044 367,070 29,906,786(2) 29,934,035(2)
OTHER FINANCIAL DATA:
Adjusted EBITDA(3)................... $ (1,066) $ 13,382 $ 6,503 $ 48,018 $ 50,612 $ 60,681
Net cash provided by (used in)
operating activities............... (949) 9,759 2,272 29,611
Net cash used in investing
activities......................... (289) (201,701) (196,983) (82,852)
Net cash provided by financing
activities......................... 4,705 194,972 192,972 48,346
</TABLE>
---------------
(1) Revenues are net of net profits interests and effects of hedging
transactions.
(2) Adjusted to give effect to the Recapitalization and the issuance of an
additional 7,150,000 shares included in this offering.
(3) Adjusted EBITDA (as used herein) is defined as net income (loss) before
interest income and expense, income taxes, depletion, depreciation and
amortization. While Adjusted EBITDA should not be considered in isolation or
as a substitute for net income (loss), operating income (loss), cash flow
provided by operating activities or other income or cash flow data prepared
in accordance with generally accepted accounting principles or as an
indicator of a company's financial performance, we believe that it provides
additional information with respect to our ability to meet our future debt
service, capital expenditures and working capital requirements. When
evaluating Adjusted EBITDA, investors should consider, among other factors,
(i) increasing or decreasing trends in Adjusted EBITDA, (ii) whether
Adjusted EBITDA has remained at positive levels historically and (iii) how
Adjusted EBITDA compares to levels of interest expense. Because Adjusted
EBITDA excludes some, but not all, items that affect net income and may vary
among companies, the Adjusted EBITDA presented above may not be comparable
to similarly titled measures of other companies. While we believe that
Adjusted EBITDA may provide additional information with respect to our
ability to meet our future debt service, capital expenditures and working
capital requirements, certain functional or legal requirements of our
business may require us to utilize our available funds for other purposes.
5
<PAGE> 9
SUMMARY CONSOLIDATED HISTORICAL AND PRO FORMA FINANCIAL DATA
The following table presents selected balance sheet data as of December 31,
1998, 1999 and September 30, 2000 on two bases:
- on an actual basis; and
- on an adjusted basis giving effect to this offering and to reflect our
anticipated use of the estimated net proceeds of this offering at an
assumed initial public offering price of $14.00 per share (the midpoint
of the price range shown on the cover page of this prospectus).
<TABLE>
<CAPTION>
AT SEPTEMBER 30, 2000
AT DECEMBER 31, AT DECEMBER 31, ------------------------
1998 1999 HISTORICAL AS ADJUSTED
--------------- --------------- ---------- -----------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C>
BALANCE SHEET DATA:
Current assets............ $3,475 $ 17,766 $ 25,442 $ 25,442
Oil and natural gas
properties, net........ -- 195,585 298,633 298,633
Other property and
equipment, net......... 271 1,080 1,189 1,189
Other assets.............. 5 1,140 6,370 6,370
------ -------- -------- --------
Total assets...... $3,751 $215,571 $331,634 $331,634
====== ======== ======== ========
Current liabilities....... $ 56 $ 12,640 $ 38,919 $ 38,919
Long-term debt............ -- 99,250 143,094 51,001
Deferred income taxes..... -- 1,259 8,780 8,780
Stockholders' equity...... 3,695 102,422 140,841 232,934
------ -------- -------- --------
Total liabilities
and
stockholders'
equity.......... $3,751 $215,571 $331,634 $331,634
====== ======== ======== ========
</TABLE>
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<PAGE> 10
SUMMARY OPERATING AND RESERVE DATA
The following estimates of net proved oil and natural gas reserves are
based on reports prepared by Miller and Lents, Ltd., independent petroleum
engineers, rolled forward by Encore to reflect reserve information as of
September 30, 2000. A summary of the Miller and Lents, Ltd. report on our proved
reserves as of June 30, 2000 is attached to this prospectus as Annex A. You
should refer to "Risk Factors", "Management's Discussion and Analysis of
Financial Condition and Results of Operations", "Business -- Proved Reserves",
"Business -- Production and Price History" and the Miller and Lents, Ltd. report
included in this prospectus in evaluating the material presented below. The
historical data are those of Encore and the pro forma data were prepared as if
the acquisition of oil and natural gas properties referred to as Cedar Creek
Anticline, Lodgepole, Crockett County and Indian Basin/Verden had taken place on
January 1, 1999 for production, price and cost data and on December 31, 1999 for
reserve data.
<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
---------------------------- ----------------------------
YEAR NINE MONTHS YEAR NINE MONTHS
ENDED ENDED ENDED ENDED
DECEMBER 31, SEPTEMBER 30, DECEMBER 31, SEPTEMBER 30,
1999(1) 2000 1999 2000
------------ ------------- ------------ -------------
<S> <C> <C> <C> <C>
PRODUCTION DATA(2):
Oil (MBbls)..................................... 1,996 3,191 5,056 3,450
Natural gas (MMcf).............................. 455 2,696 8,549 5,457
Combined volumes (MBOE)......................... 2,072 3,640 6,481 4,359
AVERAGE PRICES:(3)
Oil (per Bbl)................................... $ 15.26 $ 20.48 $ 13.48 $ 21.30
Natural gas (per Mcf)........................... 1.78 3.55 2.13 3.17
Combined volumes (per BOE)...................... 15.09 20.58 13.33 20.82
AVERAGE COSTS (PER BOE):
Lease Operating Expenses:
Direct lifting costs.......................... 4.06 3.40 2.98 3.33
Production, ad valorem and severance taxes.... 2.62 2.93 1.72 2.69
Depletion, depreciation and amortization........ 2.55 4.08 4.12 4.39
General and administrative...................... 1.95 1.06 .81 .88
</TABLE>
<TABLE>
<CAPTION>
AS OF AS OF AS OF AS OF
DECEMBER 31, SEPTEMBER 30, DECEMBER 31, SEPTEMBER 30,
1999 2000 1999 2000
------------ ------------- ------------ -------------
<S> <C> <C> <C> <C>
ESTIMATED PROVED RESERVES:
Oil (MBbls)..................................... 79,217 84,641 82,035 84,641
Natural gas (MMcf).............................. 12,502 67,496 70,479 67,496
Total MBOE...................................... 81,301 95,890 93,782 95,890
Percent proved developed........................ 84% 88% 85% 88%
PV-10 (in millions)(4).......................... $ 323.3 $ 611.1 $ 426.7 $ 611.1
Standardized measure(5)......................... 259.0 448.5 353.8 448.5
R/P Index (in years)(6)......................... 22.9 19.8 14.5 16.5
</TABLE>
---------------
(1) In the year ended December 31, 1999, the Company commenced production June
1, 1999.
(2) Production of natural gas liquids is included in natural gas revenues and
production.
(3)Includes the effects of net profits interest expense and hedging
transactions.
(4) The pretax present value of estimated future revenues to be generated from
the production of proved reserves calculated in accordance with SEC
guidelines, net of estimated production and future development costs, using
prices and costs as of the date of estimation without future escalation,
without giving effect to hedging activities, non-property related expenses
such as general and administrative expenses, debt service and depreciation,
depletion and amortization, and discounted using an annual discount rate of
10%. Giving effect to hedging transactions based on prices current at such
dates, our PV-10 value would have been $318.3 million at December 31, 1999
(historical), $421.7 million at December 31, 1999 (pro forma), and $584.6
million at September 30, 2000 (historical and pro forma).
(5) Future cash inflows from proved oil and natural gas reserves, less future
development and production costs and future income tax expenses, discounted
at 10% per annum to reflect the timing of future cash flows. Standardized
measure differs from PV-10 because standardized measure includes the effect
of future income taxes.
(6) As of December 31, 1999, calculated by dividing year-end proved reserves by
annual production for the period. As of September 30, 2000, calculated by
dividing September 30, 2000 proved reserves by annualized first three
quarters 2000 production.
7
<PAGE> 11
RISK FACTORS
Our material risks are described below. You should carefully consider these
risks before purchasing our common stock. If any of the following risks actually
occur, our business, financial condition or results of operations could be
materially adversely affected, the trading price of our common stock could
decline and you may lose all or part of your investment.
RISKS RELATING TO OUR BUSINESS
OIL AND NATURAL GAS PRICES ARE VOLATILE AND SUSTAINED PERIODS OF LOW PRICES
COULD REDUCE OR ELIMINATE OUR NET INCOME AND REDUCE OUR FINANCIAL FLEXIBILITY.
Average NYMEX oil and natural gas prices for September 2000 were $33.87 per
Bbl and $5.10 per Mcf, as compared to $25.60 per Bbl and $2.31 per Mcf for
December 1999. Our revenues, profitability and future growth and the book
carrying value of our properties depend substantially on prevailing oil and
natural gas prices. Prices also affect the amount of internally generated cash
flow available for capital expenditures and our ability to borrow and raise
additional capital. The amount we will be able to borrow under our current
credit facility will be subject to periodic redetermination based in part on
changing expectations of future prices. Lower prices may also reduce the amount
of oil and natural gas that we can economically produce.
Historically, the markets for oil and natural gas have been volatile and
are likely to continue to be volatile in the future. Among the factors that can
cause volatility are:
- the domestic and foreign supply of oil and natural gas;
- the ability of members of the Organization of Petroleum Exporting
Countries to agree upon and maintain oil prices and production levels;
- political instability or armed conflict in oil or natural gas producing
regions;
- the level of consumer product demand;
- weather conditions;
- the price and availability of alternative fuels;
- domestic political developments; and
- worldwide economic conditions.
These external factors and the volatile nature of the energy markets make
it difficult to estimate reliably future prices of oil and natural gas.
A SIGNIFICANT COMPONENT OF OUR GROWTH STRATEGY IS ACQUISITIONS, AND OUR FAILURE
TO COMPLETE FUTURE ACQUISITIONS SUCCESSFULLY COULD REDUCE OUR EARNINGS AND SLOW
OUR GROWTH.
Our business strategy has emphasized growth through strategic acquisitions,
but we may not be able to continue to identify properties for acquisition or we
may not be able to make acquisitions on terms that we consider economically
acceptable. There is intense competition for acquisition opportunities in our
industry. Competition for acquisitions may increase the cost of, or cause us to
refrain from, completing acquisitions. Our strategy of completing acquisitions
is dependent upon, among other things, our ability to obtain debt and equity
financing and, in some cases, regulatory approvals. Our ability to pursue our
growth strategy may be hindered if we are not able to obtain financing or
regulatory approvals. Our ability to grow through acquisitions and manage growth
will require us to continue to invest in operational, financial and management
information systems and to attract, retain, motivate and effectively manage our
employees. The
8
<PAGE> 12
inability to manage the integration of acquisitions effectively could reduce our
focus on subsequent acquisitions and current operations, which, in turn, could
negatively impact our earnings and growth. Our financial position and results of
operations may fluctuate significantly from period to period, based on whether
or not significant acquisitions are completed in particular periods.
We constantly evaluate acquisition opportunities and frequently engage in
bidding and negotiation for acquisitions, many of which are of substantial size
and value. If successful in this process, we may be required to alter or
increase substantially our capitalization to finance these acquisitions through
the use of cash on hand, issuance of additional debt or equity securities, the
sale of production payments, borrowing of additional funds or otherwise. The
acquisition of properties that are substantially different in operating or
geologic characteristics or geographic locations from our existing properties
could change the nature of our operations and business. While we intend to
concentrate on acquiring producing properties with development and exploitation
potential located in our current areas of operation, we may decide to acquire
properties located in other geographic regions. If we are not successful in
identifying or acquiring any material property interests, our earnings could be
reduced and our growth could be restricted.
BECAUSE A SUBSTANTIAL PORTION OF OUR PRODUCING PROPERTIES ARE LOCATED IN THE
WILLISTON BASIN, WE ARE VULNERABLE TO RISKS ASSOCIATED WITH OPERATING IN ONE
MAJOR GEOGRAPHIC AREA.
We have extensive operations in the Williston Basin, particularly our Cedar
Creek Anticline properties, which represented approximately 72% of our PV-10
reserve value at September 30, 2000. Any circumstance or event that negatively
impacts production or marketing of oil and natural gas in that geographic area
could reduce our earnings and cash flow.
OUR USE OF HEDGING ARRANGEMENTS COULD RESULT IN FINANCIAL LOSSES OR REDUCE OUR
INCOME.
To reduce our exposure to fluctuations in the prices of oil and natural
gas, we currently and may in the future enter into hedging arrangements for a
portion of our oil and natural gas production. Hedging arrangements for a
portion of our oil and natural gas production expose us to risk of financial
loss in some circumstances, including when:
- production is less than expected;
- the counter-party to the hedging contract defaults on its contract
obligations; or
- there is a change in the expected differential between the underlying
price in the hedging agreement and actual prices received.
In addition, these hedging arrangements may limit the benefit we would
receive from increases in the prices for oil and natural gas. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operation -- Qualitative and Quantitative Disclosures about Market
Risk -- Commodity Price Sensitivity".
OUR LIMITED OPERATING HISTORY MAKES IT DIFFICULT TO PREDICT OUR FUTURE
PERFORMANCE.
We were recently organized and our lack of operating history makes it
difficult to predict our future performance.
DRILLING OIL AND NATURAL GAS WELLS IS A HIGH-RISK ACTIVITY AND SUBJECTS US TO A
VARIETY OF FACTORS THAT WE CANNOT CONTROL.
Drilling oil and natural gas wells, including development wells, involves
numerous risks, including the risk that no commercially productive oil or
natural gas reservoirs will be encountered. In addition, we often are uncertain
as to the future cost or timing of drilling,
9
<PAGE> 13
completing and producing wells. Further, our drilling operations may be
curtailed, delayed or canceled as a result of a variety of factors, including:
- unexpected drilling conditions;
- pressure or irregularities in formations;
- equipment failures or accidents;
- adverse weather conditions;
- compliance with environmental and other governmental requirements, which
may increase our costs or restrict our activities (see "Regulatory
Matters"); and
- cost of, or shortages or delays in the availability of, drilling rigs and
equipment.
THE FAILURE TO REPLACE OUR RESERVES COULD ADVERSELY AFFECT OUR FINANCIAL
CONDITION.
In general, the volume of production from oil and natural gas properties
declines as reserves are depleted. If we fail to replace our reserves, our
financial assets and annual revenues would decline unless prices substantially
increase. Except to the extent that we acquire properties containing proved
reserves or conduct successful development and exploitation activities, our
proved reserves will decline as reserves are produced. Our future oil and
natural gas production is, therefore, highly dependent upon our success in
developing our producing properties and finding or acquiring additional reserves
at attractive rates of return. In order to increase reserves and production, we
must continue development drilling and recompletion programs, or undertake other
replacement activities. Our current strategy includes increasing our reserve
base by continuing to develop and exploit our existing properties and by
acquiring producing properties. Our planned development and exploitation
projects and acquisition activities may not result in significant additional
reserves, and we may not have success in drilling productive wells at favorable
finding costs.
RESERVE ESTIMATES DEPEND ON MANY ASSUMPTIONS THAT MAY TURN OUT TO BE INACCURATE.
ANY MATERIAL INACCURACIES IN OUR RESERVE ESTIMATES OR UNDERLYING ASSUMPTIONS
COULD CAUSE THE QUANTITIES AND NET PRESENT VALUE OF OUR RESERVES TO BE
OVERSTATED.
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors that are beyond our control. The reserve
information set forth in this prospectus represents estimates based on reports
prepared by independent petroleum engineers. Petroleum engineering is not an
exact science. Estimates of economically recoverable oil and natural gas
reserves and of future net cash flows necessarily depend upon a number of
variable factors and assumptions, any of which may cause these estimates to vary
considerably from actual results, such as:
- historical production from the area compared with production rates from
other producing areas;
- the assumed effect of governmental regulation; and
- assumptions about future commodity prices, production costs, severance
and excise taxes, capital expenditures and workover and remedial costs.
Estimates of reserves and expected future cash flows prepared by different
engineers (or by the same engineers at different times) may differ substantially
because of changes in relevant factors or the use of different assumptions.
Actual production, revenues and expenditures with respect to our reserves will
likely vary from estimates, and the variance may be material.
10
<PAGE> 14
WE HAVE LIMITED CONTROL OVER THE ACTIVITIES ON PROPERTIES WE DO NOT OPERATE.
While we operate our most important producing properties, other companies
operate some of the properties in which we have an interest. We have limited
ability to influence or control the operation or future development of these
non-operated properties. Our dependence on the operator and other working
interest owners for these projects and our limited ability to influence or
control the operation and future development of these properties could
materially adversely affect the realization of our targeted returns on capital
in drilling or acquisition activities. See "Business -- Operations".
OUR BUSINESS INVOLVES MANY OPERATING RISKS, WHICH MAY RESULT IN SUBSTANTIAL
LOSSES, AND INSURANCE MAY BE UNAVAILABLE OR INADEQUATE TO PROTECT US AGAINST
THESE RISKS.
Our operations are subject to hazards and risks inherent in drilling for,
producing and transporting oil and natural gas, such as:
- fires;
- natural disasters;
- explosions;
- formations with abnormal pressures;
- collapses of casing surrounding the drillpipe in wells;
- failure of oilfield drilling and service tools;
- uncontrollable flows of underground natural gas, oil and formation water;
- pressure forcing oil or natural gas out of the wellbore at a dangerous
velocity coupled with the potential for fire or explosion;
- changes in below ground pressure in a formation that causes the surface
to collapse or crater;
- pipeline ruptures or cement failures;
- environmental hazards such as natural gas leaks, oil spills and
discharges of toxic gases; and
- weather.
Any of these risks can cause substantial losses resulting from:
- injury or loss of life;
- damage to and destruction of property, natural resources and equipment;
- pollution and other environmental damage;
- regulatory investigations and penalties;
- suspension of our operations; and
- repair and remediation costs.
As protection against operating hazards, we maintain insurance coverage
against some, but not all, potential losses. We do not maintain insurance
against the loss of oil or natural gas reserves as a result of operating hazards
or business interruption insurance. Losses could occur for uninsurable or
uninsured risks, or in amounts in excess of existing insurance coverage. The
occurrence of an event that is not fully covered by insurance could harm our
financial condition and results of operations.
11
<PAGE> 15
OUR DEVELOPMENT AND EXPLOITATION OPERATIONS REQUIRE SUBSTANTIAL CAPITAL, AND WE
MAY BE UNABLE TO OBTAIN NEEDED FINANCING ON SATISFACTORY TERMS.
We make and will continue to make substantial capital expenditures in
development and exploitation projects. We intend to finance these capital
expenditures with cash flow from operations and our existing financing
arrangements. Additional financing sources may be required in the future to fund
our developmental drilling. Financing may not continue to be available under
existing or new financing arrangements, or on acceptable terms, if at all. If
additional capital resources are not available, we may be forced to curtail our
drilling and other activities or be forced to sell some of our assets on an
untimely or unfavorable basis.
THE LOSS OF OUR CHIEF EXECUTIVE OFFICER OR OTHER KEY PERSONNEL COULD ADVERSELY
AFFECT OUR BUSINESS.
We depend to a large extent on the efforts and continued employment of I.
Jon Brumley, our chief executive officer and chairman, and other key personnel.
The loss of the services of Mr. Brumley or other key personnel could adversely
affect our business, and we do not have employment agreements with, and do not
maintain key man insurance on the lives of, any of these persons. In addition,
it is a default under our credit agreement if Mr. Brumley ceases to be actively
employed on a full time basis as the chief executive officer of Encore.
THE MARKETABILITY OF OUR PRODUCTION IS DEPENDENT UPON TRANSPORTATION FACILITIES
OVER WHICH WE HAVE NO CONTROL.
The marketability of our production depends in part upon the availability,
proximity and capacity of pipelines, natural gas gathering systems and
processing facilities. Any significant change in market factors affecting these
infrastructure facilities could harm our business. We deliver oil and natural
gas through gathering systems and pipelines that we do not own. These facilities
may not be available to us in the future.
COMPETITION IN THE OIL AND NATURAL GAS INDUSTRY IS INTENSE, AND MANY OF OUR
COMPETITORS HAVE GREATER FINANCIAL, TECHNOLOGICAL AND OTHER RESOURCES THAN WE
DO.
We operate in the highly competitive areas of oil and natural gas
acquisition, development, exploitation and production. The oil and natural gas
industry is characterized by rapid and significant technological advancements
and introductions of new products and services using new technologies. We face
intense competition from independent, technology-driven companies as well as
from both major and other independent oil and natural gas companies in each of
the following areas:
- seeking to acquire desirable producing properties or new leases for
future exploration;
- marketing our oil and natural gas production;
- integrating new technologies; and
- seeking to acquire the equipment and expertise necessary to develop and
operate our properties.
Many of our competitors have financial, technological and other resources
substantially greater than ours. These companies may be able to pay more for
development prospects and productive oil and natural gas properties and may be
able to define, evaluate, bid for and purchase a greater number of properties
and prospects than our financial or human resources permit. Further, these
companies may enjoy technological advantages and may be able to implement new
technologies more rapidly than we can. Our ability to develop and exploit our
oil and natural gas properties and to acquire additional properties in the
future will depend upon our
12
<PAGE> 16
ability to successfully conduct operations, implement advanced technologies,
evaluate and select suitable properties and consummate transactions in this
highly competitive environment.
WE ARE SUBJECT TO COMPLEX FEDERAL, STATE, PROVINCIAL AND LOCAL LAWS AND
REGULATIONS THAT COULD ADVERSELY AFFECT OUR BUSINESS.
Exploration for and development, exploitation, production and sale of oil
and natural gas in North America are subject to extensive Federal, state,
provincial and local laws and regulations, including complex tax laws and
environmental laws and regulations. See "Regulatory Matters". These laws and
their interpretation are subject to change, the effects of which cannot be
predicted. Existing laws or regulations, as currently interpreted or
reinterpreted in the future, or future laws or regulations could harm our
business, results of operations and financial condition. We may be required to
make large expenditures to comply with environmental and other governmental
regulations. Matters subject to regulation include:
- discharge permits for drilling operations;
- drilling bonds;
- spacing of wells;
- unitization and pooling of properties;
- environmental protection;
- reports concerning operations; and
- taxation.
Under these laws and regulations, we could be liable for:
- personal injuries;
- property damage;
- oil spills;
- discharge of hazardous materials;
- reclamation costs;
- remediation and clean-up costs; and
- other environmental damages.
We do not believe that full insurance coverage for all potential
environmental damages is available at a reasonable cost. Failure to comply with
these laws and regulations also may result in the suspension or termination of
our operations and subject us to administrative, civil and criminal penalties.
Further, these laws and regulations could change in ways that substantially
increase our costs. Any of these liabilities, penalties, suspensions,
terminations or regulatory changes could make it more expensive for us to
conduct our business or cause us to limit or curtail some of our operations.
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<PAGE> 17
RISKS RELATING TO THIS OFFERING
OUR PRINCIPAL STOCKHOLDERS OWN ENOUGH OF OUR COMMON STOCK TO GIVE THEM CONTROL
OVER OUR CORPORATE POLICY AND MAJOR TRANSACTIONS.
Upon completion of this offering, Chase Venture Capital Associates, LLC,
Warburg, Pincus Equity Partners, L.P., Natural Gas Partners V, L.P., First Union
Capital Partners, Inc., and Mr. I. Jon Brumley, our principal stockholders, will
beneficially own approximately 72% of our outstanding common stock
(approximately 69% if the underwriters exercise their over-allotment option in
full). Accordingly, these stockholders, acting together, will be able to control
the outcome of stockholder votes, including votes concerning the election of
directors, the adoption or amendment of provisions in our certificate of
incorporation or bylaws and the approval of mergers and other significant
corporate transactions. This concentrated ownership makes it unlikely that any
other holder or group of holders of common stock will be able to affect the way
we are managed or the direction of our business. These factors may also delay or
prevent a change in our management or voting control.
Furthermore, conflicts of interest could arise in the future between
Encore, on the one hand, and Chase Venture Capital Associates, LLC, Warburg,
Pincus Equity Partners, L.P., Natural Gas Partners V, L.P. or First Union
Capital Partners, Inc., on the other hand, concerning, among other things,
potential competitive business activities or business opportunities. None of
Chase Venture Capital Associates, LLC, Warburg, Pincus Equity Partners, L.P.,
Natural Gas Partners V, L.P. or First Union Capital Partners, Inc., are
restricted from competitive oil and natural gas exploration and production
activities or investments. The interest of Chase Venture Capital Associates,
LLC, Warburg, Pincus Equity Partners, L.P., Natural Gas Partners, V. L.P. or
First Union Capital Partners, Inc., all of which currently have significant
equity interests in other public and private oil and natural gas companies,
could differ from those of our other stockholders.
WE HAVE NOT PAID DIVIDENDS AND DO NOT ANTICIPATE PAYING ANY DIVIDENDS ON OUR
COMMON STOCK IN THE FORESEEABLE FUTURE.
We anticipate that we will retain all future earnings and other cash
resources for the future operation and development of our business. Accordingly,
we do not intend to declare or pay any cash dividends in the foreseeable future.
Payment of any future dividends will be at the discretion of our Board of
Directors after taking into account many factors, including our operating
results, financial condition, current and anticipated cash needs and plans for
expansion. The declaration and payment of dividends is restricted by our
existing credit agreement, and any future dividends also may be restricted by
future agreements with our lenders.
OUR BOARD OF DIRECTORS CAN AUTHORIZE THE ISSUANCE OF PREFERRED STOCK THAT COULD
DIMINISH THE RIGHTS OF OUR COMMON STOCKHOLDERS, AND MAKE A CHANGE OF CONTROL
MORE DIFFICULT.
Our Board of Directors is authorized to issue shares of preferred stock in
one or more series, and to fix the voting powers, preferences and other rights
and limitations thereof. Accordingly, we may issue shares of preferred stock
with a preference over the common stock with respect to dividends or
distributions on liquidation or dissolution, or that may otherwise adversely
affect the voting or other rights of the holders of common stock. Issuance of
such preferred stock, depending upon the rights, preferences and designations
thereof, may have the effect of delaying, deterring or preventing a change in
control of Encore.
PURCHASERS IN THIS OFFERING WILL SUFFER IMMEDIATE AND SUBSTANTIAL DILUTION.
If you purchase common stock in this offering, you will experience
immediate and substantial dilution of $6.24 per share, based upon an assumed
initial public offering price of $14.00 per share, because the price you pay
will be substantially greater than the as adjusted net tangible book value per
share of $7.76 for the shares you acquire. This dilution is due in large part to
the
14
<PAGE> 18
fact that prior investors paid an average price of $5.35 per share when they
purchased their shares of common stock, which is substantially less than the
anticipated initial public offering price.
FUTURE SALES OF OUR COMMON STOCK BY OUR EXISTING STOCKHOLDERS MAY DEPRESS OUR
STOCK PRICE.
Sales of a substantial number of shares of our common stock in the public
market after this offering, or the perception that these sales may occur, could
cause the market price of our common stock to decline. See "Shares Available For
Future Sale". In addition, the sale of these shares could impair our ability to
raise capital through the sale of additional common or preferred stock.
After this offering, we will have 30,030,000 shares of common stock
outstanding. Of these shares, all shares sold in the offering, other than
shares, if any, purchased by our affiliates, will be freely tradable.
Substantially all of the original holders of our common stock are subject to
agreements that limit their ability to sell their common stock. These holders
cannot sell or otherwise dispose of any shares of common stock for a period of
at least 180 days after the date of this prospectus without the prior written
approval of Goldman, Sachs & Co., which could, in its sole discretion, elect to
permit resale of shares by existing stockholders prior to the lapse of the
180-day period.
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Our disclosure and analysis in this prospectus contain some forward-looking
statements. Forward-looking statements give our current expectations or
forecasts of future events. You can identify these statements by the fact that
they do not relate strictly to historical or current facts. These statements may
include words such as "anticipate", "estimate", "expect", "project", "intend",
"plan", "believe" and other words and terms of similar meaning in connection
with any discussion of future operating or financial performance. In particular,
these include, among other things, statements relating to:
- amount, nature and timing of capital expenditures;
- drilling of wells;
- timing and amount of future production of oil and natural gas;
- increases in proved reserves;
- operating costs and other expenses;
- cash flow and anticipated liquidity;
- prospect exploitation and property acquisitions; and
- marketing of oil and natural gas.
Any or all of our forward-looking statements in this prospectus may turn
out to be wrong. They can be affected by inaccurate assumptions we might make or
by known or unknown risks and uncertainties. Many factors mentioned in our
discussion in this prospectus, including the risks outlined under "Risk
Factors", will be important in determining future results. Actual future results
may vary materially. Factors that could cause our results to differ materially
from the results discussed in the forward-looking statements include the risks
described under "Risk Factors", including:
- the risks associated with operating in one major geographic area;
- the risks associated with exploitation and exploration;
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<PAGE> 19
- our ability to find, acquire, market, develop and produce new properties;
- oil and natural gas price volatility;
- uncertainties in the estimation of proved reserves and in the projection
of future rates of production and timing of exploitation expenditures;
- operating hazards attendant to the oil and natural gas business;
- drilling and completion risks that are generally not recoverable from
third parties or insurance;
- potential mechanical failure or underperformance of significant wells;
- climatic conditions;
- availability and cost of material and equipment;
- actions or inactions of third-party operators of our properties;
- our ability to find and retain skilled personnel;
- availability of capital;
- the strength and financial resources of our competitors;
- regulatory developments;
- environmental risks; and
- general economic conditions.
When you consider these forward-looking statements, you should keep in mind
these risk factors and the other cautionary statements in this prospectus.
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<PAGE> 20
USE OF PROCEEDS
We estimate that the net proceeds from our sale of 7,150,000 shares of
common stock will be approximately $92 million and will increase to
approximately $105.5 million if the underwriters exercise their over-allotment
option in full, assuming an initial public offering price of $14.00 per share
and after deducting underwriting discounts and commissions and estimated
offering expenses. We intend to use the net proceeds from the offering to repay
a portion of the debt under our existing credit agreement. We will have
approximately $69.0 million of indebtedness outstanding after application of the
net proceeds of the offering, including $51.0 million under our credit
agreement. See "Capitalization". We will use the increased borrowing capacity
under our credit agreement, along with internally generated cash flow, to pursue
an aggressive development program, along with exploitation and acquisition
activities and for general corporate purposes. We anticipate the need during
2001 to supplement internally generated cash flow with borrowed funds. Our
objective is to maintain a strong credit standing with our debt not to exceed
two times annual cash flow.
Our current credit agreement bears interest at a floating rate based on
three-month LIBOR, currently 5.68%, and matures in May 2004. For the nine months
ended September 30, 2000, the average interest rate on borrowings under the
credit agreement was approximately 7.7% per annum. All currently outstanding
indebtedness under our credit agreement, including amounts borrowed during the
past 12 months, was incurred to finance the acquisition of producing oil and
natural gas properties.
DIVIDEND POLICY
We have never declared or paid any cash dividends on our common stock. We
anticipate that we will retain all future earnings and other cash resources for
investment in our business. Accordingly, we do not intend to declare or pay cash
dividends in the foreseeable future. Payment of any future dividends will be at
the discretion of our Board of Directors after taking into account many factors,
including our financial condition, operating results, current and anticipated
cash needs and plans for expansion. In addition, our current credit agreement
provides that we may not pay any dividends, and our ability to declare and pay
any dividends may in the future be limited or restricted by agreements with our
future lenders.
RECAPITALIZATION
When Encore was organized in July 1998, we issued two classes of common
stock, Class A common stock and Class B common stock. The Class A stock, which
was issued to our management stockholders, represents approximately 20% of our
outstanding capital stock. The Class B stock, which was primarily issued to
institutional investors, represents 80% of our outstanding shares. Each of the
management stockholders also purchased Class B stock, and they collectively own
approximately 21.3% of our outstanding capital stock. The two classes are
identical in all respects, except that the purchase price per share for the
Class A shares was substantially less than for the Class B shares, and the Class
B shares are entitled to a preference in dividends and upon liquidation. Before
holders of Class A shares receive any dividends or liquidating distributions,
the holders of the Class B shares must receive as distributions an amount equal
to their total investment in Encore, plus a cumulative return of 7% per annum.
After the holders of the Class B Stock receive this preferential return, the
Class A and Class B Stock will share ratably in all subsequent distributions,
whether as dividends or upon liquidation. This capital structure was designed to
provide our management stockholders with a 20% interest in the incremental value
of Encore in excess of the amount necessary to permit our investor stockholders
to recover their investment together with a 7% return.
Immediately prior to this offering, our Class A and B shares will be
converted into one class of common stock. The conversion will allocate shares
between our management stockholders and investor stockholders on a basis that
gives effect to the Class B preferential return and the
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<PAGE> 21
Class A subordinated interest determined on the basis of Encore's valuation in
the public offering. The allocation will not affect the dilution to investors
and we do not believe it will otherwise adversely affect investors in this
offering.
Based on a public offering price of $14.00 per share, we estimate that the
Class A shares will be converted into 2,654,840 shares of common stock, or 11.6%
of the outstanding shares immediately prior to this offering, and the Class B
shares will be converted into 20,225,160 shares, or 88.4% of the outstanding
shares.
DILUTION
The net tangible book value of our common stock on September 30, 2000 was
approximately $6.16 per share of common stock, assuming the issuance of
22,880,000 shares of common stock in connection with the recapitalization of our
Class A and Class B common stock into one class designated as common stock. The
net tangible book value per share is determined by dividing our tangible net
worth, or tangible assets less total liabilities, by the total number of
outstanding shares of common stock. After giving effect to the sale of common
stock offered by this prospectus (at an assumed price of $14.00 per share) and
the receipt of the estimated net proceeds, after deducting underwriting
discounts and commissions and estimated offering expenses, our, as adjusted, net
tangible book value at September 30, 2000 would have been approximately $7.76
per share. This represents an immediate and substantial increase in the net
tangible book value of $1.60 per share to existing stockholders and an immediate
dilution, resulting from the difference between the initial public offering
price and the pro forma net tangible book value after this offering, to new
investors purchasing common stock in this offering. The following table
illustrates the per share dilution to new investors purchasing common stock in
this offering:
<TABLE>
<S> <C>
Public offering price per share............................ $14.00
------
Net tangible book value per share at September 30, 2000.... $ 6.16
------
Increase per share attributable to new investors........... $ 1.60
------
As adjusted net tangible book value per share after this
offering................................................. $ 7.76
------
Dilution per share to new investors........................ $ 6.24
======
</TABLE>
The following table sets forth, at September 30, 2000, the number of shares
of common stock purchased from us, assuming the recapitalization of all shares
of our Class A and Class B common stock into one class of common stock, the
total consideration and average price per share paid by existing stockholders
and by the new investors before deducting expenses payable by us:
<TABLE>
<CAPTION>
SHARES PURCHASED TOTAL CONSIDERATION AVERAGE
-------------------- ---------------------- PRICE
NUMBER PERCENT AMOUNT PERCENT PER SHARE
------ ------- ------ ------- ---------
<S> <C> <C> <C> <C> <C>
Existing
stockholders......... 22,880,000 76.19% $122,389,000 55.0% $ 5.35
New investors.......... 7,150,000 23.81% $100,100,000 45.0% $14.00
---------- ------ ------------ ----- ------
Total.................. 30,030,000 100.00% $222,489,000 100.0% $ 7.41
========== ====== ============ ===== ======
</TABLE>
If the underwriters' over-allotment option is exercised in full, the number
of shares held by new investors will be increased to 8,222,500, or approximately
26.44% of the total number of shares of common stock, assuming the
recapitalization of all shares of our Class A and Class B common stock into one
class of common stock.
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<PAGE> 22
CAPITALIZATION
The following table presents our capitalization as of September 30, 2000 on
two bases:
- on an actual basis; and
- on an adjusted basis giving effect to the recapitalization of all
outstanding shares of our Class A and Class B common stock into one class
of common stock immediately prior to this offering and to reflect our
anticipated use of the estimated net proceeds of this offering, assuming
an initial public offering price of $14.00 per share.
<TABLE>
<CAPTION>
SEPTEMBER 30, 2000
--------------------
AS
ACTUAL ADJUSTED
------ --------
(IN THOUSANDS)
<S> <C> <C>
Cash and equivalents........................................ $ 1,602 $ 1,602
========= ========
Long-term debt(1)........................................... 161,284 69,191
Stockholders' equity:
Common Stock, $.01 par value, 50,000,000 shares authorized,
30,030,000 issued and outstanding, as adjusted............ -- 300
Preferred stock, $.01 par value, 1,000 shares authorized
(5,000,000, as adjusted), none issued and outstanding..... -- --
Class A common stock, $.01 par value, 75,000 shares
authorized, 73,725 issued................................. 1
Class B common stock, $.01 par value, 300,000 shares
authorized, 294,901 issued................................ 3
Capital in excess of par value.............................. 298,247 214,553
Common stock subscription receivable(2)..................... (175,491) --
Notes receivable-officers and employees..................... (21) (21)
Retained earnings........................................... 18,102 18,102
--------- --------
Total stockholders' equity........................ 140,841 232,934
--------- --------
Total capitalization.............................. $ 302,125 $302,125
========= ========
</TABLE>
---------------
(1) Includes current portion of long-term debt. As of December 31, 2000,
long-term debt was $162.0 million. For a description of the credit agreement
and seller financed note, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources".
(2) Our existing stockholders have agreed to contribute additional capital for
their shares of Class A and Class B common stock upon call by Encore. Those
agreements are cancelable by the holders of 75% of our Class B Stock held by
investor stockholders and will be cancelled in connection with our
recapitalization immediately prior to this offering.
19
<PAGE> 23
PRO FORMA FINANCIAL STATEMENTS
UNAUDITED PRO FORMA FINANCIAL STATEMENTS
OF ENCORE ACQUISITION COMPANY
The following unaudited pro forma condensed consolidated balance sheet as
of September 30, 2000, and pro forma condensed consolidated statement of
operations for the year ended December 31, 1999 and the nine months ended
September 30, 2000, adjust the historical financial information of Encore
Acquisition Company to reflect the acquisitions of the Cedar Creek Anticline
properties on May 31, 1999, the Crockett County properties on March 31, 2000,
the Lodgepole properties on March 31, 2000, the Indian Basin/Verden properties
on September 1, 2000 and Other Cedar Creek properties in each of July and
October 1999. The pro forma statements of operations were prepared as if the
acquisitions were consummated on January 1, 1999. The pro forma adjustments are
explained in further detail in the accompanying notes.
The unaudited pro forma financial statements should be read in conjunction
with the accompanying notes and the historical financial statements and related
notes of Encore Acquisition Company and the historical statements of revenues
and direct operating expenses and related notes for the acquired properties,
each of which is included in this prospectus. The pro forma information
presented does not purport to be indicative of the financial position or results
of operations that would have actually occurred had the acquisitions been
consummated on the dates indicated or which may occur in the future.
20
<PAGE> 24
ENCORE ACQUISITION COMPANY
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1999
<TABLE>
<CAPTION>
OTHER INDIAN PRO
ENCORE CEDAR CEDAR CROCKETT BASIN/ PRO FORMA FORMA
HISTORICAL CREEK CREEK COUNTY LODGEPOLE VERDEN ADJUSTMENTS ENCORE
---------- ----- ----- -------- --------- ------ ----------- ------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Revenues:
Oil sales.................... $ 30,454 $13,885 $2,160(b) $ 867(b) $18,394(b) $2,377(b) $ -- $ 68,137
Natural gas sales............ 810 579 78(b) 8,310(b) 1,409(b) 7,056(b) -- 18,242
-------- ------- ------ ------ ------- ------ ----------- -----------
Total revenues......... 31,264 14,464(a) 2,238(b) 9,177(b) 19,803(b) 9,433(b) -- 86,379
-------- ------- ------ ------ ------- ------ ----------- -----------
Operating costs and expenses:
Direct lifting cost.......... 8,408 5,987(a) 781(b) 1,640(b) 252(b) 2,257(b) -- 19,325
Production, severance and ad
valorem tax................ 5,427 2,927(a) 277(b) 594(b) 994(b) 942(b) -- 11,161
General and administrative... 4,047 -- -- -- -- -- 1,234(c) 5,281
Depletion, depreciation and
amortization............... 5,283 -- -- -- -- -- 3,743(d) 26,692
17,666(e)
-------- ------- ------ ------ ------- ------ ----------- -----------
Total operating
expenses.............. 23,165 8,914 1,058 2,234 1,246 3,199 22,643 62,459
Income (loss) from
operations................... 8,099 5,550 1,180 6,943 18,557 6,234 (22,643) 23,920
-------- ------- ------ ------ ------- ------ ----------- -----------
Other income (expenses):
Interest expense............. (4,037) -- -- -- -- -- (2,403)(f) (11,043)
(4,603)(g)
Other........................ 202 -- -- -- -- -- -- 202
-------- ------- ------ ------ ------- ------ ----------- -----------
Total other income
(expenses)............ (3,835) -- -- -- -- -- (7,006) (10,841)
-------- ------- ------ ------ ------- ------ ----------- -----------
Income (loss) before income
taxes........................ 4,264 5,550 1,180 6,943 18,557 6,234 (29,649) 13,079
-------- ------- ------ ------ ------- ------ ----------- -----------
Benefit (provision) for income
taxes........................ (1,259) -- -- -- -- -- (3,399)(h) (4,658)
-------- ------- ------ ------ ------- ------ ----------- -----------
Net income (loss)............. $ 3,005 $ 5,550 $1,180 $6,943 $18,557 $6,234 $ (33,048) $ 8,421
======== ======= ====== ====== ======= ====== =========== ===========
Net income per common
share:....................... $ 8.20 $ .37
======== ===========
Weighted average number of
common shares outstanding:... 366,631 22,390,155(i) 22,756,786
======== =========== ===========
</TABLE>
The accompanying notes to the unaudited pro forma condensed consolidated
financial statements are an integral part of these statements.
21
<PAGE> 25
ENCORE ACQUISITION COMPANY
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
INDIAN PRO PRO
ENCORE CROCKETT BASIN/ FORMA FORMA
HISTORICAL COUNTY LODGEPOLE VERDEN ADJUSTMENTS ENCORE
---------- -------- --------- ------ ----------- ------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil sales...................... $ 65,345 $ 286(b) $6,367(b) $1,485 -- $ 73,483
Natural gas sales.............. 9,566 2,175(b) 306(b) 5,233 -- 17,280
-------- ------ ------ ------ ----------- -----------
Total revenues.......... 74,911 2,461(b) 6,673(b) 6,718 -- 90,763
-------- ------ ------ ------ ----------- -----------
Operating costs and expenses:
Direct lifting costs........... 12,373 406(b) 117(b) 1,609 -- 14,505
Production, severance and ad
valorem tax.................. 10,675 108(b) 320(b) 629 -- 11,732
General and administrative..... 3,845 -- -- -- -- 3,845
Depletion, depreciation and
amortization................. 14,856 -- -- -- 4,274(e) 19,130
-------- ------ ------ ------ ----------- -----------
Total operating
expenses.............. 41,749 514 437 2,238 4,274 49,212
-------- ------ ------ ------ ----------- -----------
Income (loss) from operations.... 33,162 1,947 6,236 4,480 (4,274) 41,551
-------- ------ ------ ------ ----------- -----------
Other income (expenses):
Interest expense............... (7,358) -- -- -- (1,359)(g) (8,717)
Other.......................... 416 -- -- -- -- 416
-------- ------ ------ ------ ----------- -----------
Total other income
(expenses)............ (6,942) -- -- -- (1,359) (8,301)
-------- ------ ------ ------ ----------- -----------
Income (loss) before income
taxes.......................... 26,220 1,947 6,236 4,480 (5,633) 33,250
-------- ------ ------ ------ ----------- -----------
Benefit (provision) for income
taxes.......................... (10,113) -- -- -- (2,711)(h) (12,824)
-------- ------ ------ ------ ----------- -----------
Net income (loss)................ $ 16,107 $1,947 $6,236 $4,480 $ (8,344) $ 20,426
======== ====== ====== ====== =========== ===========
Net income (loss) per common
share:......................... $ 43.88 $ .90
======== ===========
Weighted average number of common
shares outstanding:............ 367,070 22,416,965(i) 22,784,035
======== =========== ===========
</TABLE>
The accompanying notes to the unaudited pro forma condensed consolidated
financial statements are an integral part of these statements.
22
<PAGE> 26
ENCORE ACQUISITION COMPANY
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
ENCORE OFFERING AS
HISTORICAL ADJUSTMENTS ADJUSTED
---------- ----------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
BALANCE SHEET DATA:
Current assets........................................... $ 25,442 $ 25,442
Oil and natural gas properties, net...................... 298,633 298,633
Other property and equipment, net........................ 1,189 1,189
Other assets............................................. 6,370 6,370
-------- -------- --------
Total assets............................................. $331,634 $ 0 $331,634
======== ======== ========
Current liabilities...................................... $ 38,919 $ 38,919
Long-term debt........................................... 143,094 (92,093) 51,001
Deferred income taxes.................................... 8,780 8,780
Stockholders' equity..................................... 140,841 92,093 232,934
-------- -------- --------
Total liabilities and stockholders' equity............... $331,634 $ 0 $331,634
======== ======== ========
</TABLE>
The accompanying notes to the unaudited pro forma condensed consolidated
financial statements are an integral part of these statements.
23
<PAGE> 27
ENCORE ACQUISITION COMPANY
NOTES TO PRO FORMA CONDENSED CONSOLIDATED
STATEMENTS OF OPERATIONS
The accompanying Pro Forma Condensed Consolidated Statements of Operations
and Balance Sheet have been prepared to reflect certain adjustments to the
historical consolidated statement of operations of Encore.
(a) To record the revenues and expenses relating to the Cedar Creek Anticline
acquisition for the five months ended May 31, 1999 at historically reported
amounts. The initial Cedar Creek Anticline acquisition occurred on June 1,
1999. Subsequently, additional interests were acquired in July and October
1999 and are listed under "Other Cedar Creek" on the pro formas.
(b) To record the revenues and expenses relating to the Other Cedar Creek,
Crockett County, Lodgepole and Indian Basin/Verden acquisitions for the
year ended December 31, 1999 and the nine months ended September 30, 2000
at historically reported amounts.
(c) To record an estimated increase in general and administrative expenses
relating to the Cedar Creek Anticline acquisition for the five months ended
May 31, 1999 and for the Crockett County for the year ended December 31,
1999.
(d) To record depreciation, depletion and amortization relating to the Cedar
Creek Acquisition for the periods prior to the acquisition date of June 1,
1999.
(e) To record depreciation, depletion and amortization relating to the Crockett
County, Lodgepole and Indian Basin/Verden acquisitions for the periods
prior to the acquisition date of April 1, 2000 for Crockett County and
Lodgepole and September 1, 2000 for Indian Basin/Verden.
(f) To record the interest expense resulting from the increased borrowings
($95.0 million) related to the Cedar Creek acquisition for the periods
prior to the acquisition date of June 1, 1999. An interest rate of 7.2%,
which was the average rate incurred by Encore during the year ended
December 31, 1999, was used to calculate the pro forma adjustment. The pro
forma amount of $2.4 million results from the calculated amount of $6.4
million less the Encore historical reported amount of $4.0 million. Each
1/8% change in the interest rate would affect operations by $74,000 per
year.
(g) To record the interest expense resulting from the increased borrowings
relating to the Crockett County ($21.5 million), Lodgepole ($35.2 million)
and Indian Basin/Verden ($23.2 million) acquisitions for the periods prior
to the acquisition dates of April 1, 2000 for Crockett County and Lodgepole
and September 1, 2000 for Indian Basin/Verden. The average interest rate
used for Crockett County and Indian Basin/Verden was 7.6%, which was the
average rate incurred by Encore during the nine months ended September 30,
2000. The Lodgepole acquisition is financed with a note payable at a fixed
rate of 4%. Each 1/8% change in the interest rate on the variable rate
debt would affect operations by $35,000 per year.
(h) To record an estimated provision for income taxes for the change in income
before taxes resulting from inclusion of the historical results of
operations of the acquisitions and the related adjustments using a 35%
Federal statutory rate and a 3% state rate.
(i) To record the effect of the recapitalization on weighted average shares
outstanding.
24
<PAGE> 28
SUPPLEMENTAL INFORMATION TO PRO FORMA
OIL & NATURAL GAS PRODUCING ACTIVITIES
The estimates of Encore's proved oil and natural gas reserves, which are
located entirely within the United States, were prepared in accordance with
guidelines established by the SEC and the Financial Accounting Standards Board.
Proved oil and natural gas reserve quantities are based on estimates prepared by
Miller and Lents, Ltd., who are independent petroleum engineers, rolled forward
by Encore to reflect reserve information as of September 30, 2000.
Future prices received for production and future production costs may vary,
perhaps significantly from the prices and costs assumed for purposes of these
estimates. The proved reserves may not be developed within the periods
indicated, and prices and costs may not remain constant. Actual production may
not equal the estimated amounts used in the preparation of reserve projections.
In accordance with the SEC's guidelines, Encore's estimates of future net cash
flows from proved properties and the representative value thereof are made using
oil and natural gas prices in effect as of the dates of such estimates and are
held constant throughout the life of the properties. Average wellhead prices
used in estimating net cash flows at September 30, 2000 were $28.76 per barrel
for oil and $5.19 per Mcf for natural gas. The net profits interest on our Cedar
Creek Anticline properties has been deducted from future cash inflows in the
calculation of standardized measure. Encore's reserve quantities have not been
adjusted for the net profits interest. In addition, future net cash flows have
been adjusted for hedge positions outstanding at the end of the year. The future
cash flows are reduced by estimated production costs and development costs which
are based on year-end economic conditions and held constant throughout the life
of the properties.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. Oil and natural gas reserve engineering is and must be
recognized as a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in any exact way, and estimates of
other engineers might differ materially from those shown below. The accuracy of
any reserve estimate is a function of the quality of available data and
engineering and estimates may justify revisions. Accordingly, reserve estimates
are often materially different from the quantities of oil and natural gas that
are ultimately recovered. Reserve estimates are integral in management's
analysis of impairments of oil and natural gas properties and the calculation of
depreciation, depletion and amortization on its properties.
Estimated net quantities of proved oil and natural gas reserves of Encore
(in thousands) were as follows:
<TABLE>
<CAPTION>
NATURAL OIL
OIL GAS EQUIVALENT
(MBbl) (MMcf) (MBOE)
------ ------- ----------
<S> <C> <C> <C>
September 30, 2000
Proved reserves................................... 84,641 67,496 95,890
Proved developed reserves......................... 73,703 62,331 84,092
</TABLE>
25
<PAGE> 29
The changes in proved reserves (in thousands) were as follows for the
period ended:
<TABLE>
<CAPTION>
SEPTEMBER 30, 2000
-----------------------------
NATURAL OIL
OIL GAS EQUIVALENT
(MBbl) (MMcf) (MBOE)
------ ------- ----------
<S> <C> <C> <C>
Reserves at beginning of year............................... 79,217 12,502 81,301
Acquisitions of minerals-in-place........................... 3,010 56,902 12,494
Extensions and discoveries.................................. 1,559 191 1,591
Revisions of estimates...................................... 4,046 597 4,146
Production.................................................. (3,191) (2,696) (3,640)
------ ------ ------
Reserves at end of period................................... 84,641 67,496 95,890
====== ====== ======
</TABLE>
The standardized measure of discounted estimated future net cash flows and
changes therein related to proved oil and natural gas reserves (in thousands) is
as follows:
<TABLE>
<CAPTION>
SEPTEMBER 30, 2000
------------------
<S> <C>
Future cash inflows......................................... $2,424,052
Future production costs..................................... (978,081)
Future development costs.................................... (32,511)
Future income tax expense................................... (456,231)
----------
Future net cash flows....................................... 957,229
10% annual discount......................................... (508,772)
----------
Standardized measure of discounted estimated future net cash
flows..................................................... $ 448,457
==========
</TABLE>
Primary changes in the standardized measure of discounted estimated future
net cash flows (in thousands) are as follows for the period ended:
<TABLE>
<CAPTION>
SEPTEMBER 30, 2000
------------------
<S> <C>
Standardized measure, beginning of period................... $259,038
Net change in sales prices, net of production costs....... 77,799
Development costs incurred during the year................ 10,682
Revisions of quantity estimates........................... 21,679
Extensions, discoveries and improved recovery, net........ 11,553
Accretion of discount..................................... 32,326
Change in future development costs........................ --
Acquisitions of reserves-in-place......................... 194,266
Sales of reserves in place................................ --
Sales, net of production costs............................ (51,863)
Change in timing and other................................ (21,162)
Net change in income taxes................................ (85,861)
--------
Standardized measure, end of period......................... $448,457
========
</TABLE>
26
<PAGE> 30
SELECTED CONSOLIDATED FINANCIAL DATA
The following table presents summary consolidated historical financial data
for the years ended December 31, 1998 and 1999 and for the nine months ended
September 30, 1999 and 2000, in each case derived from the consolidated
financial statements of Encore Acquisition Company.
You should read the following data along with "Selected Consolidated
Financial Data", "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the consolidated financial statements and related
notes, each of which is included in this prospectus. You should also read the
pro forma information together with the unaudited pro forma combined financial
statements and related notes included in this prospectus.
<TABLE>
<CAPTION>
PERIOD FROM
INCEPTION NINE MONTHS
(APRIL 22, 1998) ENDED
THROUGH YEAR ENDED SEPTEMBER 30,
DECEMBER 31, DECEMBER 31, --------------------
1998 1999 1999 2000
---------------- ------------ ---- ----
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues.................................... $ -- $ 31,264 $ 16,268 $ 74,911
-------- --------- --------- --------
Operating expenses:
Direct lifting costs...................... -- 8,408 4,430 12,373
Production, ad valorem and severance
taxes................................... -- 5,427 2,824 10,675
General and administrative................ 1,066 4,047 2,511 3,845
Depletion, depreciation and
amortization............................ 18 5,283 2,966 14,856
-------- --------- --------- --------
Total operating expenses........... 1,084 23,165 12,731 41,749
-------- --------- --------- --------
Income (loss) from operations............... (1,084) 8,099 3,537 33,162
-------- --------- --------- --------
Other income (expenses):
Interest expense.......................... -- (4,037) (2,148) (7,358)
Other..................................... 74 202 129 416
-------- --------- --------- --------
Total other income (expense)....... 74 (3,835) (2,019) (6,942)
-------- --------- --------- --------
Income (loss) before income taxes........... (1,010) 4,264 1,518 26,220
Provision for income taxes.................. -- (1,259) (1,067) (10,113)
-------- --------- --------- --------
Net income (loss)........................... $ (1,010) $ 3,005 $ 451 $ 16,107
======== ========= ========= ========
Net income (loss) per common share:
Basic and diluted......................... $ (5.18) $ 8.20 $ 1.24 $ 43.88
Weighted average number of common shares
outstanding............................. 195,036 366,631 365,044 367,070
OTHER FINANCIAL DATA:
Adjusted EBITDA(1)........................ $ (1,066) $ 13,382 $ 6,503 $ 48,018
Net cash provided by (used in) operating
activities.............................. (949) 9,759 2,272 29,611
Net cash used in investing activities..... (289) (201,701) (196,983) (82,852)
Net cash provided by financing
activities.............................. 4,705 194,972 192,972 48,346
Capital expenditures(2)................... -- (6,883) (2,232) (22,431)
</TABLE>
---------------
(1) Adjusted EBITDA (as used herein) is defined as net income (loss) before
interest income and expense, income taxes, depletion, depreciation and
amortization. While Adjusted EBITDA should not be considered in isolation or
as a substitute for net income (loss), operating income (loss), cash flow
provided by operating activities or other income or cash flow data prepared
in accordance with generally accepted accounting principles or as an
indicator of a company's financial performance, we believe that it provides
additional information with respect to our ability to meet our future debt
service, capital expenditures and working capital requirements. When
evaluating Adjusted EBITDA, investors should consider, among other factors,
(i) increasing or decreasing trends in Adjusted EBITDA, (ii) whether
Adjusted EBITDA has remained at positive levels historically and (iii) how
Adjusted EBITDA compares to levels of interest expense. Because Adjusted
EBITDA excludes some, but not all, items that affect net income and may vary
among companies, the Adjusted EBITDA presented above may not be comparable
to similarly titled measures of other companies. While we believe that
Adjusted EBITDA may provide additional information with respect to our
ability to meet our future debt service, capital expenditures and working
capital requirements, certain functional or legal requirements of our
business may require us to utilize our available funds for other purposes.
(2) Capital expenditures for development and exploitation activities, excluding
acquisition expenditures.
27
<PAGE> 31
SELECTED CONSOLIDATED FINANCIAL DATA, CONTINUED
<TABLE>
<CAPTION>
AT DECEMBER 31, AT DECEMBER 31, AT SEPTEMBER 30, AT SEPTEMBER 30,
1998 1999 1999 2000
--------------- --------------- ---------------- ----------------
(UNAUDITED) (UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C>
BALANCE SHEET DATA:
Current assets............. $3,475 $ 17,766 $ 11,632 $ 25,442
Oil and natural gas
properties, net......... -- 195,585 193,241 298,633
Other property and
equipment, net.......... 271 1,080 1,036 1,189
Other assets............... 5 1,140 1,405 6,370
------ -------- -------- --------
Total assets....... $3,751 $215,571 $207,314 $331,634
====== ======== ======== ========
Current liabilities........ $ 56 $ 12,640 $ 9,129 $ 38,919
Long-term debt............. -- 99,250 97,250 143,094
Deferred income taxes...... -- 1,259 1,067 8,780
Stockholders' equity....... 3,695 102,422 99,868 140,841
------ -------- -------- --------
Total liabilities
and stockholders'
equity........... $3,751 $215,571 $207,314 $331,634
====== ======== ======== ========
</TABLE>
28
<PAGE> 32
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This prospectus contains forward-looking statements that involve risks and
uncertainties. See "Information Regarding Forward Looking Statements". Actual
results may differ materially from those anticipated in our forward looking
statements due to many factors, including, but not limited to, those set forth
under "Risk Factors". The following discussion should be read in conjunction
with "Selected Financial Data" and the financial statements and notes to those
statements included in this prospectus.
OVERVIEW
Because of our rapid growth through acquisitions since formation, our
historical results of operations and period-to-period comparisons of such
results and certain financial data may not be meaningful or indicative of future
results. Our acquisition history through September 30, 2000 is as follows:
<TABLE>
<CAPTION>
ASSET DATE ACQUIRED
----- -------------
<S> <C>
Cedar Creek Anticline(CCA)........................ June 1, 1999
Crockett County................................... March 30, 2000
Lodgepole......................................... March 31, 2000
Indian Basin/Verden............................... August 24, 2000
</TABLE>
We paid approximately $172.0 million to acquire the CCA properties. This
acquisition gave us operating control of the CCA with an average working
interest of approximately 78%. Subsequently, we acquired additional working
interests from various owners in July and October 1999 for a combined price of
approximately $22.2 million, which increased our average working interest to its
current level of approximately 86%. Our cumulative acquisition investment in the
CCA totals approximately $194.2 million. The CCA properties contributed
approximately $31.3 million to our revenues for the year ended December 31, 1999
and $16.3 million and $67.6 million for the nine months ended September 30, 1999
and 2000, respectively.
During June 1999, the first month of Encore's ownership of the CCA, the
properties produced 9,099 net BOE/D, which consisted of 8,767 Bbls of oil and
1,994 Mcf of natural gas, and produced 53,660 barrels of water per day. During
September 2000, fifteen months after the initial acquisition, the properties
produced 10,733 net BOE/D, which consisted of 10,322 Bbls of oil and 2,466 Mcf
of natural gas, and produced 65,506 barrels of water per day. Adjusted for the
additional acquired volumes, which represent 9% of the increase, Encore has
offset the natural field decline and increased production by an additional 9%.
This increase resulted from an aggressive surveillance and workover program
coupled with drilling additional wells.
We paid approximately $43.0 million to purchase the Crockett County
properties. We acquired additional working interests for $0.5 million subsequent
to the acquisition. Our combined investment in Crockett County equals
approximately $43.5 million. The Crockett County properties averaged 9,078 Mcf
of natural gas per day and 29 barrels of oil per day with negligible water in
September 2000 and contributed approximately $6.8 million to our revenues for
the nine months ended September 30, 2000.
We paid approximately $35.2 million for the Lodgepole property. Production
from the Lodgepole properties averaged 2,448 Bbls of oil, 1,266 Mcf of natural
gas and 593 barrels of water per day, representing a water cut of 19.5%, or
2,636 BOE/D in September 2000 and contributed approximately $14.1 million to our
revenues for the nine months ended September 30, 2000.
The Indian Basin/Verden properties were acquired for $25.4 million. The
Indian Basin assets are located in the Permian Basin of New Mexico and are 100%
non-operated and 95% natural
29
<PAGE> 33
gas. The Verden assets, located in the Anadarko Basin of Oklahoma, are 75%
non-operated and 90% natural gas. Encore's net production for the Indian
Basin/Verden properties is 8,280 Mcf/D and 170 Bbl/D in September 2000, and the
properties contributed approximately $1.3 million to our revenues for the nine
months ended September 30, 2000. The Verden properties produce negligible
volumes of water, and the Indian Basin properties produce 1,730 barrels of water
per day.
The average prices received by producers in all our core areas have risen
sharply in the third quarter 2000 compared to the third quarter 1999. The NYMEX
average price for West Texas Intermediate Crude ("WTI"), a benchmark crude, was
$31.58 per barrel for the third quarter 2000, compared to $21.72 for third
quarter 1999. Approximately $9.1 million of our increase in revenues for the
nine months ended September 30, 2000, as compared to the same period in 1999
resulted from increases in prevailing oil and natural gas prices, $47.9 million
resulted from acquisitions and the balance resulted from increased production
from existing properties. Significant decreases in product prices would
significantly reduce our revenues from existing properties.
We use the successful efforts method of accounting for our oil and natural
gas properties. Under this method, all development costs and acquisition costs
of proved properties are capitalized and amortized on a unit-of-production basis
over the remaining life of proved developed reserves or proved reserves, as
applicable. Exploration expenses, including geological and geophysical expenses
and lease rentals, are charged to expense as incurred.
RESULTS OF OPERATIONS
The following table sets forth operating information of Encore for the
periods presented.
<TABLE>
<CAPTION>
FOR THE NINE MONTHS ENDED
FOR THE YEAR SEPTEMBER 30,
ENDED ------------------------------
DECEMBER 31, INCREASE
1999 1999 2000 (DECREASE)
------------ ---- ---- ----------
<S> <C> <C> <C> <C>
Oil and natural gas revenues (in
thousands).............................. $31,264 $16,268 $74,911 $58,643
Direct lifting costs (in thousands)....... $ 8,408 $ 4,430 $12,373 $ 7,943
Production, ad valorem and severance taxes
(in thousands).......................... $ 5,427 $ 2,824 $10,675 $ 7,851
Daily production:
Oil volumes (Bbls)...................... 9,327 9,157 11,646 2,489
Natural gas volumes (Mcf)............... 2,127 2,072 9,840 7,768
Combined volumes (BOE).................. 9,681 9,502 13,286 3,784
Average prices:
Oil (per Bbl)........................... $ 15.26 $ 14.21 $ 20.48 $ 6.27
Natural gas (per Mcf)................... 1.78 1.56 3.55 1.99
Combined volumes (per BOE).............. 15.09 14.03 20.58 6.55
Average costs (per BOE):
Direct lifting costs.................... $ 4.06 $ 3.82 $ 3.40 $ (0.42)
Production, ad valorem and severance
taxes................................ 2.62 2.44 2.93 0.49
G&A..................................... 1.95 2.17 1.06 (1.11)
DD&A.................................... 2.55 2.56 4.08 1.52
</TABLE>
Average prices shown in the table are net of net profits interests and the
effects of hedging transactions. As a result of hedging transactions, oil and
natural gas revenues were reduced by
30
<PAGE> 34
$4.4 million in 1999. For the first nine months of 1999 and 2000, oil and
natural gas revenues were reduced by $1.7 million and $14.9 million,
respectively, as a result of hedging activities.
As a result of our net profits interest payments, oil and natural gas
revenues were reduced by $4.4 million in 1999. For the first nine months of 1999
and 2000, oil and natural gas revenues were reduced by $2.6 million and $9.5
million, respectively, as a result of our net profits interest payments.
We have not provided a detailed analysis of our operating history,
including any discussion comparing operating performance for 1999 to that of
1998, because we were not organized until 1998 and we did not operate any assets
until the CCA acquisition in June 1999. As a result, a comparison of 1999 to
1998 is not meaningful because it compares a period of operations to a period of
start-up activity with no meaningful operations. In addition to the table
provided above, financial information may be found under "Summary Consolidated
Historical and Pro Forma Financial Data" and "Consolidated Financial
Statements".
INTERIM PERIOD COMPARISON (NINE MONTHS 2000 VS NINE MONTHS 1999)
Set forth below is our comparison of operations during the nine months
ended September 30, 2000 with the same period of 1999. In reading the
comparison, you should remember that the 2000 period included nine months of
operations while the 1999 period included only four months of operating
activities. Accordingly, operations in the two accounting periods are not
directly comparable.
NINE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
1999
REVENUES. Oil and natural gas revenues of Encore for the nine months ended
September 30, 2000 increased as compared to the same period of 1999 by $58.6
million, from $16.3 million to $74.9 million. This increase resulted from the
additional five months of production from the Cedar Creek Anticline properties
acquired in June 1999, as well as the Crockett County and Lodgepole acquisitions
completed in April 2000. The Indian Basin/Verden acquisition includes one month
of production for 2000. Hedging transactions had the effect of reducing oil and
natural gas revenues by $14.8 million, or $4.07 per BOE, during the first nine
months of 2000 and decreasing oil and natural gas revenues by $1.7 million, or
$1.44 per BOE, during the first nine months of 1999. We have no hedges extending
beyond 2003. Net profits interest payments had the effect of reducing oil and
natural gas revenues by $9.5 million, or $2.62 per BOE, during the first nine
months of 2000 and decreasing oil and natural gas revenues by $2.6 million or
$2.26 per BOE, during the first nine months of 1999.
On a pro forma basis, Encore's revenues and production volumes for the nine
months ended September 30, 2000 would have been $90.8 million and 4.4 million
BOE.
DIRECT LIFTING COSTS. Direct lifting costs of Encore for the nine months
ended September 30, 2000 increased as compared to the same period of 1999 by
$8.0 million, from $4.4 million to $12.4 million. The increase in direct lifting
costs resulted from the Cedar Creek Anticline acquisition completed in June
1999, as well as the Crockett County, Lodgepole and Indian Basin/ Verden
acquisitions completed in 2000. On a per BOE basis, direct lifting costs
decreased from $3.82 to $3.40, primarily as a result of lower lifting costs
associated with our Lodgepole acquisition in April 2000.
On a pro forma basis, Encore's direct lifting costs for the nine months
ended September 30, 2000 would have been $14.5 million, or $3.33 per BOE.
PRODUCTION, AD VALOREM AND SEVERANCE TAXES. Production, ad valorem and
severance taxes for the nine months ended September 30, 2000 increased as
compared to the same period of 1999 by $7.9 million, from $2.8 million to $10.7
million. The increase in production, ad valorem and severance taxes resulted
from the Cedar Creek Anticline acquisition completed in June 1999,
31
<PAGE> 35
as well as the Crockett County, Lodgepole and Indian Basin/Verden acquisitions
completed in 2000. As a percent of oil and natural gas revenues (excluding the
effects of hedges), production, ad valorem and severance taxes decreased from
15.7 % to 11.9%. The decrease in production, ad valorem and severance taxes as a
percent of revenue was a result of the higher production, ad valorem and
severance tax rate in Montana associated with our Cedar Creek Anticline asset
versus the tax rates in Texas and North Dakota associated with our Crockett
County and Lodgepole assets, respectively.
On a pro forma basis, Encore's production, ad valorem and severance taxes
for the nine months ended September 30, 2000 would have been $11.7 million, or
$2.69 per BOE.
DEPLETION, DEPRECIATION AND AMORTIZATION (DD&A) EXPENSE. DD&A expense
increased by $11.9 million, during the nine months ended September 30, 2000 from
$3.0 million to $14.9 million as compared to the same period of 1999. The
increase in DD&A resulted from the Cedar Creek Anticline acquisition completed
in June 1999, as well as the Crockett County, Lodgepole and Indian Basin/Verden
acquisitions completed in 2000. The average DD&A rate of $4.08 per BOE of
production during the first nine months of 2000 represents an increase of $1.52
per BOE from the $2.55 per BOE recorded in the first nine months of 1999. The
increase was attributable to higher per BOE acquisition costs associated with
the Crockett County, Lodgepole and Indian Basin/Verden acquisitions completed in
2000.
On a pro forma basis, Encore's DD&A for the nine months ended September 30,
2000 would have been $19.1 million, or $4.38 per BOE.
GENERAL AND ADMINISTRATIVE (G&A) EXPENSE. G&A expense increased $1.3
million, during the nine months ended September 30, 2000, from $2.5 million to
$3.8 million as compared to the same period of 1999. The increase in G&A
resulted from the additional staff and lease space necessary for the Cedar Creek
Anticline acquisition completed in June 1999, as well as the Crockett County,
Lodgepole and Indian Basin/Verden acquisitions completed in 2000. In addition,
Encore incurred $.8 million of compensation expense in the 2000 period relating
to the issuance of capital stock to employees. On a BOE basis, G&A expense fell
to $1.06 during the first nine months of 2000 from $2.17 during the first nine
months of 1999.
On a pro forma basis, Encore's G&A for the nine months ended September 30,
2000 would have been $3.0 million, or $0.88 per BOE.
The Company has calculated approximately $2.1 million of non-cash
compensation expense related to common shares issued to management, of which $.8
million has been recorded through September 30, 2000. Encore will record the
remaining compensation expense in general administrative expenses upon
successful completion of the initial public offering. This compensation expense
will be recorded over the vesting of the class A shares. Upon completion of the
recapitalization, all shares will be fully vested.
INTEREST EXPENSE. Interest expense for the nine months ended September 30,
2000 was $7.4 million compared to a $2.1 million for the nine months ended
September 30, 1999. The increase in interest expense resulted from the
additional borrowing necessary under Encore's credit agreement for the Cedar
Creek Anticline acquisition completed in June 1999, as well as the Crockett
County acquisition completed in April 2000 and the Indian Basin/Verden
acquisition completed in August 2000. Additional interest expense during the
first nine months of 2000 resulted from a seller financed note from Burlington
Resources Oil & Gas. The note requires monthly principal payments and 4%
interest on the outstanding principal paid at maturity of the note in January
2002.
On a pro forma basis, Encore's interest expense for the nine months ended
September 30, 2000 would have been $8.7 million, or $2.00 per BOE.
LIQUIDITY AND CAPITAL RESOURCES
Principal uses of capital have been for the acquisition and development of
oil and natural gas properties.
32
<PAGE> 36
During the nine months ended September 30, 2000, net cash provided by
operations was $29.6 million, an increase of $27.4 million compared to the nine
months ended September 30, 1999. We anticipate that our capital expenditures
will total approximately $11 million for the fourth quarter of 2000. The level
of these and other future expenditures is largely discretionary, and the amount
of funds devoted to any particular activity may increase or decrease
significantly, depending on available opportunities and market conditions. We
plan to finance our ongoing development and acquisition expenditures using
internally generated cash flow, available cash and our existing credit
agreement.
At September 30, 2000, Encore had total assets of $331.6 million. Total
capitalization was $302.1 million, of which 46.6% was represented by
stockholders' equity and 53.4% by senior debt.
Encore's operating subsidiary currently maintains a credit agreement with a
group of banks that matures in May 2004. Encore has guaranteed the subsidiary's
obligations under the credit agreement and has pledged the stock and other
equity interests of its subsidiaries to secure the guaranty. Borrowings under
the credit agreement totaled $138.5 million as of September 30, 2000. The
borrowing base, as established in the credit agreement, was $180.0 million as of
September 30, 2000. During the nine months ended September 30, 2000, the average
interest rate under the facility was 7.6 percent. The remaining borrowing base
available under the credit agreement at December 31, 2000, was $35.5 million.
Encore pays certain fees based on the unused portion of the borrowing base.
The credit agreement contains a number of negative and financial covenants.
Encore was in compliance with all of them as of December 31, 2000. The most
important of these covenants are:
- a prohibition against incurring debt in excess of $6,000,000, except for
borrowings under the credit agreement and the seller financing note
described below;
- a prohibition against paying dividends or purchasing or redeeming capital
stock;
- a restriction on creating liens on Encore's assets;
- restrictions on merging and selling assets outside the ordinary course of
business;
- restrictions on investments, transactions with affiliates, changing
Encore's principal business and incurring funding obligations under
ERISA;
- a provision limiting oil and natural gas hedging transactions to a volume
not exceeding 75% of anticipated production from proved reserves; and
- a requirement that Encore maintain a ratio of consolidated current assets
to consolidated current liabilities of not less than 1.0 to 1.0.
Encore issued a $35.2 million note payable to the seller in connection with
the Lodgepole acquisition in North Dakota. The note requires monthly principal
payments over the 22 month period ending January 31, 2002. The note bears
monthly compounded interest at the rate of 4% per annum on the outstanding
principal plus accrued interest and is payable at maturity in January 2002.
Principal payments through September 30, 2000 totaled $12.4 million. Principal
payments during the last quarter of 2000 equal $5.2 million. Principal payments
for the year ending December 31, 2001 will total $16.4 million. The remaining
amount will total $1.1 million and will be paid in January 2002. Burlington may
demand payment at any time, within 45 days notice, of all remaining principal
and interest outstanding less a demand premium. In the case Burlington elects to
demand payment, our credit agreement allows us additional borrowings to meet the
demand payment.
Encore believes that its capital resources are adequate to meet the
requirements of its business. Based on our anticipated capital investment
programs, we expect to spend
33
<PAGE> 37
approximately 50% of our internally generated cash flow to replace production
through developing and exploiting our core properties. Additional capital may be
required to pursue acquisitions and longer term capital projects, such as our
proposed CO(2) tertiary recovery project in the CCA, to increase our reserve
base. Substantially all of these expenditures are discretionary and will be
undertaken only if funds are available and the projected rates of return are
satisfactory. Future cash flows are subject to a number of variables including
the level of oil and natural gas production and prices. Operations and other
capital resources may not provide cash in sufficient amounts to maintain planned
levels of capital expenditures.
INFLATION AND CHANGES IN PRICES
While the general level of inflation affects certain of our costs, factors
unique to the petroleum industry result in independent price fluctuations.
Historically, significant fluctuations have occurred in oil and natural gas
prices. In addition, changing prices often cause costs of equipment and supplies
to vary as industry activity levels increase and decrease to reflect perceptions
of future price levels. Although it is difficult to estimate future prices of
oil and natural gas, price fluctuations have had, and will continue to have, a
material effect on us.
The following table indicates the average oil and natural gas prices
received for the year ended December 31, 1999 and nine months ended September
30, 2000. Average equivalent prices for 1999 and 2000 were decreased by $2.13
and $4.08 per BOE, respectively, as a result of our hedging activities. Average
prices per equivalent barrel indicate the composite impact of changes in oil and
natural gas prices. Natural gas production is converted to oil equivalents at
the conversion rate of six Mcf per Bbl. Average prices shown in the following
table are net of net profit interests.
<TABLE>
<CAPTION>
OIL NATURAL GAS EQUIV. OIL
(per Bbl) (per Mcf) (per BOE)
--------- ----------- ----------
<S> <C> <C> <C>
NET PRICE REALIZATION WITH HEDGES
Nine months ended September 30, 2000................. $20.48 $3.55 $20.58
Year ended December 31, 1999......................... 15.26 1.78 15.09
AVERAGE WELLHEAD PRICE
Nine months ended September 30, 2000................. $24.76 $3.99 $24.66
Year ended December 31, 1999......................... 17.47 1.78 17.22
</TABLE>
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
HEDGING POLICY. We have adopted a formal hedging policy. The purpose of our
hedging program is to mitigate the negative effects of volatile commodity
prices. The hedging policy is set by the Chief Executive Officer with input from
the Chief Financial Officer and the Executive Vice President of Business
Development. Trades are executed by the Executive Vice President of Business
Development. The Treasury Department handles the administration functions, which
entail tracking existing trades, confirming new trades and conducting monthly
settlements. Our Accounting Department records the transaction in the financial
statements. We plan to continue in the normal course of business to hedge our
exposure to fluctuating commodity prices. These arrangements will not exceed 75%
of anticipated production from proved producing reserves. Our hedging policy
does not permit us to engage in hedging transactions for speculation for our own
account.
COUNTERPARTIES. Encore's counterparties to hedging contracts include Bank
of America, a commercial bank, J. Aron, a wholly-owned subsidiary of Goldman,
Sachs & Co. and a commodities trading firm, and Enron Corp., a public energy
marketing company. Approximately 48.0%, 39.6% and 12.4% of oil production hedged
is committed to Enron, Bank of America and J. Aron, respectively. Approximately
6% of Encore's hedged gas production is contracted with
34
<PAGE> 38
Bank of America and approximately 94% of Encore's hedged gas production is
contracted with Enron.
COMMODITY PRICE SENSITIVITY. The tables in this section provide the
information about derivative financial instruments to which we were a party as
of September 30, 2000 that are sensitive to changes in oil and natural gas
commodity prices. No instrument provides the option to roll the contract forward
rather than make or take delivery.
Encore hedges commodity price risk with swap contracts, put contracts and
collar contracts. Swap contracts provide a fixed price for a notional amount of
sales volumes. Put contracts provide a fixed floor price on a notional amount of
sales volumes while allowing full price participation if the relevant index
price closes above the floor price. Collar contracts provide a floor price for
Encore on a notional amount of sales volumes while allowing some additional
price participation if the relevant index price closes above the floor price. A
swaption is an option to enter into a swap in the future. While Encore does not
intend to terminate any of these arrangements, the unrealized mark-to-market
loss upon termination of outstanding commodity derivatives at September 30, 2000
was approximately $29.9 million.
OIL HEDGES AT SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
DAILY FLOOR DAILY CAP DAILY SWAP FAIR MARKET
FLOOR VOLUME PRICE CAP VOLUME PRICE SWAP VOLUME PRICE VALUE AT
PERIOD (Bbl) (per Bbl) (Bbl) (per Bbl) (Bbl) (per Bbl) SEPTEMBER 30, 2000
------ ------------ --------- ---------- --------- ----------- --------- ------------------
<S> <C> <C> <C> <C> <C> <C> <C>
4Q 2000.............. 3,500 $19.80 2,500 $21.77 4,000 $22.38 $ (5,695,131)
2001................. 4,000 $20.36 1,000 $22.03 3,000 $19.88 $(11,457,555)
2002................. 1,500 $21.97 -- $ -- 2,000 $17.97 $ (5,024,490)
</TABLE>
NATURAL GAS HEDGES AT SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
DAILY FLOOR DAILY CAP DAILY SWAP FAIR MARKET
FLOOR VOLUME PRICE CAP VOLUME PRICE SWAP VOLUME PRICE VALUE AT
(Mcf) (per Mcf) (Mcf) (per Mcf) (Mcf) (per Mcf) SEPTEMBER 30, 2000
------------ --------- ---------- --------- ----------- --------- ------------------
<S> <C> <C> <C> <C> <C> <C> <C>
4Q 2000.............. -- $ -- -- $ -- 11,000 $3.64 $(1,557,799)
2001................. 3,500 $3.00 -- $ -- 9,500 $3.09 $(4,945,808)
2002................. 5,000 $3.05 -- $ -- 3,500 $3.31 $ (752,983)
2003................. -- $ -- -- $ -- 2,500 $3.11 $ (425,650)
</TABLE>
OIL HEDGES SUBSEQUENT TO SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
DAILY FLOOR DAILY CAP DAILY SWAP FAIR MARKET
FLOOR VOLUME PRICE CAP VOLUME PRICE SWAP VOLUME PRICE VALUE AT
PERIOD (Bbl) (per Bbl) (Bbl) (per Bbl) (Bbl) (per Bbl) SEPTEMBER 30, 2000
------ ------------ --------- ---------- --------- ----------- --------- ------------------
<S> <C> <C> <C> <C> <C> <C> <C>
2001................. 250 $23.50 -- -- -- -- N/A
2002................. 500 $23.50 -- -- -- -- N/A
</TABLE>
NATURAL GAS HEDGES SUBSEQUENT TO SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
DAILY FLOOR DAILY CAP DAILY SWAP FAIR MARKET
FLOOR VOLUME PRICE CAP VOLUME PRICE SWAP VOLUME PRICE VALUE AT
(Mcf) (per Mcf) (Mcf) (per Mcf) (Mcf) (per Mcf) SEPTEMBER 30, 2000
------------ --------- ---------- --------- ----------- --------- ------------------
<S> <C> <C> <C> <C> <C> <C> <C>
2001................. 2,500 $3.50 -- $ -- -- -- N/A
2002................. 2,500 $3.00 2,500 $8.05 -- -- N/A
</TABLE>
For 2001, we have approximately 28% of our oil production placed in floors,
7% capped and 21% in swap agreements. In addition we have approximately 17% of
our natural gas placed in floors and 48% in swap agreements.
35
<PAGE> 39
INTEREST RATE SENSITIVITY. At September 30, 2000, Encore had long-term debt
of $161.3 million. Of this amount, $22.8 million bears interest at a fixed rate
of 4%. The remaining outstanding long-term debt of $138.5 million is under
Encore's credit agreement, which is subject to floating market rates of
interest. Borrowings under the credit agreement bear interest at a fluctuating
rate that is linked to LIBOR or the prime rate, at Encore's option. Any increase
in these rates can have an adverse impact on Encore's results of operations and
cash flow. Encore has entered into interest rate swap agreements to hedge the
impact of interest rate changes on a portion of its floating rate debt. As of
September 30, 2000, Encore had interest swaps as follows:
<TABLE>
<CAPTION>
HEDGE SUMMARY
--------------------------------------------------------------------------------------
FAIR MARKET
NOTIONAL LIBOR VALUE AT
SWAP AMOUNT START DATE END DATE SWAP RATE SEPTEMBER 30, 2000
----------- ---------- -------- --------- ------------------
<C> <S> <C> <C> <C>
$6,500,000.. October 1, 1999 September 30, 2002 6.16% $ 58,750
10,250,000... October 29, 1999 October 30, 2000 6.10% 13,204
41,000,000... September 1, 1999 August 31, 2002 6.23% 254,907
13,083,333... November 30, 1999 November 30, 2001 6.26% 52,581
10,750,000... March 31, 2000 March 31, 2005 7.20% (253,183)
----------- ---- ---------
$81,583,333... 6.35%(1) $ 126,259
=========== ==== =========
</TABLE>
---------------
(1) Weighted average interest rate.
ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities". SFAS No. 133
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or liability
measured at its fair value. It also requires that changes in the derivative's
fair value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement for fair value hedges or to be recorded in other comprehensive income
for cash flow hedges. SFAS No. 133 requires that a company must formally
document, designate and assess the effectiveness of transactions that receive
hedge accounting. SFAS No. 133 is effective for all fiscal quarters of fiscal
years beginning after June 15, 2000. We will adopt SFAS No. 133 as of January 1,
2000. However, SFAS No. 133 may increase volatility in earnings.
36
<PAGE> 40
BUSINESS
OUR COMPANY
Encore is a rapidly growing independent energy company engaged in the
acquisition, development, exploitation and marketing of North American oil and
natural gas reserves. Our oil and natural gas reserves are concentrated in
fields located in the Williston Basin of Montana and North Dakota, the Permian
Basin of Texas and New Mexico and the Anadarko Basin of Oklahoma. The following
table provides information on a pro forma basis regarding net production from
our oil and natural gas properties for September 2000 and our proved reserves at
September 30, 2000.
PROPERTIES -- PRINCIPAL AREAS OF OPERATIONS
<TABLE>
<CAPTION>
NET
PRODUCTION
FOR SEPTEMBER PROVED RESERVE QUANTITIES PV-10
2000 AT SEPTEMBER 30, 2000 AT SEPTEMBER 30, 2000
---------------- -------------------------- ------------------------
NATURAL
OIL GAS TOTAL AMOUNT(1)
BOE/D PERCENT (MBbls) (MMcf) (MBOE) (IN THOUSANDS) PERCENT
----- ------- ------- ------- ------ -------------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
Cedar Creek
Anticline............ 10,733 65% 82,083 12,641 84,190 $436,790 72%
Crockett County........ 1,542 9 121 35,216 5,990 79,456 13
Lodgepole.............. 2,659 16 2,179 914 2,331 50,859 8
Indian Basin/Verden.... 1,550 10 258 18,725 3,379 43,993 7
------ --- ------ ------ ------ -------- ---
Total........ 16,484 100% 84,641 67,496 95,890 $611,098 100%
====== === ====== ====== ====== ======== ===
</TABLE>
---------------
(1)Without deducting the discounted value of hedging transactions, which
aggregated $26.5 million based on prevailing prices at September 30, 2000.
We were organized as a Delaware corporation in April 1998 and made our
first property acquisition in June 1999. Since our organization, we have
completed four acquisitions at a total acquisition cost of $298 million,
representing 96 million BOE of proved reserves at September 30, 2000. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" for a description of our acquisitions.
During the last quarter of 2000 and the first six months of 2001, we plan
to expend approximately $40 million to exploit and develop our existing core
properties, including $35 million to drill up to 65 development wells. If
appropriate opportunities arise during that period, we will acquire additional
producing oil and natural gas properties, and we will continue to evaluate and
develop our proposed CO(2) tertiary recovery project in the Williston Basin.
We believe that the increased capacity under our credit agreement that will
result from applying the proceeds of this offering, together with our internally
generated cash flow, will satisfy the cash requirements of our business for the
foreseeable future. We do not foresee the need during the next six months to
raise additional funds to operate our business, except borrowings under our
credit agreement.
OPERATIONS
We act as operator of properties representing approximately 81% of our
PV-10 reserve value at September 30, 2000. As operator, we are able to control
expenses, capital allocation and the timing of exploitation and development
activities of these properties. Our remaining properties are operated by third
parties, and, as working interest owners in those properties, we are required to
pay our share of the costs of exploiting and developing them. See "Properties --
37
<PAGE> 41
Nature of Our Ownership Interests". During the year ended December 31, 1999 and
the nine months ended September 30, 2000 our approximate costs for development
activities on non-operated properties were $250,000 and $800,000, respectively.
RECENT DEVELOPMENTS
Effective October 1, 2000, we acquired producing properties in Powder River
and Carter Counties, Montana, known as the Bell Creek Field for a total purchase
amount of $7.3 million, of which $5.8 million is attributable to the properties
and $1.5 million is attributable to an escrow account to cover the anticipated
costs of plugging and abandoning wells.
PROVED RESERVES
The following table sets forth estimated period-end proved reserves for the
periods indicated:
<TABLE>
<CAPTION>
HISTORICAL
----------------------------
DECEMBER 31, SEPTEMBER 30,
1999 2000
------------ -------------
<S> <C> <C>
Oil (MBbls)
Developed......................................... 67,019 73,703
Undeveloped....................................... 12,198 10,938
-------- --------
Total..................................... 79,217 84,641
======== ========
Natural Gas (MMcf)
Developed......................................... 10,082 62,330
Undeveloped....................................... 2,420 5,166
-------- --------
Total..................................... 12,502 67,496
======== ========
Total (MBOE)........................................ 81,301 95,890
======== ========
PV-10 (in thousands)(1)
Developed......................................... $287,439 $559,447
Undeveloped....................................... 35,813 51,651
-------- --------
Total..................................... $323,252 $611,098
======== ========
</TABLE>
---------------
(1) The pretax present value of estimated future revenues to be generated from
the production of proved reserves calculated in accordance with SEC
guidelines, net of estimated production and future development costs, using
prices and costs as of the date of estimation without future escalation,
without giving effect to hedging activities, non-property related expenses
such as general and administrative expenses, debt service and depreciation,
depletion and amortization, and discounted using an annual discount rate of
10%. Giving effect to hedging transactions based on prices current at such
dates, our PV-10 value would have been $318.3 million at December 31, 1999
(historical), $421.7 million at December 31, 1999 (pro forma), and $584.6
million at September 30, 2000 (historical and pro forma).
The estimates included in this prospectus of proved oil and natural gas
reserves at September 30, 2000 are based upon reports of Miller and Lents, Ltd.,
adjusted by us to roll forward such reserve information to September 30, 2000.
Estimates of future recoverable reserves are consistent with volumetrically
derived reserves in place, and the recovery factors applied are believed to be
reasonable.
A summary letter of Miller and Lents, Ltd. reporting our proved reserves as
of June 30, 2000 is attached to this prospectus as Annex A. The proved reserves
set forth in such letter as of June 30, 2000 were 93.3 million BOE, which is
equal to 97% of the 95.9 million BOE of our estimate of proved reserves as of
September 30, 2000. A reconciliation of the adjustments made by Encore to the
reserves reported by Miller and Lents, Ltd. is set forth in the following table.
38
<PAGE> 42
CHANGES IN PROVED RESERVES
BETWEEN JUNE 30, 2000 AND SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
OIL GAS
MBbls MMcf MBOE
------ ------ ------
<S> <C> <C> <C>
June 30, 2000 Miller and Lents, Ltd. report on proved
reserves.................................................. 84,716 51,626 93,320
Acquisition of Indian Basin/Verden.......................... 263 18,973 3,425
Extensions and discoveries.................................. 1,560 303 1,611
Revisions................................................... (740) (2,024) (1,078)
Production.................................................. (1,158) (1,382) (1,388)
------ ------ ------
September 30, 2000 proved reserves.......................... 84,641 67,496 95,890
====== ====== ======
</TABLE>
The reserve estimates for the acquisition of the Indian Basin/Verden
properties were based on a supplemental September 1, 2000 acquisition reserve
report prepared by Miller and Lents, Ltd. and rolled forward by us to September
30, 2000.
Proved developed reserves are proved reserves that are expected to be
recovered from existing wells with existing equipment and operating methods.
Proved undeveloped reserves are proved reserves that are expected to be
recovered from new wells drilled to known reservoirs on undrilled acreage for
which the existence and recoverability of such reserves can be estimated with
reasonable certainty, or from existing wells where a relatively major
expenditure is required to establish production.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
exploitation expenditures. The data in the above table represents estimates
only. Oil and natural gas reserve engineering is inherently a subjective process
of estimating underground accumulations of oil and natural gas that cannot be
measured exactly, and estimates of other engineers might differ materially from
those shown above. The accuracy of any reserve estimate is a function of the
quality of available data and engineering and geological interpretation and
judgment. Results of drilling, testing and production after the date of the
estimate may justify revisions. Accordingly, reserve estimates may vary from the
quantities of oil and natural gas that are ultimately recovered.
Future prices received for production and costs may vary, perhaps
significantly, from the prices and costs assumed for purposes of these
estimates. The PV-10 reserve value shown should not be construed as the current
market value of the reserves. The 10% discount factor used to calculate present
value, which is mandated by the SEC, is not necessarily the most appropriate
discount rate. The present value, no matter what discount rate is used, is
materially affected by assumptions as to timing of future production, which may
prove to be inaccurate. For properties that we operate, expenses exclude our
share of overhead charges. In addition, the calculation of estimated future net
revenues does not take into account the effect of various cash outlays,
including, among other things, general and administrative costs and interest
expense.
During the calendar year 2000, Encore filed estimates of oil and natural
gas reserves at December 31, 1999 with the U.S. Department of Energy on Form
EIA-23. This estimate was based on an internal reserve study and reflected more
reserves than those set forth in the table above. This reduction resulted from a
reassessment of some of our proved undeveloped reserves as a result of
additional drilling.
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<PAGE> 43
PRODUCTION AND PRICE HISTORY
The following table sets forth information regarding net production of oil,
natural gas and natural gas liquids, and certain price and cost information for
each of the periods indicated:
<TABLE>
<CAPTION>
HISTORICAL PRO FORMA
---------------------------- ----------------------------
YEAR NINE MONTHS YEAR NINE MONTHS
ENDED ENDED ENDED ENDED
DECEMBER 31, SEPTEMBER 30, DECEMBER 31, SEPTEMBER 30,
1999(1) 2000(2) 1999(3) 2000(4)
------------ ------------- ------------ -------------
<S> <C> <C> <C> <C>
PRODUCTION DATA (1):
Oil (MBbls)..................................... 1,996 3,191 5,056 3,450
Natural gas (MMcf).............................. 455 2,696 8,549 5,457
Combined volumes (MBOE)......................... 2,072 3,640 6,481 4,359
AVERAGE PRICES (5):
Oil (per Bbl)................................... $ 15.26 $ 20.48 $ 13.48 $ 21.30
Natural gas (per Mcf)........................... 1.78 3.55 2.13 3.17
Combined volumes (per BOE)...................... 15.09 20.58 3.33 20.82
AVERAGE COSTS (PER BOE):
Lease Operating Expenses:
Direct lifting costs.......................... 4.06 3.40 2.98 3.33
Production, ad valorem and severance taxes.... 2.62 2.93 1.72 2.69
Depletion, depreciation and amortization........ 2.55 4.08 4.12 4.39
General and administrative...................... 1.95 1.06 .81 .88
</TABLE>
---------------
(1) Prior to June 1, 1999, Encore had no production.
(2) Includes six months of Crockett County and Lodgepole production from April
to September 2000.
(3) Pro forma as if the Cedar Creek Anticline, Other Cedar Creek, Crockett
County, Lodgepole and Indian Basin/Verden acquisitions had taken place on
January 1, 1999.
(4) Pro forma as if the Crockett County, Lodgepole and Indian Basin/Verden
acquisitions had taken place on January 1, 2000.
(5)Includes the effects of net profits interest expense and Encore's hedging
activities.
PRODUCING WELLS
The following table sets forth information at September 30, 2000 relating
to the producing wells in which we owned a working interest as of that date. We
also held royalty interests in 578 producing wells as of that date. Wells are
classified as oil or natural gas wells according to their predominant production
stream. Gross wells are the total number of producing wells in which we have an
interest, and net wells are determined by multiplying gross wells by our average
working interest.
<TABLE>
<CAPTION>
AVERAGE
GROSS NET WORKING
WELLS WELLS INTEREST
----- ----- --------
<S> <C> <C> <C>
Cedar Creek Anticline....................................... 477 413 86%
Crockett County............................................. 274 110 40%
Lodgepole................................................... 25 6 24%
Indian Basin/Verden......................................... 159 21 17%
--- --- --
Total....................................................... 935(1) 550 59%(2)
=== === ==
</TABLE>
---------------
(1) Our total wells include 614 operated wells and 321 non-operated wells.
(2) Our total weighted average working interest is 59%.
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<PAGE> 44
ACREAGE
The following table sets forth information at September 30, 2000 relating
to acreage held by us. Developed acreage is assigned to producing wells.
Undeveloped acreage is acreage held under lease, permit, contract or option that
is not in a spacing unit for a producing well, including leasehold interests
identified for exploitation or exploratory drilling.
<TABLE>
<CAPTION>
GROSS NET
ACREAGE ACREAGE
------- -------
<S> <C> <C>
Developed acreage........................................... 141,639 95,475
Undeveloped acreage......................................... 57,407 47,741
------- -------
Total............................................. 199,046 143,216
======= =======
</TABLE>
DRILLING RESULTS
The following table sets forth information with respect to wells drilled
during the periods indicated. The information should not be considered
indicative of future performance, nor should it be assumed that there is
necessarily any correlation between the number of productive wells drilled,
quantities of reserves found or economic value. Productive wells are those that
produce commercial quantities of hydrocarbons, whether or not they produce a
reasonable rate of return.
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED ENDED
DECEMBER 31, SEPTEMBER 30,
DEVELOPMENT WELLS 1999 2000
----------------- ------------ -------------
<S> <C> <C>
Productive
Gross.............................................. 10.0 34.0
Net................................................ 8.3 22.2
Dry
Gross.............................................. -- 2.0
Net................................................ -- 0.1
</TABLE>
In addition, three (2.8 net) wells were in the process of drilling at
September 30, 2000.
MARKETING
Our oil and natural gas production is principally sold to end users,
marketers and other purchasers having access to nearby pipeline facilities. In
areas where there is no practical access to pipelines, oil is trucked to storage
facilities. Our marketing of oil and natural gas can be affected by factors
beyond our control, the effects of which cannot be accurately predicted. For the
fiscal year 1999, our largest purchasers included Equiva Trading Company (a
joint venture between Shell and Texaco), Conoco and Bear Paw Energy, which
accounted for 91%, 5% and 2% of total oil and natural gas sales, respectively.
COMPETITION
We compete with major and independent oil and natural gas companies. Some
of our competitors have substantially greater financial and other resources than
we do. In addition, larger competitors may be able to absorb the burden of any
changes in Federal, state, provincial and local laws and regulations more easily
than we can, which would adversely affect our competitive position. Our
competitors may be able to pay more for productive oil and natural gas
properties and may be able to define, evaluate, bid for and purchase a greater
number of properties and prospects than we can. Further, these companies may
enjoy technological advantages and may be able to implement new technologies
more rapidly than we can. Our ability to acquire additional properties in the
future will depend upon our ability to conduct
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<PAGE> 45
operations, to evaluate and select suitable properties, implement advanced
technologies and to consummate transactions in this highly competitive
environment.
OPERATING HAZARDS AND INSURANCE
The oil and natural gas business involves a variety of operating risks,
including fires, explosions, blowouts, environmental hazards and other potential
events which can adversely affect our operations. Any of these problems could
adversely affect our ability to conduct operations and cause us to incur
substantial losses. Such losses could reduce or eliminate the funds available
for exploration, exploitation or leasehold acquisitions, or result in loss of
properties.
In accordance with industry practice, we maintain insurance against some,
but not all, potential risks and losses. We do not carry business interruption
insurance. For some risks, we may not obtain insurance if we believe the cost of
available insurance is excessive relative to the risks presented. In addition,
pollution and environmental risks generally are not fully insurable at a
reasonable cost. If a significant accident or other event occurs and is not
fully covered by insurance, it could adversely affect us.
EMPLOYEES
At September 30, 2000, we had a total of 82 full-time employees, of which
36 are in field operations. We believe that our relationships with our employees
are satisfactory. None of our employees are covered by a collective bargaining
agreement. From time to time, we use the services of independent consultants and
contractors to perform various professional services, particularly in the areas
of construction, design, well-site surveillance, permitting and environmental
assessment. Currently we engage one engineering and two geology/geophysical
consultants. Independent contractors often perform field and on-site production
operation services for us, including pumping, maintenance, dispatching,
inspection and testing.
LEGAL PROCEEDINGS
From time to time, we may be a party to various legal proceedings. We are
not currently party to any material legal proceedings.
PROPERTIES
NATURE OF OUR OWNERSHIP INTERESTS
We own interests in oil and natural gas properties located in Montana,
North Dakota, Texas, New Mexico and Oklahoma. Substantially all of our PV-10
reserve value at September 30, 2000 was attributable to working interests in oil
and natural gas properties. A working interest in an oil and natural gas lease
requires us to pay our proportionate share of the costs of drilling and
production.
A major portion of our acreage position in the Cedar Creek Anticline is
subject to net profits interests ranging from 1% to 50%. The holders of these
net profits interests are entitled to receive a fixed percentage of the cash
flow remaining after specified costs have been subtracted from net revenue.
These net profits interests are reflected in our reserve reports, and revenues
reported in our financial statements are net of net profits interest payments.
See "-- Description of the Cedar Creek Anticline -- Land".
DESCRIPTION OF CEDAR CREEK ANTICLINE
Our core asset is the Cedar Creek Anticline, which we acquired from a major
oil and gas company in June 1999. The Cedar Creek Anticline, which has produced
393 million barrels of oil,
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<PAGE> 46
is located in the Williston Basin of eastern Montana and western North Dakota.
The properties are characterized by:
- a large quantity of remaining recoverable reserves;
- significant proved developed producing reserves and significant
opportunities to increase those reserves through exploitation and
development;
- well established shallow production decline rates;
- suitability to the application of recently introduced technologies,
including horizontal drilling and tertiary recovery operations; and
- geographic concentration.
HISTORY AND DEVELOPMENT OF CEDAR CREEK ANTICLINE PROPERTIES. Natural gas
was discovered on the Cedar Creek Anticline in 1912 at a depth of 750 feet in
the Cretaceous Judith River and Eagle Formations. Oil was first encountered in a
few noncommercial wells drilled to deeper formations between the years 1936 and
1950. Commercial quantities of oil in the deeper formations were discovered in
the South Pine Field in 1952. Development drilling on the Cedar Creek Anticline
peaked during the late 1950's and early 1960's, with over 1,100 deep wells
drilled to date. Peak production from the fields occurred in 1963 at a rate of
approximately 37,000 gross barrels of oil per day. Secondary recovery waterflood
projects were initiated between 1964 and 1972. Currently, we have 471 operated
and five non-operated active production wells, including 56 horizontal wells
drilled since 1993, which are presently producing at a rate of approximately
13,738 Bbls (gross) of oil, 2,715 Mcf (gross) of natural gas per day and 84,265
barrels (gross) of water per day.
GEOLOGY. The Cedar Creek Anticline is a major geological feature in eastern
Montana and western North Dakota. Carbonate rocks were deposited in the ancient
seas of the Williston Basin 350 million years ago. Powerful regional forces then
caused folding and faulting of these rocks to create an anticlinal structure.
Oil, generated in the deeper portions of the Williston Basin, then migrated
upwards until it was trapped in the crest of this structure. Encore's acreage is
concentrated on the crest of the CCA, which gives it access to the greatest
accumulation of oil in the structure. Our holdings extend for approximately 70
miles in a northwest-southeast direction and range from two to six miles in
width. Production is primarily from four carbonate formations. From shallowest
to deepest, the four formations are the Mission Canyon, Lodgepole, Interlake and
Stony Mountain/Red River. This gross producing interval is approximately 2,000
feet thick, and ranges in depth from approximately 7,000 feet to 9,000 feet.
EXPLOITATION OPPORTUNITIES. We have identified more than 225 undrilled
exploitation opportunities on the Cedar Creek Anticline, of which 42 are
reflected in our proved reserves at September 30, 2000. These infill drilling,
horizontal redevelopment and extensional drilling projects should increase
reserve recoveries and production rates and extend the productive limits of our
fields. We plan to pursue more than 200 of these projects over the next four
years. These projects, along with the associated investment in field facilities,
will require an estimated investment of $159 million.
Infill Drilling. We have identified over 110 infill projects. One
prospective area for infill drilling is the Cabin Creek unit where we expect to
spend $16 million. We analyzed production data to determine the likely drainage
radius of the producing wells in the field and have identified more than 31
infill locations designed to recover oil that will not be recovered by existing
wellbores. We also have infill projects planned at the South Pine, Coral Creek,
Little Beaver, Monarch and Pennel units.
Horizontal Redevelopment. We have identified more than 75 projects
involving new horizontal wells and horizontal recompletions. Horizontal wells
are drilled laterally for several
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<PAGE> 47
thousand feet within the targeted formation, allowing the wellbore to contact
more oil than a typical vertical well which only penetrates the formation at a
single point. Developments in horizontal technology now allow us to re-enter
existing vertical wells, including inactive wells, and drill out horizontally
for several thousand feet. For example, at the Pennel unit we analyzed each of
27 sections to determine potential incremental reserve recoveries through
horizontal drilling based upon analogues to recent horizontal drilling on a
nearby lease. Based on this analysis, we expect to spend $30 million on 38
horizontal projects in the Pennel unit. We also plan horizontal redevelopment in
the North and South Pine units.
Extensional Development. We have identified more than 40 projects to extend
the producing limits of our existing fields. At the Monarch unit, we plan to
drill and waterflood the Red River formation, which is productive throughout the
anticline but has yet to be developed in this area. We also plan to extend the
productive limits of the Cabin Creek and South Pine units with stepout wells
targeting the Red River formation.
CO(2) Tertiary Recovery. Encore believes that the current waterflood
projects in the Cedar Creek Anticline will ultimately recover about 26% of the
corresponding estimated original oil in place. In 1985, the previous operator
conducted a pilot test to evaluate the specific applicability of CO(2) at the
CCA. That test demonstrated that injected CO(2) was effective at recovering
additional oil. While the prior operator did not undertake a full-scale CO(2)
tertiary recovery project, we believe that a number of factors make a CO(2)
project more feasible in the current environment.
Since the 1985 test, the industry has accumulated fifteen years of
experience with CO(2) tertiary recovery. In addition, prevailing commodity
prices are currently significantly higher than in 1985 and more economical
sources of CO(2) supply have become available as there are increasing concerns
related to gas processors continuing to vent CO(2), a byproduct of their
operations, to the atmosphere. Presently, there are two viable sources of CO(2)
near our CCA properties: the Dakota Gasification Plant in North Dakota and
Exxon's Shute Creek Gas Processing Plant in southeastern Wyoming. Preliminary
discussions with both parties have suggested that adequate volumes of CO(2) are
available at prices that we believe will permit full-scale projects to be
economically attractive.
Encore has begun the engineering studies necessary to fully evaluate the
economics of a field-scale project. Based on the results of the 1985 pilot and
internally generated computer models, our preliminary assessment of the
incremental CO(2) project reserve potential at the CCA is approximately 16% of
the original oil in place. We believe this potential would be actualized through
a series of projects, each lasting 20 to 30 years. Implementation of the first
of these projects is at least three years in the future. We anticipate that
approximately 60% of the Cedar Creek Anticline properties will be suitable for
CO(2) flooding. There are inherent uncertainties in estimates based upon
computer models, and our estimates may ultimately be inaccurate.
LAND. A major portion of Encore's acreage position is subject to agreements
with Montana-Dakota Utilities Company (MDU) and Fidelity Gas Company. Various
Federal, state and private leases and contracts on mineral interests govern
Encore's oil and natural gas rights on the Cedar Creek Anticline. In addition,
the MDU/Fidelity agreements provide for various net profits interests ranging
from 1% to 50% to be paid after the recovery of capital costs, operating
expenses and interest on several of the units. The net profits interests are
reflected in our reserve report and net profits payments are excluded from our
revenues. Encore operates 99% of our total CCA value. Of the fields we operate,
we own an 86% weighted-average working interest. The royalty burden is about
13%. Encore controls approximately 134,000 gross and 118,000 net leasehold acres
along the Cedar Creek Anticline.
DESCRIPTION OF CROCKETT COUNTY
The Crockett County properties are located in the Permian Basin in West
Texas. Encore purchased all of these interests in Crockett County, Texas. The
properties produce mainly natural
44
<PAGE> 48
gas, 99% by reserve volume, and are part of the prolific Val Verde basin natural
gas area. The natural gas reservoirs in this area have multi-pay potential in
thick, porous zones. We believe that we acquired quality, long-lived natural gas
assets with significant development potential at an attractive price through
this acquisition. It also enabled us to enter a basin well known for its
abundant natural gas resources, low operating costs and competitive finding
costs. Attractive additional acquisition opportunities will continue to make
this a focus area for us.
The purchase price for this acquisition was $43.0 million, with an
effective date of April 1, 2000 and a closing date of March 30, 2000. The
Crockett County properties consist primarily of three field groupings,
Henderson, Ozona and Hunt-Baggett. We operate 68% of the properties based on
PV-10 reserve value. There are 271 active wells currently producing 9.1 MMcf/D
net to Encore. We operate 128 wells producing from the Canyon and Strawn
intervals.
This area provides the potential for additional infill and stepout
drilling. The limits of the Canyon and Strawn reservoirs have not been found,
and the multi-pay nature of the sands have the potential to add reserves and
value through continued development. The properties produce high quality natural
gas and liquids and are connected to several different markets.
DESCRIPTION OF LODGEPOLE
The Lodgepole properties are also located in the Williston Basin in Stark
County, North Dakota. The Lodgepole area is characterized by highly productive
wells, low R/P Index ratios and low lifting costs. The purchase price for these
properties was $35.2 million. The Lodgepole properties are 93% oil by volume,
and approximately 97% of the properties are non-operated. The Lodgepole
properties consist of working and overriding royalty interests in the Eland,
Stadium, Hiline, Livestock, Patterson Lake and the Beattrice Ridl fields. The
major asset, constituting 85% of the reserve value, is the Eland Unit, which is
operated by Duncan Oil Inc. of Denver, Colorado. Encore owns a 26.0% working
interest and 25.6% revenue interest in the Eland Unit. In September 2000,
production from the property averaged 2,448 Bbls of oil per day, 593 barrels of
water per day and 1,266 Mcf of natural gas per day, net to our interests.
Because of the unique characteristics of its producing reservoir, namely
its high permeability and thick oil column, producing wells in the Eland Unit
are prolific, with some wells flowing as much as 1,000 barrels of oil per day.
As a result, the lifting costs for these properties are less than $1.00 per Bbl
and the gross profit margin on production, after royalties and taxes, is
currently greater than 90% of revenues.
DESCRIPTION OF INDIAN BASIN/VERDEN
The Indian Basin/Verden properties were acquired for $25.4 million on
August 24, 2000, effective April 1, 2000.
The Indian Basin, Cemetery and Dagger Draw South Fields, collectively
referred to as the Indian Basin assets, are located in the Permian Basin of
southeast New Mexico. Encore owns varied non-operated working interests in two
Federal units and in six communitized areas. The reserves are 95% natural gas by
volume. Production is from Pennsylvanian-aged (Canyon) carbonates at 8,000 feet.
Encore's current net production is 4.8 MMcf/D of natural gas, 90 Bbl/D of oil
and 1,730 barrels of water per day. Marathon, Texaco and Chevron are the major
operators. Production from the area has been steadily increasing over the past
several years as the operators have been successfully perforating natural gas
zones that were not completed when the wells were originally drilled.
The Verden assets, located in the Anadarko Basin of Oklahoma, are 75%
non-operated and 90% natural gas by volume. Encore's current net production is
3.5 MMcf/D of natural gas and 80 Bbl/D of oil. The properties produce negligible
volumes of water. Apache is the principal operator. Production is from the
Springer formations below 15,000 feet. These deep, multi-pay,
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<PAGE> 49
geologically complex reservoirs have historically proven to be conducive to
subsequent drilling and workover operations beyond the initial development well.
Since acquiring the properties in late August, Encore has elected to participate
in three separate development wells.
TITLE TO PROPERTIES
We believe that our title to our oil and natural gas properties is good and
defensible in accordance with standards generally accepted in the oil and
natural gas industry.
Our properties are typically subject, in one degree or another, to one or
more of the following:
- royalties, overriding royalties, net profit interests and other burdens
under oil and natural gas leases;
- contractual obligations, including, in some cases, development
obligations, arising under operating agreements, farmout agreements,
production sales contracts and other agreements that may affect the
properties or their titles;
- liens that arise in the normal course of operations, such as those for
unpaid taxes, statutory liens securing unpaid suppliers and contractors
and contractual liens under operating agreements;
- pooling, unitization and communitization agreements, declarations and
orders; and
- easements, restrictions, rights-of-way and other matters that commonly
affect property.
We believe that the burdens and obligations affecting our properties are
conventional in the industry for similar properties and do not in the aggregate
materially interfere with the use of the properties.
REGULATORY MATTERS
FEDERAL REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978 and the regulations promulgated thereunder by
the Federal Energy Regulatory Commission. In the past, the Federal government
has regulated the prices at which natural gas could be sold. Deregulation of
natural gas sales by producers began with the enactment of the Natural Gas
Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act,
which removed all remaining Natural Gas Act and Natural Gas Policy Act price and
non-price controls affecting producer sales of natural gas effective January 1,
1993. Congress could, however, reenact price controls in the future. If price
controls that limit prices to below market rates were instituted, Encore's
revenues would be adversely affected. However, we do not currently sell any oil
or natural gas at above market prices.
Our sales of natural gas are affected by the availability, terms and cost
of pipeline transportation. The price and terms for access to pipeline
transportation remain subject to extensive Federal regulation. Commencing in
April 1992, the Federal Energy Regulatory Commission issued Order No. 636 and a
series of related orders, which required interstate pipelines to provide
open-access transportation on a basis that is equal for all natural gas
suppliers. The Federal Energy Regulatory Commission has stated that it intends
for Order No. 636 to foster increased competition within all phases of the
natural gas industry. Although Order No. 636 does not directly regulate our
production and marketing activities, it does affect how buyers and sellers gain
access to the necessary transportation facilities and how we and our competitors
sell natural gas in the marketplace. The courts have largely affirmed the
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<PAGE> 50
significant features of Order No. 636 and the numerous related orders pertaining
to individual pipelines, although some appeals remain pending and the Federal
Energy Regulatory Commission continues to review and modify its regulations
regarding the transportation of natural gas. For example, the Federal Energy
Regulatory Commission has recently begun a broad review of its transportation
regulations, including how its regulations operate in conjunction with state
proposals for retail natural gas marketing restructuring, whether to eliminate
cost-of-service based rates for short-term transportation, whether to allocate
all short-term capacity on the basis of competitive auctions and whether changes
to its long-term transportation service policies may be appropriate to avoid a
market bias toward short-term contracts. We cannot predict what action the
Federal Energy Regulatory Commission will take on these matters, nor can we
accurately predict whether the Federal Energy Regulatory Commission's actions
will achieve the goal of increasing competition in markets in which our natural
gas is sold. However, Encore believes that the Federal Energy Regulatory
Commission regulations should generally benefit its natural gas business. In any
event, we do not believe that any action taken will affect us in a way that
materially differs from the way it affects other natural gas producers.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the Federal Energy Regulatory Commission
and the courts. The natural gas industry historically has been very heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by the Federal Energy Regulatory Commission and
Congress will continue.
FEDERAL LEASES
A substantial portion of our operations are located on Federal oil and
natural gas leases, which are administered by the Minerals Management Service.
Such leases contain relatively standardized terms, typically providing a 1/8
royalty and providing that they will be held by production inside the federal
unit with no expiration until production ceases. These leases require compliance
with detailed Minerals Management Service regulations and orders, which are
subject to interpretation and change by the Minerals Management Service. The
Minerals Management Service also has regulations restricting the flaring or
venting of natural gas, and has proposed to amend such regulations to prohibit
the flaring of liquid hydrocarbons and oil without prior authorization. If we
fail to produce hydrocarbons from any of these leases on a continuous basis, the
Minerals Management Service may require any of our operations on the relevant
Federal leases to be suspended or terminated. Any such suspension or termination
could materially adversely affect our financial condition and results of
operations.
OIL PRICE CONTROLS AND TRANSPORTATION RATES
Sales of oil, condensate and natural gas liquids by us are not currently
regulated and are made at market prices. Effective as of January 1, 1995, the
Federal Energy Regulatory Commission implemented regulations establishing an
indexing system for transportation rates for oil that could increase the cost of
transporting oil to the purchaser. We do not believe that these regulations
affect us any differently than other crude oil producers and marketers.
ENVIRONMENTAL REGULATIONS
Our operations, which include the bulk storage of oil and hazardous
materials, are subject to numerous laws and regulations governing the discharge
of materials into the environment or otherwise relating to environmental
protection, including those listed below. We could incur substantial costs,
including cleanup costs, fines and civil or criminal sanctions, as a result of
violations of or liabilities under environmental laws or the non-compliance with
environmental permits required at our facilities. Public interest in the
protection of the environment has increased dramatically in recent years.
Offshore drilling in some areas has been opposed by environmental groups and, in
some areas, has been restricted. To the extent laws are enacted or
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<PAGE> 51
other governmental action is taken that prohibits or restricts drilling or
otherwise imposes environmental protection requirements that result in increased
costs to the oil and natural gas industry, our business and prospects could be
adversely affected.
Under the Comprehensive Environmental Response, Compensation, and Liability
Act, also known as the "Superfund" law, as well as similar state statutes, an
owner or operator of real property or a person who arranges for disposal of
hazardous substances may be liable for the costs of removing or remediating
hazardous substance contamination. Liability may be imposed on a current owner
or operator without regard to fault and for the entire cost of the cleanup. It
is not uncommon for neighboring landowners and other third parties to file
claims for personal injury and property damage allegedly caused by the hazardous
substances released into the environment. However, we are not aware of any
current claims under the Superfund law or similar state statutes against us.
We conduct remedial activities at some of our facilities as a result of
spills of oil or produced water from current or historical activities. To date,
the cost of such activities has not been material. However, we could incur
significant cost at these or other sites if additional contaminants are detected
or clean-up obligations imposed.
Our operations are also subject to the regulation of air emissions under
the Clean Air Act, comparable state and local requirements and of water
discharges under the Clean Water Act. We may be required to incur capital
expenditures to upgrade pollution control equipment or become liable for
non-compliance with applicable permits.
In addition, legislation has been proposed in Congress from time to time
that would reclassify some oil and natural gas exploration and production wastes
as "hazardous wastes", which would make the reclassified wastes subject to much
more stringent handling, disposal and clean-up requirements. This, or the
imposition of other environmental legislation, could increase our operating or
compliance costs.
We believe that we are in compliance in all material respects with current
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse impact on us.
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<PAGE> 52
MANAGEMENT
EXECUTIVE OFFICERS AND DIRECTORS
The following table sets forth the names, ages and positions of our
executive officers and directors as of September 30, 2000. Each director will
serve in that capacity until the next annual meeting of stockholders and until
his successor is elected and qualified. Each executive officer serves at the
pleasure of the Board of Directors.
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
I. Jon Brumley............................ 61 Chairman, President, Chief Executive
Officer and Director
Gene R. Carlson........................... 47 Executive Vice President-Operations
Jon S. Brumley............................ 30 Executive Vice President-Business
Development and Director
Kyle M. Schultz........................... 43 Executive Vice President-Exploitation and
Director
Morris B. Smith........................... 56 Executive Vice President and Chief
Financial Officer
Arnold L. Chavkin......................... 49 Director
Howard H. Newman.......................... 53 Director
Kenneth A. Hersh.......................... 37 Director
</TABLE>
The following biographies describe the business experience of our executive
officers and directors:
I. JON BRUMLEY, CHAIRMAN, PRESIDENT, CHIEF EXECUTIVE OFFICER AND DIRECTOR
SINCE INCEPTION IN APRIL 1998. Mr. Brumley began his career with Southland
Royalty Company as a risk analyst in 1967 and became its President in 1974. In
1980, while Mr. Brumley was President, Southland carved out two groups of
producing properties and formed two royalty trusts called the San Juan Basin
Royalty Trust and the Permian Basin Royalty Trust. These royalty trusts still
trade on the NYSE under the symbols SJT and PBT, respectively. In 1985,
Southland was acquired by Burlington Northern Railroad.
In 1986, Mr. Brumley co-founded Cross Timbers Oil Company to focus on the
acquisition and development of long-lived oil and natural gas properties. In
1992, while Mr. Brumley was Chairman of the Board, Cross Timbers created the
Cross Timbers Royalty Trust by carving out non-operated producing properties and
selling one half the trust units in the public market and distributing the other
half to the original investors. Cross Timbers Oil Company had a public offering
in 1993 while Mr. Brumley was Chairman of the Board, with an original market
capitalization of more than $200 million. Cross Timbers Oil Company had acquired
approximately $500 million of properties when Mr. Brumley resigned in July 1996.
In August 1996, Mr. Brumley accepted the position of Chairman and Chief
Executive Officer of MESA, and in August 1997 MESA was merged with Parker
Parsley to become Pioneer Natural Resources Company. In May 1998, Mr. Brumley
resigned as Executive Chairman of Pioneer Natural Resources (oil and gas
exploration, development and production).
Mr. Brumley holds a BBA from the University of Texas and a MBA from the
University of Pennsylvania Wharton School of Business.
GENE R. CARLSON, EXECUTIVE VICE PRESIDENT -- OPERATIONS SINCE INCEPTION IN
APRIL 1998. Mr. Carlson is a 26-year veteran of the oil and natural gas
industry. He began his career with Exxon where he held various engineering
assignments. From April 1977 to June 1996 he held various positions with
Southland Royalty Company and Burlington Resources, including Engineering
Manager, Denver Region of Burlington Resources from 1989 to 1996. He became
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<PAGE> 53
Corporate Development Manager for Duncan Oil in July 1996 and served in that
capacity until joining Encore. He has experience in evaluating acquisitions,
managing reservoir exploitation and operating oil and natural gas properties,
concentrated in the Mid-continent, Permian Basin and Rocky Mountain producing
regions. Mr. Carlson is a 1974 graduate of Texas A&M University and holds a
Bachelor of Science degree in Mechanical Engineering.
JON S. BRUMLEY, EXECUTIVE VICE PRESIDENT -- BUSINESS DEVELOPMENT AND
DIRECTOR SINCE INCEPTION IN APRIL 1998. Prior to joining Encore, Mr. Brumley
held the position of Manager of Commodity Risk and Commercial Projects for
Pioneer Natural Resources (an oil and natural gas exploration, development and
production company). He was with Pioneer since its creation by the merger of
MESA and Parker & Parsley in August 1997. Before the merger, he served as
Director -- Business Development for MESA from September 1996. From August 1993
to August 1996, he held various positions with Cross Timbers Oil Company and
North Central Oil Corporation. Mr. Brumley holds a Bachelor of Business
Administration in Marketing from the University of Texas. He is the son of I.
Jon Brumley.
KYLE M. SCHULTZ, EXECUTIVE VICE PRESIDENT -- EXPLOITATION SINCE INCEPTION
IN APRIL 1998. Prior to joining Encore, Mr. Schultz was a divisional Reservoir
Engineering Manager for Pioneer Natural Resources beginning in February 1997.
From March 1988 to February 1997, he was employed by Cross Timbers Oil Company,
where in December 1994 he was named Vice President -- Exploitation. Prior to
March 1988, he worked a total of nine years in the Refining and Production
Departments of Exxon. Mr. Schultz received a Bachelor of Science degree in
Chemical Engineering from the University of Texas in 1979.
MORRIS B. "SAM" SMITH, EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER
SINCE AUGUST 2000. Prior to joining Encore, Mr. Smith held the position of Vice
President of Finance and Chief Financial Officer for Union Pacific Resources
Group, Inc. (an independent oil and natural gas company). Mr. Smith held this
position since the spin-off of Union Pacific Resources Group from Union Pacific
Corporation in October 1996. Mr. Smith began his career with Shell Oil and held
a variety of positions in Houston and California. From 1976 to 1990, Mr. Smith
held various positions with Union Pacific Resources. In 1990 Mr. Smith joined
Union Pacific Corporation as Assistant Controller-Planning, moving to the Chief
Financial Officer of U.S.P.C.I. (Hazardous Waste Company) in 1993, Vice
President of Finance for the Union Pacific Railroad in 1995 and Vice President &
Controller of Union Pacific Corporation, then returned to Union Pacific
Resources as the Chief Financial Officer in July 1996. Mr. Smith is a graduate
of McMurry University located in Abilene, Texas and holds a Bachelor of Business
Administration degree in Accounting. He also attended the Advanced Management
Program/International Senior Management Program at Harvard Business School. He
is a Certified Public Accountant.
ARNOLD L. CHAVKIN, DIRECTOR SINCE AUGUST 1998. Mr. Chavkin is an executive
partner of Chase Capital Partners, an affiliate of The Chase Manhattan Bank, and
has served in such capacity for more than the past five years. Prior to joining
Chase Capital Partners, Mr. Chavkin was a member of Chemical Bank's merchant
banking group and a generalist in its corporate finance group specializing in
mergers and acquisitions and private placements for the energy industry. His
experience prior to Chemical Bank included corporate development for Freeport
McMoRan as well as positions with Gulf and Western Industries and Arthur Young &
Company. Mr. Chavkin is a Certified Public Accountant. He received his B.A. and
M.B.A. degrees from Columbia University. Mr. Chavkin is a director of American
Tower Corporation, Better Minerals & Aggregates, Carrizo Oil & Gas, Inc., Crown
Media Holdings, Inc., HDFC Bank, R&B Falcon Corporation, and Triton PCS, Inc. He
serves on the Advisory Investment Boards of Richina Group, the India Private
Equity Fund and the Asia Development Partners Fund.
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<PAGE> 54
HOWARD H. NEWMAN, DIRECTOR SINCE AUGUST 1998. Mr. Newman has been employed
by E.M. Warburg, Pincus & Co., LLC since January 1984 and has been a partner of
Warburg, Pincus & Co. since January 1987. Prior to that, he held various
positions with Morgan Stanley & Co., Incorporated from 1974 to 1983. Mr. Newman
holds Bachelor of Arts and Master of Arts degrees in economics from Yale
University and a Ph.D. degree in Business-Economics from Harvard University. He
also spent two years doing research in economics at Cambridge University. At
Warburg Pincus, Mr. Newman is currently Vice Chairman and a member of its
Operating, Compensation and Investment Policy Committees. He is also a director
of ADVO, Inc., Cox Insurance Holdings, Plc., Dime Bancorp Inc., Eagle Family
Foods Holdings, Inc., EEX Corporation, Newfield Exploration Company, Spinnaker
Exploration Company and several privately held companies. He also serves as Vice
Chairman of the Yale Alumni Fund.
KENNETH A. HERSH, DIRECTOR SINCE AUGUST 1998. From 1989 to the present, Mr.
Hersh has been a manager and Managing Director of the Natural Gas Partners
private equity investment funds. Previously, he was employed by the investment
banking division of Morgan Stanley & Co. Incorporated where he was a member of
the firm's energy group, specializing in oil and gas financing and acquisition
transactions. He is also a director of Prize Energy Corp., an independent oil
and gas company and several private companies. Mr. Hersh earned an MBA from the
Stanford University Graduate School of Business and a BA from Princeton
University.
COMMITTEES OF THE BOARD OF DIRECTORS
We have been a privately owned company to date, with substantial outside
investor participation. As a result, our Board of Directors has not yet
established an audit committee or a compensation committee. Shortly after
becoming a public company, however, we intend to name additional independent
directors, and our Board of Directors will establish those committees with
appropriate independent director participation.
AUDIT COMMITTEE
Our audit committee will be responsible for:
- recommending the selection of our independent accountants;
- reviewing and approving the scope of our independent accountants' audit
activity and extent of non-audit services;
- reviewing with management and the independent accountants the adequacy
of our basic accounting systems;
- reviewing our financial statements with management and the independent
accountants and exercising general oversight of our financial reporting
process; and
- reviewing our litigation and other legal matters that may affect our
financial condition and monitoring compliance with our business ethics
and other policies.
COMPENSATION COMMITTEE
Our compensation committee's responsibilities will include:
- administering and granting awards under our incentive stock plan;
- reviewing the compensation of our chief executive officer and
recommendations of the chief executive officer as to appropriate
compensation for our other executive officers and key personnel;
- examining periodically our general compensation structure; and
- supervising our welfare and pension plans and compensation plans.
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<PAGE> 55
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
None of our executive officers serves as a member of the Board of Directors
or compensation committee of any entity that has one or more of its executive
officers serving as a member of our Board of Directors or compensation
committee. Prior to December 2000, compensation matters were addressed by our
entire board of directors, on which Messrs. I. Jon Brumley, Jon S. Brumley and
Kyle Schultz serve. Each of those persons purchased shares of our common stock
in 1998. Each also is a party to an agreement pursuant to which we granted him
registration rights for those shares. For a description of these transactions,
please read "Certain Transactions".
COMPENSATION
COMPENSATION OF DIRECTORS
We paid no compensation to any non-employee director in 1999.
EXECUTIVE COMPENSATION
The following table sets forth certain summary information concerning the
compensation of our chief executive officer and each of the next four most
highly compensated officers for 1999. The annual compensation amounts in the
table exclude perquisites and other personal benefits for individuals for whom
the aggregate amount of such compensation does not exceed the lesser of (i)
$50,000 or (ii) 10% of the total annual salary and bonus for such named
executive officer in that year.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
ANNUAL
COMPENSATION
------------------ OTHER ANNUAL TOTAL
SALARY BONUS COMPENSATION COMPENSATION
------ ----- ------------ ------------
<S> <C> <C> <C> <C>
I. Jon Brumley....................... $300,000 $78,000 $ -- $378,000
Chairman, President and Chief
Executive Officer
Jon S. Brumley....................... 190,000 51,300 -- 241,300
Executive Vice President
-- Business Development
Kyle M. Schultz...................... 190,000 55,100 -- 245,100
Executive Vice President
-- Exploitation
Gene R. Carlson...................... 190,000 47,500 -- 237,500
Executive Vice President
-- Operations
Bruce B. Selkirk(1).................. 190,000 45,600 -- 235,600
Executive Vice President and Chief
Financial Officer
</TABLE>
---------------
(1) Mr. Selkirk resigned from Encore in March 2000.
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<PAGE> 56
DESCRIPTION OF THE ENCORE INCENTIVE STOCK PLAN
Encore's existing stockholders and Board of Directors will approve the
adoption of the Encore Acquisition Company 2000 Incentive Stock Plan.
The purpose of the plan will be to promote the acquisition, by directors
and employees of Encore and its subsidiaries, of a proprietary interest in
Encore through ownership of our common stock. This ownership is intended to
encourage employees to remain with us and to attract other qualified persons to
become employees and directors. The plan provides for the awarding of restricted
stock and the granting of options to purchase shares of common stock to
directors, officers and other eligible employees of Encore. All directors and
employees will be eligible to participate in the plan. Encore has three
non-employee directors and 82 employees.
The plan will be administered by the compensation committee of the Board of
Directors. The compensation committee will interpret and administer the plan and
will determine the participants to be granted options or awarded restricted
stock, the options or awards granted to the participants, the exercise price of
options, vesting provisions and other terms of each option and award.
The plan provides for the granting of options and awarding restricted stock
to directors and employees. No more than six percent (6%) of the outstanding
shares of common stock may be issued under the plan, and no person may be issued
incentive stock options covering shares with a fair market value at the date of
grant, in excess of $100,000 exercisable in any calendar year. For purposes of
determining the number of shares available for issuance under the plan, only net
shares issued are counted as issued. Net shares would exclude shares delivered
or withheld for payment of exercising an option or for payment of tax
withholding and would exclude shares remaining subject to options which expire
or are terminated and restricted shares that are forfeited. Options may be
either incentive stock options authorized under Section 422 of the Internal
Revenue Code or non-qualified options which do not qualify as incentive stock
options.
OPTIONS
The term of each option will be fixed by the compensation committee, but
may not be longer than ten years from the date of grant. The exercise price of
each option will be determined by the compensation committee, but may not be
less than the fair market value of the common stock on the date of grant in the
case of incentive stock options or 85% of fair market value in the case of
non-qualified options. Each option will be exercisable at the times and subject
to any conditions established by the compensation committee, and, upon a change
of control of Encore, as defined in the plan, unless otherwise determined by the
compensation committee all options will vest and become exercisable and all
transfer restrictions and vesting requirements on award shares will lapse. In
such event, all awards will be cashed out. The exercise price will be paid in
cash or, if permitted by the compensation committee, in common stock previously
owned by the option holder. The compensation committee may provide the option
holder with the right to satisfy any minimum withholding tax obligation by
delivery of previously owned shares or withholding shares otherwise issuable
upon exercise of the option. In the event of a stock dividend or stock split,
the number of shares subject to outstanding options will be proportionately
increased and the exercise price proportionately decreased, unless the
compensation committee determines otherwise. The number of shares available
under the plan and maximum number of shares issuable to one person will also be
proportionately increased, unless the compensation committee determines
otherwise. In the event of a combination of shares, recapitalization,
reclassification, merger or other similar capital or corporate structure change,
the compensation committee may adjust the terms of outstanding options, the
number of shares available under the plan, the maximum number of shares issuable
to one person and other provisions of the plan.
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<PAGE> 57
RESTRICTED STOCK
A restricted stock award is an award of common stock that is subject to
such restrictions on transferability and other restrictions, if any, as the
compensation committee may impose at the date of grant or thereafter, which
restrictions may lapse separately or in combinations at such time, under such
circumstances, including without limitation a specified period of employment or
the satisfaction of pre-established performance goals, when granted to executive
officers, in such installments, or otherwise, as the compensation committee may
determine. The compensation committee may grant restricted stock to such
persons, in such amounts, and subject to such terms and conditions as the
compensation committee may determine in its discretion. Shares of restricted
stock granted to executive officers may only vest upon the attainment of
performance goals pre-established by the compensation committee based on one or
more of the following criteria: return on equity; pre-tax or after tax income;
reserve levels; revenues; return on assets; increases in EBITDA; share price;
increase in equity; debt reduction; or such other criteria as Encore's
stockholders may approve. Restricted stock may not be sold, assigned,
transferred, pledged, or otherwise encumbered during the restricted period.
AMENDMENT; TERMINATION. The Board of Directors may suspend, revise,
terminate or amend the plan at any time; provided, however, that no such
amendment will be made without stockholder approval if such approval is required
under applicable law, or if such amendment would either decrease the grant or
exercise price of any stock option to less than the minimum price set forth in
the plan on the date of grant or increase the total number of shares of common
stock that may be distributed under the plan. The plan will terminate 10 years
after adoption by stockholders.
NEW PLAN BENEFITS
Encore proposes to grant, immediately following the public offering,
incentive stock options covering an aggregate of 602,000 shares of common stock
at an exercise price equal to the public offering price, to an aggregate of 82
of its employees, including 51,000 shares to Mr. I. Jon Brumley, 51,000 shares
to Mr. Jon S. Brumley, 51,000 shares to Mr. Kyle M. Schultz, 51,000 shares to
Mr. Gene R. Carlson, 60,000 shares to Mr. Morris B. Smith, 341,500 shares to
Encore's executive officers as a group, 250,500 shares to employees who are not
executive officers and 10,000 shares to non-employee directors.
CERTAIN FEDERAL INCOME TAX CONSEQUENCES
The following discussion is a brief summary of the principal United States
federal income tax consequences under current federal income tax laws relating
to awards under the plan. This summary is not intended to be exhaustive and,
among other things, does not describe state, local or foreign income and other
tax consequences
NON-QUALIFIED STOCK OPTIONS. An optionee will not recognize any taxable
income upon the grant of a non-qualified stock option. Encore will not be
entitled to a tax deduction with respect to the grant of a non-qualified stock
option. Upon exercise of a non-qualified stock option, the excess of the fair
market value of the common stock on the exercise date over the option exercise
price will be taxable as compensation income to the optionee and will be subject
to applicable withholding taxes. Encore will generally be entitled to a tax
deduction at such time in the amount of such compensation income. The optionee's
tax basis for the common stock received pursuant to the exercise of a
non-qualified stock option will equal the sum of the compensation income
recognized and the exercise price. In the event of a sale of common stock
received upon the exercise of a non-qualified stock option, any appreciation or
depreciation after the exercise date generally will be taxed as capital gain or
loss.
INCENTIVE STOCK OPTIONS. An optionee will not recognize any taxable income
at the time of grant or timely exercise of an incentive stock option, and Encore
will not be entitled to a tax
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<PAGE> 58
deduction with respect to such grant or exercise. Exercise of an Incentive stock
option may, however, give rise to taxable compensation income subject to
applicable withholding taxes, and a tax deduction to Encore, if the incentive
stock option is not exercised on a timely basis (generally, while the optionee
is employed by Encore or within 90 days after termination of employment) or if
the optionee subsequently engages in a "disqualifying disposition," as described
below. A sale or exchange by an optionee of shares acquired upon the exercise of
an incentive stock option more than one year after the transfer of the shares to
such optionee and more than two years after the date of grant of the incentive
stock option will result in the difference between the net sale proceeds and the
exercise price, if any, being treated as long-term capital gain (or loss) to the
optionee. If such sale or exchange takes place within two years after the date
of grant of the incentive stock option or within one year from the date of
transfer of the Incentive stock option shares to the optionee, such sale or
exchange will generally constitute a "disqualifying disposition" of such shares
that will have the following results: any excess of (a) the lesser of (i) the
fair market value of the shares at the time of exercise of the Incentive stock
option and (ii) the amount realized on such disqualifying disposition of the
shares over (b) the option exercise price of such shares, will be ordinary
income to the optionee, subject to applicable withholding taxes, and Encore will
be entitled to a tax deduction in the amount of such income. Any further gain or
loss after the date of exercise generally will qualify as capital gain or loss
and will not result in any deduction by Encore.
RESTRICTED STOCK. A grantee will not recognize any income upon the receipt
of restricted stock unless the holder elects under Section 83(b) of the Code,
within 30 days of such receipt, to recognize ordinary income in an amount equal
to the fair market value of the restricted stock at the time of receipt, less
any amount paid for the shares. If the election is made, the holder will not be
allowed a deduction for amounts subsequently required to be returned to Encore.
If the election is not made, the holder will generally recognize ordinary
income, on the date that the restrictions to which the restricted stock are
subject are removed, in an amount equal to the fair market value of such shares
on such date, less any amount paid for the shares. At the time the holder
recognizes ordinary income, Encore generally will be entitled to a deduction in
the same amount. Generally, upon a sale or other disposition of restricted stock
with respect to which the holder has recognized ordinary income (i.e., a Section
83(b) election was previously made or the restrictions were previously removed),
the holder will recognize capital gain or loss in an amount equal to the
difference between the amount realized on such sale or other disposition and the
holder's basis in such shares.
CERTAIN TRANSACTIONS
Following is a discussion of transactions between us and our officers,
directors and stockholders owning more than 5% of the outstanding shares of
common stock.
REGISTRATION RIGHTS
Encore, Warburg Pincus Equity Partners, Chase Venture Capital Associates,
Natural Gas Partners V, First Union Capital Partners and our other stockholders,
together holding 100% of our common stock prior to this offering, are parties to
a registration rights agreement. This registration rights agreement is described
under "Description of Capital Stock -- Registration Rights".
INVESTMENTS IN ENCORE
Since our inception, our executive officers, directors and 5% stockholders
have invested cash in Encore in exchange for shares of our Class A and Class B
common stock. The following table summarizes the shares of our Class A and Class
B common stock acquired from us by our executive officers, directors and 5%
stockholders since our inception. The shares were
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<PAGE> 59
purchased pursuant to subscription agreements and a stock purchase agreement
that require each stockholder to contribute additional capital for his or its
shares upon call by Encore. Those agreements and the commitments to contribute
additional capital are terminable by the holders of 75% of our Class B Stock
held by investor stockholders and will be terminated in the recapitalization
effected prior to this offering. Accordingly, no further capital contributions
will be made by such persons. Termination of the capital call obligations will
not reduce the number of shares purchased by our existing stockholders and will
have the effect of fixing the cost per share based on the amount paid in to
date. See "Dilution".
<TABLE>
<CAPTION>
CLASS A CLASS B
EXECUTIVE OFFICERS, DIRECTORS AND COMMON COMMON
5% STOCKHOLDERS STOCK STOCK
--------------------------------- ------- -------
<S> <C> <C>
Warburg, Pincus Equity Partners L.P.(1)..................... -- 140,000
Chase Venture Capital Associates, LLC(2).................... -- 100,000
Natural Gas Partners V, L.P.(3)............................. -- 30,000
First Union Capital Partners, Inc.(4)....................... -- 20,000
I. Jon Brumley(5)........................................... 39,944 3,536
Jon S. Brumley(6)........................................... 9,249 374
Kyle M. Schultz(7).......................................... 6,144 248
Gene R. Carlson(8).......................................... 3,137 123
Morris B. Smith(9).......................................... 1,324 50
</TABLE>
---------------
(1) Warburg, Pincus Equity Partners paid us $57.5 million of its $140 million
commitment for the shares listed above. One of our directors, Mr. Newman, is
affiliated with Warburg Pincus Equity Partners. You can read more about Mr.
Newman's affiliation with Warburg, Pincus Equity Partners under the heading
"Security Ownership of Management and Certain Beneficial Owners". We
estimate that Warburg Pincus Equity Partners' Class B shares will be
converted into 9,601,600 shares of common stock in the recapitalization to
be effected before we complete our initial public offering.
(2) Chase Venture Capital Associates paid us $41.1 million of its $100 million
commitment for the shares listed above. One of our directors, Mr. Chavkin,
is affiliated with Chase Venture Capital Associates. You can read more about
Mr. Chavkin's affiliation with Chase Venture Capital Associates under the
heading "Security Ownership of Management and Certain Beneficial Owners". We
estimate that Chase Venture Capital Associates' Class B shares will be
converted into 6,858,206 shares of common stock in the recapitalization to
be effected before we complete our initial public offering.
(3) Natural Gas Partners V paid us $12.3 million of its $30 million commitment
for the shares listed above. One of our directors, Mr. Hersh, is affiliated
with Natural Gas Partners V. You can read more about Mr. Hersh's affiliation
with Natural Gas Partners V under the heading "Security Ownership of
Management and Certain Beneficial Owners". We estimate that Natural Gas
Partners' Class B shares will be converted into 2,057,416 shares of common
stock in the recapitalization to be effected before we complete our initial
public offering.
(4) First Union Capital Partners paid us $8.2 million of its $20 million
commitment for the shares listed above. We estimate that First Union Capital
Partners' Class B shares will be converted into 1,371,657 shares of common
stock in the recapitalization to be effected before we complete our initial
public offering.
(5) Mr. I.J. Brumley paid us $2.1 million of his $5.2 million commitment for the
shares listed above, which we estimate will be converted into 1,680,894
shares of common stock in the recapitalization.
(6) Mr. J.S. Brumley paid us $307,000 of his $747,000 commitment for the shares
listed above, which we estimate will be converted into 358,694 shares of
common stock in the recapitalization.
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<PAGE> 60
(7) Mr. Schultz paid us $204,000 of his $496,000 commitment for the shares
listed above, which we estimate will be converted into 238,260 shares of
common stock in the recapitalization.
(8) Mr. Carlson paid us $103,000 of his $250,000 commitment for the shares
listed above, which we estimate will be converted into 121,398 shares of
common stock in the recapitalization.
(9) Mr. Smith paid us $43,000 of his $103,000 commitment for the shares listed
above, which we estimate will be converted into 51,107 shares of common
stock in the recapitalization.
INDEMNIFICATION AGREEMENTS
We have entered into indemnification agreements with our officers and
directors containing provisions requiring us, among other things to indemnify
our officers and directors against liabilities that may arise by reason of their
status or service as officers or directors, other than liabilities arising from
willful misconduct of a culpable nature, and to advance expenses they incur as a
result of any proceeding against them as to which they could be indemnified.
SECURITY OWNERSHIP OF MANAGEMENT
AND CERTAIN BENEFICIAL HOLDERS
The following presents information regarding beneficial ownership of our
common stock as of September 30, 2000 as though the recapitalization were
completed on that day by:
- each person who we know owns beneficially more than 5% of our common
stock;
- each of our directors;
- our chief executive officer and each of our four other most highly
compensated executive officers; and
- all our executive officers and directors as a group.
Immediately prior to the closing of this offering, our Class A and Class B
common stock will be converted into a single class of common stock. The number
of shares into which each class will be converted will be determined to give
effect to the Class B preferential return and the Class A subordinated interest
based on our valuation in the public offering. See "Recapitalization". The table
below estimates the number of shares that will be issued to our current
stockholders in the Recapitalization based on a public offering price of $14.00
per share.
Unless otherwise indicated, each person listed has sole voting and
dispositive power over the shares indicated as owned by that person, and the
address of each stockholder is the same as our address. Furthermore, under the
regulations of the SEC, shares are deemed to be "beneficially owned" by a person
if he directly or indirectly has or shares the power to vote or dispose of these
shares, whether or not he has any pecuniary interest in these shares, or if he
has the right to acquire the power to vote or dispose of shares within 60 days,
including any right to acquire through the exercise of any option, warrant or
right. The table does not reflect beneficial ownership of shares issuable upon
exercise of stock options expected to be granted upon completion of this
offering.
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<PAGE> 61
<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP
--------------------------------
PERCENT
-------------------
BEFORE AFTER
BENEFICIAL OWNER SHARES OFFERING OFFERING
---------------- ------ -------- --------
<S> <C> <C> <C>
Warburg, Pincus Equity Partners L.P.(1)................... 9,601,600 37.98% 31.97%
Chase Venture Capital Associates, LLC(2).................. 6,858,286 27.13 22.84
Natural Gas Partners V, L.P.(3)........................... 2,057,486 8.14 6.85
First Union Capital Partners, Inc.(4)..................... 1,371,657 5.43 4.57
I. Jon Brumley(5)......................................... 1,680,894 7.35 5.60
Jon S. Brumley............................................ 358,694 2.61 1.19
Kyle M. Schultz........................................... 238,260 1.73 *
Gene R. Carlson........................................... 121,398 * *
Morris B. Smith........................................... 51,107 * *
Howard H. Newman(1)....................................... 9,601,600 37.98 31.97
Arnold L. Chavkin(2)...................................... 6,858,286 27.13 22.84
Kenneth A. Hersh(3)....................................... 2,057,486 8.14 6.85
All executive officers and directors as a group........... 22,339,382 97.64% 74.39%
</TABLE>
---------------
* Represents beneficial ownership of less than 1%.
(1) This holder's address is 466 Lexington Avenue, New York, New York 10017.
These shares are shown in the table as being owned both by Warburg, Pincus
Equity Partners L.P. and Mr. Howard H. Newman. The sole general partner of
Warburg, Pincus Equity Partners is Warburg, Pincus & Co. E. M. Warburg,
Pincus & Co., LLC, a New York limited liability company, manages Warburg,
Pincus Equity Partners. Lionel I. Pincus is the managing member of E. M.
Warburg, Pincus & Co., LLC and the managing partner of Warburg, Pincus & Co.
and may be deemed to control both entities. Mr. Newman is a Managing
Director and a member of E. M. Warburg, Pincus & Co., LLC. and a general
partner of Warburg, Pincus & Co. As such, Mr. Newman may be deemed to have
an indirect pecuniary interest in an indeterminate portion of the shares
beneficially owned by Warburg, Pincus Equity Partners. Mr. Newman disclaims
beneficial ownership of the shares owned by Warburg, Pincus Equity Partners.
(2) This holder's address is 1221 Avenue of the Americas, New York, New York
10020-1080. These shares are shown in the table as being owned both by Chase
Venture Capital Associates, LLC and Mr. Arnold L. Chavkin. Chase Capital
Partners is the sole managing member of Chase Venture Capital Associates,
LLC. Mr. Chavkin is an executive partner of Chase Capital Partners and as
such may be deemed to have shared voting and dispositive power with respect
to the shares owned by Chase Venture Capital Associates, LLC. Mr. Chavkin
disclaims beneficial ownership of shares owned by Chase Venture Capital
Associates, LLC to the extent they exceed his pecuniary interest.
(3) This holder's address is 125 E. John Carpenter Freeway, Irving, Texas 75062.
These shares are shown in the table as being owned both by Natural Gas
Partners V, L.P. and Mr. Kenneth A. Hersh. As manager of Natural Gas
Partners V, L.P., Mr. Hersh may be deemed to have shared voting and
dispositive power with respect to the shares owned by that entity. Mr. Hersh
disclaims beneficial ownership of all shares owned by Natural Gas Partners
V, L.P.
(4) The address of this holder is 301 S. College Street, 5th Floor, Charlotte,
North Carolina 28288-0732. No representative of First Union currently serves
on Encore's Board of Directors.
(5) The shares are owned by two limited partnership, the sole general partner of
each of which is a corporation of which Mr. Brumley is the sole officer and
director and the principal shareholder. Accordingly, Mr. Brumley has sole
voting and dispositive power with respect to such shares.
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DESCRIPTION OF CAPITAL STOCK
Immediately prior to this offering, the capitalization of Encore will be
substantially modified. We are currently authorized to issue 375,000 shares of
common stock, par value $0.01 per share consisting of 75,000 shares of Class A
common stock and 300,000 shares of Class B common stock and 1,000 shares of
preferred stock. As of September 30, 2000, 73,725 shares of Class A common stock
and 294,901 shares of Class B common stock, par value $0.01, were outstanding.
Class A and Class B holders of common stock vote together as a single class on
all matters voted on by our stockholders, and each stockholder is entitled to
one vote (or a fraction thereof) for each share (or fraction thereof) of Class A
or Class B common stock owned by the stockholder. Subject to preferences that
may be applicable to any outstanding preferred stock, the holders of Class A and
Class B shares are entitled to receive ratable dividends, if any, as may be
declared from time to time by the Board of Directors out of funds legally
available for the payment of dividends once the Class B stockholders receive as
distributions an amount equal to each Class B stockholder's total investment in
Encore plus a return on investment of 7% per annum. In the event of any
voluntary or involuntary liquidation, after payment or provision for payment of
the debts and other liabilities of Encore, the holders of Class A and Class B
shares are entitled to share in the remaining net assets of Encore in the same
manner as dividends are distributed. All outstanding shares of common stock are
fully paid and nonassessable.
On the closing of this offering, our authorized capital stock will consist
of 50,000,000 shares of common stock, $0.01 par value, and 5,000,000 shares of
preferred stock, $0.01 par value.
COMMON STOCK
Immediately prior to this offering, there will be 22,880,000 shares of
common stock outstanding and held of record by 32 stockholders. There will be
30,030,000 shares of common stock outstanding (assuming no exercise of the
underwriters' over-allotment option) after giving effect to the sale of the
shares of common stock to the public in this offering. The holders of common
stock are entitled to one vote per share on all matters to be voted on by the
stockholders. Subject to preferences that may be applicable to any outstanding
preferred stock, the holders of common stock are entitled to receive ratable
dividends, if any, as may be declared from time to time by the Board of
Directors out of funds legally available for the payment of dividends. In the
event of the liquidation, dissolution, or winding up of Encore, the holders of
common stock are entitled to share ratably in all assets remaining after payment
of liabilities, subject to prior distribution rights of preferred stock, if any,
then outstanding. The common stock has no preemptive, conversion or other
subscription rights. There are no redemption or sinking fund provisions
applicable to the common stock. All outstanding shares of common stock are fully
paid and nonassessable, and the shares of common stock to be issued upon
completion of this offering will be fully paid and nonassessable.
PREFERRED STOCK
On the closing of this offering, 5,000,000 shares of preferred stock will
be authorized and no shares will be outstanding. The Board of Directors, without
further vote or action by the stockholders, has the authority to issue the
preferred stock in one or more series and to fix the rights, preferences,
privileges and restrictions thereof, including dividend rights, dividend rates,
conversion rights, voting rights, terms of redemption, redemption prices,
liquidation preferences and the number of shares constituting any series or the
designation of such series. The issuance of preferred stock may have the effect
of delaying, deferring or preventing a change in control of Encore without
further action by the stockholders and may adversely affect the voting and other
rights of the holders of common stock. The issuance of preferred stock with
voting and conversion rights may adversely affect the voting power of the
holders of common stock, including the loss of voting control to others. We
currently have no plans to issue any of the preferred stock.
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ANTI-TAKEOVER PROVISIONS OF OUR BYLAWS
Our bylaws establish an advance notice procedure for the nomination of
candidates for election as directors. In general, notice of intent to nominate a
director must be delivered to our principal executive offices as follows:
- With respect to elections to be held at the annual meeting of
stockholders, not less than 90 days nor more than 120 days prior to
the anniversary date of the immediately preceding annual meeting of
stockholders, and must contain specified information concerning the
person to be nominated.
- With respect to an election to be held at a special meeting of
stockholders for the election of directors, not less than 90 days nor
more than 120 days prior to the anniversary date of the immediately
preceding special meeting of stockholders or within ten days
following the day on which public announcement is first made of the
date of the special meeting and of the nominees proposed by the Board
of Directors to be elected at the special meeting.
These procedures may operate to limit the ability of stockholders to
nominate candidates for election as directors.
DELAWARE TAKEOVER STATUTE
We have opted out of Section 203 of the Delaware General Corporation Law
("DGCL"). Because approximately 71.83 % of our common stock outstanding after
the offering will be owned by five persons, our Board of Directors and
stockholders have determined that we do not need the benefit of Section 203.
DGCL Section 203 regulates corporate acquisitions and prevents certain Delaware
corporations, including those whose securities are listed on the New York Stock
Exchange from engaging, under certain circumstances, in a "business combination"
with any "interested stockholder" for three years following the date that such
stockholder became an interested stockholder. For purposes of DGCL Section 203,
a "business combination" includes, among other things, a merger or consolidation
involving Encore and the interested stockholder and the sale of 10% or more of
our assets. In general, DGCL Section 203 defines an "interested stockholder" as
any entity or person beneficially owning 15% or more of our outstanding voting
stock and any entity or person affiliated with or controlling or controlled by
such entity or person.
DELAWARE CORPORATE OPPORTUNITY PROVISION
As permitted by Section 122(17) of the DGCL, Encore's Certificate of
Incorporation contains a provision that permits any of our current investor
stockholders and their affiliates to participate in transactions relating
exclusively to the acquisition, development and exploitation of North American
oil and natural gas reserves without making such opportunities available to
Encore. Our investor stockholders believe this provision is necessary and
appropriate because of their other significant investments in entities that
conduct operations in the oil and natural gas industry.
REGISTRATION RIGHTS
After this offering, the holders of approximately 22,339,382 shares of
common stock will be entitled to rights with respect to the registration of such
shares under the Securities Act. Under the terms of the agreement between us and
the holders of such registrable securities, if we propose to register any of our
securities under the Securities Act, either for our own account or for the
account of other security holders exercising registration rights, such holders
are entitled to notice of such registration and are entitled to include shares
of such common stock in the registration. Additionally, such holders are also
entitled to demand registration rights, pursuant to which they may require us on
up to three occasions to file a registration statement under the Securities Act
at our expense with respect to their shares of common stock, and we are required
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to use all reasonable efforts to effect such registration. All of these
registration rights are subject to certain conditions and limitations, including
the right of the underwriters of an offering to limit the number of shares
included in such registration and our right not to effect a requested
registration within 180 days following an offering of our securities, including
the offering made by this prospectus.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for our common stock is ChaseMellon
Shareholder Services, L.L.C.
SHARES AVAILABLE FOR FUTURE SALE
Prior to this offering, there has been no market for our common stock, and
a significant public market for our common stock may not develop or be sustained
after this offering. Sales of substantial amounts of our common stock in the
public market could cause the market price of our common stock to fall and could
affect our ability to raise capital on terms favorable to us in the future.
Upon completion of this offering, we will have outstanding 30,030,000
shares of common stock, assuming the underwriters' over-allotment option is not
exercised. Of these shares, 7,150,000 shares, or 8,222,500 shares if the
underwriters exercise their over-allotment option in full, of the common stock
sold in this offering will be freely tradable without restriction under the
Securities Act unless purchased by our affiliates as that term is defined in
Rule 144 under the Securities Act. The remaining shares of common stock
outstanding will be restricted securities under Rule 144 and may in the future
be sold without registration under the Securities Act to the extent permitted by
Rule 144 or any other applicable exemption under the Securities Act, subject to
the restrictions on transfer contained in the lock-up agreements described below
and in "Underwriting".
RULE 144
In general, under Rule 144 as currently in effect, beginning 90 days after
the date of this prospectus, a person, or persons whose shares are aggregated,
who has beneficially owned restricted shares for at least one year, including
the holding period of any prior owner except an affiliate, would be entitled to
sell within any three-month period a number of shares that does not exceed the
greater of:
- one percent of the number of shares of common stock then outstanding,
which will equal approximately 300,300 shares immediately after this
offering; or
- the average weekly trading volume of the common stock during the four
calendar weeks preceding the filing of a Form 144 with respect to the
sale.
Sales under Rule 144 also are subject to manner of sale provisions and
notice requirements and to the availability of current public information about
us. Under Rule 144(k), a person who is not deemed to have been an affiliate of
us at any time during the three months preceding a sale and who has beneficially
owned the shares proposed to be sold for at least two years, including the
holding period of any prior owner except an affiliate, is entitled to sell those
shares without complying with the manner of sale, public information, volume
limitation or notice provisions of Rule 144.
RULE 701
Rule 701 permits resales of shares in reliance on Rule 144 but without
compliance with specified restrictions of Rule 144. Any employee, officer or
director of or consultant to Encore
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who purchased his or her shares under a written compensatory plan or contract
may be entitled to rely on the resale provisions of Rule 701. Rule 701 permits
affiliates to sell their Rule 701 shares under Rule 144 without complying with
the holding period requirements of Rule 144. Rule 701 further provides that
non-affiliates may sell those shares in reliance on Rule 144 without having to
comply with the holding period, public information, volume limitation or notice
provisions of Rule 144. All holders of Rule 701 shares are required to wait
until 90 days after the date of this prospectus before selling those shares.
STOCK OPTIONS
Following the consummation of this offering, we intend to file a
registration statement on Form S-8 under the Securities Act covering shares of
common stock reserved for issuance under our incentive stock plan. Based on the
number of shares currently reserved for issuance under the plan, that
registration statement would cover up to 1,802,000 shares issuable as restricted
stock awards or on exercise of options. No options have been issued as of the
date of this offering, but Encore expects to grant up to 602,000 options
immediately following the offering at an exercise price equal to the public
offering price. The registration statement on Form S-8 will automatically become
effective upon filing. Accordingly, subject to the exercise of those options,
shares registered under that registration statement will be available for sale
in the open market immediately after the 180-day lock-up agreements expire.
LOCK-UP AGREEMENTS
All of our officers, directors and substantially all of our stockholders
have signed Lock-Up Agreements under which they agreed not to transfer or
dispose of, directly or indirectly, any shares of common stock or any securities
convertible into or exercisable or exchangeable for shares of common stock, for
a period of 180 days after the date of this prospectus. Transfers or
dispositions can be made sooner with the prior written consent of Goldman, Sachs
& Co. See "Underwriting".
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UNDERWRITING
Encore and the underwriters named below (the "Underwriters") have entered
into an underwriting agreement with respect to the shares being offered. Subject
to customary conditions in the underwriting agreement, each underwriter has
severally agreed to purchase the number of shares indicated in the following
table. Goldman, Sachs & Co., Credit Suisse First Boston Corporation, Dain
Rauscher Incorporated, and Petrie Parkman & Co., Inc. are the representatives of
the Underwriters.
<TABLE>
<CAPTION>
UNDERWRITERS NUMBER OF SHARES
------------ ----------------
<S> <C>
Goldman, Sachs & Co. .......................................
Credit Suisse First Boston Corporation......................
Dain Rauscher Incorporated..................................
Petrie Parkman & Co., Inc. .................................
---------
Total............................................. 7,150,000
=========
</TABLE>
Under the terms and conditions of the underwriting agreement, the
underwriters are committed to take and pay for all of the shares offered hereby,
if any are taken.
If the Underwriters sell more than the total number set forth in the table
above, the Underwriters have an option to buy up to an additional 1,072,500
shares from Encore to cover such sales. They may exercise that option for 30
days. If any shares are purchased pursuant to this option, the Underwriters will
severally purchase shares in approximately the same proportion as set forth in
the table above.
The following table shows the per share and total underwriting discounts
and commissions to be paid to the Underwriters by Encore. Such amounts are shown
assuming both no exercise and full exercise of the Underwriters' option to
purchase additional shares.
PAID BY ENCORE
--------------
<TABLE>
<CAPTION>
NO EXERCISE FULL EXERCISE
----------- -------------
<S> <C> <C>
Per Share................................................... $ $
Total....................................................... $ $
</TABLE>
Shares sold by the Underwriters to the public will initially be offered at
the initial public offering price set forth on the cover of this prospectus. Any
shares sold by the Underwriters to securities dealers may be sold at a discount
of up to $ per share from the initial public offering price. Any such
securities dealers may resell any shares purchased from the Underwriters to
certain other brokers or dealers at a discount of up to $ per share
from the initial public offering price. If all the shares are not sold at the
initial offering price, the representatives may change the offering price and
the other selling terms.
A prospectus in electronic format will be made available on the web sites
maintained by one or more of the joint book-running managers of this offering
and may also be made available on web sites maintained by other underwriters.
The Underwriters may agree to allocate a number of shares to Underwriters for
sale to their online brokerage account holders. Internet distributions will be
allocated by the joint book-running managers to Underwriters that may make
Internet distributions on the same basis as other allocations. Credit Suisse
First Boston Corporation may effect an on-line distribution through its
affiliate, DLJdirect, Inc., an on-line broker/dealer as a selling group member.
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Encore, its officers, directors and principal stockholders have agreed with
the Underwriters not to dispose of or hedge any of their common stock or
securities convertible into or exchangeable for shares of common stock during
the period from the date of this prospectus continuing through the date 180 days
after the date of this prospectus, except with the prior written consent of
Goldman, Sachs & Co. in its sole discretion. This agreement does not apply to
any existing employee benefit plans. See "Shares Available for Future Sale" for
a discussion of certain transfer restrictions.
Prior to the offering, there has been no public market for the shares. The
initial public offering price will be negotiated among Encore and the
representatives. The most important factors to be considered in determining the
initial public offering price of the shares, in addition to prevailing market
conditions, will be Encore's historical performance, estimates of the business
potential and earnings prospects of Encore, an assessment of Encore's management
and the consideration of the above factors in relation to market valuation of
companies in related businesses.
We have made application for listing of the common stock on the New York
Stock Exchange under the symbol "EAC".
In connection with the offering, the Underwriters may purchase and sell
shares of common stock in the open market. These transactions may include short
sales, stabilizing transactions and purchases to cover positions created by
short sales. Shorts sales involve the sale by the Underwriters of a greater
number of shares than they are required to purchase in the offering. "Covered"
short sales are sales made in an amount not greater than the Underwriters'
option to purchase additional shares from Encore in the offering. The
Underwriters may close out any covered short position by either exercising their
option to purchase additional shares or purchasing shares in the open market. In
determining the source of shares to close out the covered short position, the
Underwriters will consider, among other things, the price of shares available
for purchase in the open market as compared to the price at which they may
purchase shares through the overallotment option. "Naked" short sales are any
sales in excess of such option. The Underwriters must close out any naked short
position by purchasing shares in the open market. A naked short position is more
likely to be created if the Underwriters are concerned that there may be
downward pressure on the price of the common stock in the open market after
pricing that could adversely affect investors who purchase in the offering.
Stabilizing transactions consist of various bids for or purchases of common
stock made by the Underwriters in the open market prior to the completion of the
offering.
The Underwriters may also impose a penalty bid. This occurs when a
particular Underwriter repays to the Underwriters a portion of the underwriting
discount received by it because the representatives have repurchased shares sold
by or for the account of such Underwriter in stabilizing or short covering
transactions.
Purchases to cover a short position and stabilizing transactions may have
the effect of preventing or retarding a decline in the market price of Encore's
stock, and together with the imposition of the penalty bid, may stabilize,
maintain or otherwise affect the market price of the common stock. As a result,
the price of the common stock may be higher than the price that otherwise might
exist in the open market. If these activities are commenced, they may be
discontinued at any time. These transactions may be effected on the New York
Stock Exchange, in the over-the-counter market or otherwise.
The Underwriters do not expect sales to discretionary accounts to exceed
five percent of the total number of shares offered.
Encore estimates that its share of the total expenses of the offering,
excluding underwriting discounts and commissions, will be approximately
$1,000,000.
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Encore has agreed to indemnify the several Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933.
Credit Suisse First Boston Corporation, one of the underwriters for this
offering, is a subsidiary of Credit Suisse Group, which indirectly holds a 19.9%
passive minority interest in Warburg, Pincus & Co., the general partner of
Warburg, Pincus Ventures, one of our principal stockholders. Some of the
Underwriters or their affiliates have from time to time provided investment
banking and financial advisory services to us and our affiliates in the ordinary
course of business, for which they have received customary fees, and they may
continue to do so in the future.
NOTICE TO CANADIAN RESIDENTS
RESALE RESTRICTIONS
The distribution of the common stock in Canada is being made only on a
private placement basis exempt from the requirement that we prepare and file a
prospectus with the securities regulatory authorities in each province where
trades of common stock are made. Any resale of the common stock in Canada must
be made under applicable securities laws which will vary depending on the
relevant jurisdiction, and which may require resales to be made under available
statutory exemptions or under a discretionary exemption granted by the
applicable Canadian securities regulatory authority. Purchasers are advised to
seek legal advice prior to any resale of the common stock.
REPRESENTATIONS OF PURCHASERS
By purchasing common stock in Canada and accepting a purchase confirmation
a purchaser is representing to us and the dealer from whom the purchase
confirmation is received that
- the purchaser is entitled under applicable provincial securities laws to
purchase the common stock without the benefit of a prospectus qualified
under those securities laws,
- where required by law, that the purchaser is purchasing as principal and
not as agent, and
- the purchaser has reviewed the text above under Resale Restrictions.
RIGHTS OF ACTION (ONTARIO PURCHASERS)
The securities being offered are those of a foreign issuer and Ontario
purchasers will not receive the contractual right of action prescribed by
Ontario securities law. As a result, Ontario purchasers must rely on other
remedies that may be available, including common law rights of action for
damages or rescission or rights of action under the civil liability provisions
of the U.S. federal securities laws.
ENFORCEMENT OF LEGAL RIGHTS
All of the issuer's directors and officers as well as the experts named
herein may be located outside of Canada and, as a result, it may not be possible
for Canadian purchasers to effect service of process within Canada upon the
issuer or such persons. All or a substantial portion of the assets of the issuer
and such persons may be located outside of Canada and, as a result, it may not
be possible to satisfy a judgment against the issuer or such persons in Canada
or to enforce a judgment obtained in Canadian courts against such issuer or
persons outside of Canada.
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NOTICE TO BRITISH COLUMBIA RESIDENTS
A purchaser of common stock to whom the Securities Act (British Columbia)
applies is advised that the purchaser is required to file with the British
Columbia Securities Commission a report within ten days of the sale of any
common stock acquired by the purchaser in this offering. The report must be in
the form attached to British Columbia Securities Commission Blanket Order BOR
#95/17, a copy of which may be obtained from us. Only one report must be filed
for common stock acquired on the same date and under the same prospectus
exemption.
TAXATION AND ELIGIBILITY FOR INVESTMENT
Canadian purchasers of common stock should consult their own legal and tax
advisors with respect to the tax consequences of an investment in the common
stock in their particular circumstances and about the eligibility of the common
stock for investment by the purchaser under relevant Canadian legislation.
LEGAL MATTERS
The validity of the shares of common stock offered hereby have been passed
upon for Encore by Kelly, Hart & Hallman, P.C., Fort Worth, Texas. Certain legal
matters related to the common stock offered hereby will be passed upon for the
Underwriters by Baker Botts L.L.P., Houston, Texas.
EXPERTS
The audited financial statements included in this prospectus and elsewhere
in the registration statement have been audited by Arthur Andersen LLP,
independent public accountants, as indicated in their reports with respect
thereto, and are included herein in reliance upon the authority of said firm as
experts in giving said reports.
The estimated reserve evaluations and related calculations of Miller &
Lents, Ltd., independent petroleum engineers, have been included in this
prospectus in reliance upon authority of that firm as experts in petroleum
engineering.
WHERE YOU CAN FIND MORE INFORMATION
This prospectus is part of a registration statement we have filed with the
SEC relating to our common stock. As permitted by SEC rules, this prospectus
does not contain all of the information we have included in the registration
statement and the accompanying exhibits and schedules we filed with the SEC. You
may refer to the registration statement, exhibits and schedules for more
information about us and our common stock. You can read and copy the
registration statement, exhibits and schedules at the SEC's Public Reference
Room at 450 Fifth Street, N.W., Washington, D.C. 20549 and at the SEC's regional
offices located at Seven World Trade Center, New York, New York 10048, and at
500 West Madison Street, Chicago, Illinois 60661. You can obtain information
about the operation of the SEC's Public Reference Room by calling the SEC at
1-800-SEC-0330. The SEC also maintains an Internet site that contains reports,
proxy and information statements, and other information regarding issuers that
file electronically with the SEC. The address of that site is
http://www.sec.gov.
Following this offering, we will be required to file current reports,
quarterly reports, annual reports, proxy statements and other information with
the SEC. You may read and copy those reports, proxy statements and other
information at the SEC's Public Reference Room and regional offices or through
its Internet site. We intend to furnish our stockholders with annual reports
that will include a description of our operations and audited consolidated
financial statements certified by an independent public accounting firm.
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GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms commonly
used in the oil and natural gas industry and this prospectus:
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in
reference to oil or other liquid hydrocarbons.
Bbl/D. One stock tank barrel of oil or other liquid hydrocarbons per day.
Bcf. One billion cubic feet of natural gas at standard atmospheric
conditions.
BCFE. One billion cubic feet equivalent of natural gas, calculated by
converting oil to equivalent Mcf at a ratio of six Mcf to one Bbl of oil.
BOE. One barrel of oil equivalent, calculated by converting natural gas to
oil equivalent barrels at a ratio of six Mcf to one Bbl of oil.
BOE/D. One barrel of oil equivalent per day, calculated by converting
natural gas to oil equivalent barrels at a ratio of six Mcf to one Bbl of oil.
Cf. A cubic foot of natural gas measured at standard conditions, which are
60 degreesF and 14.7 psi atmospheric pressure.
CO(2). Carbon dioxide.
Completion. The installation of permanent equipment for the production of
oil or natural gas.
Delay Rentals. Fees paid to the owner of the oil and natural gas lease
prior to the commencement of production.
Developed Acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Development Well. A well drilled within or in close proximity to an area of
known production targeting existing reservoirs.
Direct lifting costs. All direct costs of producing oil and natural gas
after completion of drilling and before removal of production from the property.
Such costs include labor, superintendence, supplies, repairs, maintenance and
direct overhead charges.
Exploratory Well. A well drilled to find and produce oil or natural gas in
an unproved area or to find a new reservoir in a field previously found to be
productive of oil or natural gas in another reservoir.
Finding and Development Costs. Capital costs incurred in the acquisition,
development, exploitation and revisions of proved oil and natural gas reserves,
divided by proved reserve additions.
Gross Acres or Gross Wells. The total acres or wells, as the case may be,
in which we have a working interest.
Horizontal Drilling. A drilling operation in which a portion of the well is
drilled horizontally within a productive or potentially productive formation.
This operation usually yields a well which has the ability to produce higher
volumes than a vertical well drilled in the same formation.
Infill Drilling. A drilling operation in which one or more development
wells is drilled within the proven boundaries of a field between two or more
other wells.
Injector Well or Injector. A well which is used to place liquids or natural
gases into the producing zone during secondary/tertiary recovery operations to
assist in maintaining reservoir pressure and enhancing recoveries from the
field.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent, calculated by converting gas
to oil equivalent barrels at a ratio of six Mcf to one Bbl of oil.
Mcf. One thousand cubic feet of natural gas.
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MMBbl. One million barrels of oil or other liquid hydrocarbons.
MMBtu. One million British thermal units. One British thermal unit is the
amount of heat required to raise the temperature of one pound of water one
degree Fahrenheit.
MMcf. One million cubic feet of natural gas.
MMcf/D. One million cubic feet of natural gas per day.
Net Acres or Net Wells. Gross acres or wells multiplied, as the case may
be, by the percentage working interest owned by us.
Net Production. Production that is owned by Encore less royalties and
production due others.
NYMEX. New York Mercantile Exchange.
Oil. Crude oil or condensate.
Operating Income. Gross oil and natural gas revenue less applicable
production taxes and lease operating expense.
Operator. The individual or company responsible for the exploration,
exploitation and production of an oil or natural gas well or lease.
Present Value of Future Net Revenues or Present Value or PV-10. The pretax
present value of estimated future revenues to be generated from the production
of proved reserves calculated in accordance with SEC guidelines, net of
estimated production and future development costs, using prices and costs as of
the date of estimation without future escalation, without giving effect to
hedging activities, non-property related expenses such as general and
administrative expenses, debt service and depreciation, depletion and
amortization, and discounted using an annual discount rate of 10%.
Proved Developed Reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of oil, natural gas and natural
gas liquids that geological and engineering data demonstrate with reasonable
certainty are recoverable in future years from known reservoirs under existing
economic and operating conditions.
Proved Undeveloped Reserves. Reserves that are expected to be recovered
from new wells on undrilled acreage or from existing wells where a relatively
major expenditure is required for recompletion.
Reserve-To-Production Index or R/P Index. An estimate expressed in years,
of the total estimated proved reserves attributable to a producing property
divided by production from the property for the 12 months preceding the date as
of which the proved reserves were estimated.
Royalty. An interest in an oil and natural gas lease that gives the owner
of the interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
Standardized Measure. Future cash inflows from proved oil and natural gas
reserves, less future development and production costs and future income tax
expenses, discounted at 10% per annum to reflect the timing of future cash
flows. Standardized measure differs from PV-10 because standardized measure
includes the effect of future income taxes.
68
<PAGE> 72
Tertiary Recovery. An enhanced recovery operation that normally occurs
after waterflooding in which chemicals or natural gasses are used as the
injectant.
Waterflood. A secondary recovery operation in which water is injected into
the producing formation in order to maintain reservoir pressure and force oil
toward and into the producing wells.
Working Interest. An interest in an oil and natural gas lease that gives
the owner of the interest the right to drill for and produce oil and natural gas
on the leased acreage and requires the owner to pay a share of the costs of
drilling and production operations.
69
<PAGE> 73
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Encore Acquisition Company
Report of Independent Public Accountants.................. F-1
Consolidated Balance Sheets as of December 31, 1998 and
1999................................................... F-2
Consolidated Statements of Operations for the period from
inception (April 22, 1998) to December 31, 1998 and the
Year ended December 31, 1999........................... F-3
Consolidated Statements of Stockholders' Equity for the
period from inception (April 22, 1998) to December 31,
1998 and the Year ended December 31, 1999.............. F-4
Consolidated Statements of Cash Flows for the period from
inception (April 22, 1998) to December 31, 1998 and the
Year ended December 31, 1999........................... F-5
Notes to Consolidated Financial Statements................ F-6
Consolidated Balance Sheet as of September 30, 2000
(unaudited)............................................ F-18
Consolidated Statements of Operations for the nine months
ended September 30, 1999 and 2000 (unaudited).......... F-19
Consolidated Statements of Cash Flows for the nine months
ended September 30, 1999 and 2000 (unaudited).......... F-20
Notes to Interim Consolidated Financial Statements
(unaudited)............................................ F-21
Cedar Creek Acquisition
Report of Independent Public Accountants.................. F-26
Statements of Revenues and Direct Operating Expenses for
the years ended December 31, 1996, 1997 and 1998 and
the five months ended May 31, 1998 and 1999............ F-27
Notes to Statements of Revenues and Direct Operating
Expenses............................................... F-28
Crockett County Acquisition
Report of Independent Public Accountants.................. F-31
Statements of Revenues and Direct Operating Expenses for
the years ended December 31, 1998 and 1999 and the
quarters ended March 31, 1999 and 2000................. F-32
Notes to Statements of Revenues and Direct Operating
Expenses............................................... F-33
Lodgepole Acquisition
Report of Independent Public Accountants.................. F-36
Statements of Revenues and Direct Operating Expenses for
the years ended December 31, 1998 and 1999 and the
quarters ended March 31, 1999 and 2000................. F-37
Notes to Statements of Revenues and Direct Operating
Expenses............................................... F-38
Indian Basin/Verden Acquisition
Report of Independent Public Accountants.................. F-41
Statements of Revenues and Direct Operating Expenses for
the year ended December 31, 1999 and periods ended June
30, 1999 and 2000...................................... F-42
Notes to Statements of Revenues and Direct Operating
Expenses............................................... F-43
</TABLE>
70
<PAGE> 74
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of
Encore Acquisition Company:
We have audited the accompanying consolidated balance sheets of Encore
Acquisition Company (a Delaware corporation) and subsidiaries as of December 31,
1999 and 1998, and the related consolidated statements of operations,
stockholders' equity and cash flows for year ended December 31, 1999, and the
period from inception (April 22, 1998) to December 31, 1998. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Encore Acquisition Company
and subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for year ended December 31, 1999, and for the
period from inception (April 22, 1998) to December 31, 1998, in conformity with
accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Dallas, Texas
March 10, 2000 (except with
respect to the matters
discussed in Note 13,
as to which the date
is October 6, 2000)
F-1
<PAGE> 75
ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1998 1999
---- ----
(IN THOUSANDS)
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents................................. $ 3,467 $ 6,497
Accounts receivable....................................... 1 9,895
Inventory and other....................................... 7 1,374
--------- ---------
Total Current Assets.............................. 3,475 17,766
--------- ---------
Properties and Equipment, at cost:
Oil and natural gas properties, successful efforts
method................................................. -- 200,686
Accumulated depletion, depreciation and amortization...... -- (5,101)
--------- ---------
195,585
--------- ---------
Other property and equipment.............................. 289 1,304
Accumulated depletion, depreciation and amortization...... (18) (224)
--------- ---------
271 1,080
--------- ---------
Other Assets:
Debt issuance costs, net.................................. -- 498
Bond collateral........................................... -- 463
Commodity contract premiums............................... -- 168
Other..................................................... 5 11
--------- ---------
Total Other Assets................................ 5 1,140
--------- ---------
Total Assets...................................... $ 3,751 $ 215,571
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable.......................................... $ 48 $ 5,979
Accrued liabilities....................................... 8 6,661
--------- ---------
Total Current Liabilities......................... 56 12,640
--------- ---------
Long-term debt.............................................. -- 99,250
Deferred income taxes....................................... -- 1,259
--------- ---------
Total Liabilities................................. 56 113,149
--------- ---------
Commitments and Contingencies............................... -- --
Stockholders' Equity:
Preferred stock, $.01 par value, 1,000 shares authorized,
none issued and outstanding............................ -- --
Class A common stock, $.01 par value, 75,000 shares
authorized 70,019 and 72,522 issued and outstanding.... 1 1
Class B common stock, $.01 par value, 300,000 shares
authorized 294,751 and 294,852 issued and
outstanding............................................ 3 3
Additional paid-in capital................................ 297,158 297,142
Common stock subscription receivable...................... (292,457) (196,719)
Retained earnings......................................... (1,010) 1,995
--------- ---------
Total Stockholders' Equity........................ 3,695 102,422
--------- ---------
Total Liabilities and Stockholders' Equity........ $ 3,751 $ 215,571
========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-2
<PAGE> 76
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
(INCEPTION TO DATE)
APRIL 22, 1998 TO YEAR ENDED
DECEMBER 31, DECEMBER 31,
1998 1999
------------------- ------------
(IN THOUSANDS EXCEPT
PER SHARE DATA)
<S> <C> <C>
Revenues:
Oil................................................. $ -- $ 30,454
Natural gas......................................... -- 810
-------- --------
Total revenues........................................ -- 31,264
Expenses:
Production --
Direct lifting costs................................ -- 8,408
Production, ad valorem and severance tax............ -- 5,427
General and administrative.......................... 1,066 4,047
Depreciation, depletion and amortization............ 18 5,283
-------- --------
Total expenses........................................ 1,084 23,165
-------- --------
Operating income (loss)............................... (1,084) 8,099
-------- --------
Other income (expenses):
Interest............................................ -- (4,037)
Other............................................... 74 202
-------- --------
Total other income (expenses)......................... 74 (3,835)
-------- --------
Income (loss) before income taxes..................... (1,010) 4,264
Provision for income taxes............................ -- (1,259)
-------- --------
Net income (loss)..................................... $ (1,010) $ 3,005
======== ========
Income (loss) per common share:
Basic and diluted................................... $ (5.18) $ 8.20
Weighted average common shares outstanding............ 195,036 366,631
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
<PAGE> 77
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
DECEMBER 31, 1999
<TABLE>
<CAPTION>
RETAINED CLASS A CLASS B
EARNINGS COMMON COMMON PAID-IN SUBSCRIPTION STOCKHOLDERS'
(DEFICIT) STOCK STOCK CAPITAL RECEIVABLE EQUITY
--------- ------- ------- ------- ------------ -------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
STOCKHOLDERS' EQUITY AT
APRIL 22, 1998........ $ -- $ -- $ -- $ -- $ -- $ --
Deficit accumulated
during development
stage................. (1,010) -- -- -- -- (1,010)
Issuance of 70,019
shares of A common
stock and 294,751 of B
common stock.......... -- 1 3 5,114 -- 5,118
Offering costs.......... -- -- -- (413) -- (413)
Common stock
Subscription
Receivable............ -- -- -- 292,457 (292,457) --
------- ---- ---- -------- --------- --------
BALANCE AT DECEMBER 31,
1998.................. (1,010) 1 3 297,158 (292,457) 3,695
------- ---- ---- -------- --------- --------
Net income.............. 3,005 -- -- -- -- 3,005
Offering costs.......... -- -- -- (16) -- (16)
Issuance of 2,503 shares
of A common stock and
101 of B common
stock................. -- -- -- -- 95,738 95,738
------- ---- ---- -------- --------- --------
BALANCE AT DECEMBER 31,
1999.................. $ 1,995 $ 1 $ 3 $297,142 $(196,719) $102,422
======= ==== ==== ======== ========= ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE> 78
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
(INCEPTION TO DATE)
APRIL 22, 1998 TO YEAR ENDED
DECEMBER 31, DECEMBER 31,
1998 1999
------------------- ------------
(IN THOUSANDS)
<S> <C> <C>
Operating Activities
Net income (loss)..................................... $(1,010) $ 3,005
Adjustments to reconcile net income (loss) to net cash
provided (used) by operating activities:
Depreciation, depletion and amortization............ 18 5,283
Deferred taxes...................................... -- 1,259
Other non-cash charges.............................. -- 97
Changes in operating assets and liabilities:
Accounts receivable................................. (1) (9,894)
Other current assets................................ (7) (1,367)
Other assets........................................ (5) (1,208)
Accounts payable and accrued liabilities............ 56 12,584
------- ---------
Cash Provided (Used) by Operating
Activities.......................................... (949) 9,759
Investing Activities
Purchases of other property and equipment........... (289) (1,015)
Acquisition and development of oil and gas
properties....................................... -- (200,686)
------- ---------
Cash Used by Investing Activities..................... (289) (201,701)
Financing Activities
Proceeds from capital calls......................... 5,118 95,738
Offering costs paid................................. (413) (16)
Proceeds from long-term debt........................ 125 100,250
Payments on long-term debt.......................... (125) (1,000)
------- ---------
Cash Provided by Financing Activities................. 4,705 194,972
Increase in Cash and Cash Equivalents................. 3,467 3,030
Cash and Cash Equivalents, Beginning of Period........ -- 3,467
------- ---------
Cash and Cash Equivalents, End of Period.............. $ 3,467 $ 6,497
======= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE> 79
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(IN THOUSANDS EXCEPT PER SHARE DATA)
1. FORMATION OF THE COMPANY AND BASIS OF PRESENTATION
Encore Acquisition Company ("Encore"), a Delaware Corporation, is an
independent (non-integrated) oil and natural gas company in the United States.
We were organized in April 1998 and are engaged in the acquisition, development,
exploitation and production of crude oil and natural gas properties in the
continental United States. Our sole producing area at December 31, 1999 was the
Cedar Creek Anticline located in Southeastern Montana and Southwestern North
Dakota.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
Our consolidated financial statements include the accounts of all
subsidiaries in which we hold a controlling interest. All material intercompany
balances and transactions are eliminated.
OIL AND NATURAL GAS PROPERTIES
We utilize the successful efforts method of accounting for our oil and
natural gas properties. Under this method, all development costs and acquisition
costs of proved properties are capitalized and amortized on a unit-of-production
basis over the remaining life of proved developed reserves or proved reserves,
as applicable. Exploration expenses, including geological and geophysical
expenses and delay rentals, are charged to expense as incurred. Costs of
drilling exploratory wells are initially capitalized, but charged to expense if
and when the well is determined to be unsuccessful. Natural gas volumes are
converted to equivalent barrels at the rate of six Mcf to one barrel.
Encore has adopted Statement of Financial Accounting Standards, No. 121
("SFAS 121"), "Accounting for the Impairment of Long Lived Assets and for Long
Lived Assets to be Disposed Of". Under SFAS 121 we are required to assess the
need for an impairment of capitalized costs of oil and natural gas properties
and other assets. If impairment is indicated based on undiscounted expected
future net cash flows, then it is recognized to the extent that net capitalized
costs exceed discounted expected future net cash flows. During 1999 and 1998, we
did not provide for any such impairments.
The costs of retired, sold or abandoned properties that constitute a part
of an amortization base are charged or credited, net of proceeds, to the
accumulated depreciation, depletion and amortization reserve. Gains or losses
from the disposal of other properties are recognized in the current period.
Expenditures for maintenance, repairs and minor renewals necessary to maintain
properties in operating condition are expensed as incurred. Major replacements
and renewals are capitalized.
INVENTORIES
Inventories are comprised principally of materials and supplies, and are
stated at the lower of cost (determined on an average basis) or market.
INCOME TAXES
Deferred tax assets and liabilities are recognized for future tax
consequences attributable to differences between financial statement carrying
amounts of existing assets and liabilities and their respective tax bases.
Valuation allowances are established when necessary to reduce
F-6
<PAGE> 80
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
deferred tax assets to amounts expected to be realized. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected to be
recovered or settled.
State franchise taxes are also calculated on a stand-alone basis.
REVENUE RECOGNITION
Revenues are recognized from jointly owned properties as oil and natural
gas is produced and sold net of royalties. Revenues from natural gas production
are recorded using the sales method, net of royalties. Under this method,
revenue is recognized based on the cash received rather than the proportionate
share of natural gas produced. Natural gas imbalances at December 31, 1999 and
1998 were zero. Revenues are stated net of any net profits interests held by
others.
HEDGING AND RELATED ACTIVITIES
We use various financial instruments for non-trading purposes in the normal
course of our business to manage and reduce price volatility and other market
risks associated with our crude oil production. This activity is referred to as
hedging. These arrangements are structured to reduce our exposure to commodity
price decreases, but they can also limit the benefit we might otherwise receive
from commodity price increases. Our risk management activity is generally
accomplished through over-the-counter forward contracts. These agreements are
accounted for as hedges using the deferral method of accounting. Gains and
losses resulting from these transactions are deferred and included in other
assets or accrued liabilities, as appropriate, until the physical production
required by the contracts is delivered. At the time of delivery, the resulting
gains and losses are recognized as an adjustment to oil and natural gas sales.
The cash flows related to any recognized gains or losses associated with
these hedges are reported as cash flows from operations. If the hedge is
terminated prior to maturity, gains or losses are deferred and included in
income in the same period as the physical production required by the contracts
is delivered.
We also use derivative instruments in the form of interest rate swaps.
These swaps primarily serve to hedge against interest rate exposure. These
agreements are accounted for as hedges using the accrual method of accounting.
The differences to be paid or received on swaps designated as hedges are
included in interest expense during the period to which the payment or receipt
relates. The related amounts payable to, or receivable from, the counterparties
are included in other assets or accrued liabilities. The cash flows related to
recognized gains or losses associated with these hedges are reported as cash
flows from operations.
The conditions to be met for a derivative instrument to qualify as a hedge
are the following: (1) the item to be hedged exposes us to price or interest
rate risk; (2) the derivative reduces our risk exposure and is designated as a
hedge at the time the derivative contract is entered into; and (3) at the
inception of the hedge and throughout the hedge period there is a high
correlation of changes in the market value of the derivative instrument and the
fair value of the underlying item being hedged. (See Note 12.)
USE OF ESTIMATES
Preparing financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial
F-7
<PAGE> 81
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Estimates with regard to these financial statements include the estimate of
proved oil and natural gas reserve volumes and the estimated future development,
dismantlement and abandonment costs used in determining amortization provisions.
COMPREHENSIVE INCOME
During 1998, Encore adopted Statement of Financial Accounting Standards No.
130 ("SFAS 130") "Reporting Comprehensive Income", which establishes standards
for reporting and display of comprehensive income and its components in a full
set of general purpose financial statements. Comprehensive income includes net
income and other comprehensive income, which includes, but is not limited to,
unrealized gains for marketable securities and future contracts, foreign
currency translation adjustments and minimum pension liability adjustments. SFAS
130 did not have any effect on Encore's financial condition or operations as we
do not have any differences between net income and comprehensive income.
OTHER
All liquid investments with an original maturity of three months or less
are considered to be cash equivalents.
3. OIL AND NATURAL GAS PROPERTIES
Costs, both capitalized and expensed, incurred in oil and natural gas
producing activities were as follows for the year ended December 31, 1999 (in
thousands).
<TABLE>
<S> <C>
Proved Property Acquisition Costs....................... $193,626
Development Costs....................................... 7,060
--------
Total......................................... $200,686
========
</TABLE>
ACQUISITION OF CEDAR CREEK ANTICLINE PROPERTIES
During June 1999, we purchased from Shell Western E&P Inc. their interests
in approximately 475 oil and natural gas properties (450 operated, 25
non-operated) in the Cedar Creek Anticline located in Southeastern Montana and
Southwestern North Dakota for $173.3 million ($171.8 million of proved
properties and $1.5 million of inventory and other equipment).
The acquisition has been accounted for as a purchase. The operating results
of the Shell Western properties have been included in our consolidated financial
statements since the date of acquisition.
F-8
<PAGE> 82
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
During July and October 1999, we purchased additional working interests
within the Cedar Creek Anticline properties from various working interest owners
for $21.8 million. These acquisitions were also accounted for as a purchase and
included in our consolidated financial statements since the date of acquisition.
Pro forma information, as if the acquisitions were consummated on January 1,
1998 is as follows:
Summary Pro Forma Data
<TABLE>
<CAPTION>
FOR THE
YEAR ENDED
DECEMBER 31,
-----------------
1998 1999
---- ----
(UNAUDITED)
<S> <C> <C>
Revenue..................................................... $32,247 $46,509
Net income (loss)........................................... (5,931) 2,155
Earnings per share.......................................... $(30.41) $ 5.88
</TABLE>
4. COMMITMENTS AND CONTINGENCIES
LEASES
We lease office space and equipment. The leases on most of the office space
and equipment contain renewal provisions. The following table summarizes our
estimated minimum future payments under operating leases that have remaining
noncancelable lease terms in excess of one year as of December 31, 1999 (in
thousands):
<TABLE>
<S> <C>
2000........................................................ $292
2001........................................................ 377
2002........................................................ 377
2003........................................................ 377
2004........................................................ 347
2005 and later years........................................ 542
</TABLE>
Our operating lease rental expense was approximately $262,000 in 1999 and
$45,000 in 1998.
5. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Accounts Payable and Accrued liabilities were as follows at December 31 (in
thousands):
<TABLE>
<CAPTION>
1998 1999
---- ----
<S> <C> <C>
Accounts payable trade...................................... $48 $ 4,885
Oil and natural gas revenue payable......................... -- 1,046
Property and production taxes............................... -- 3,342
Net proceeds payable........................................ -- 1,264
Hedge settlements payable................................... -- 1,094
Interest.................................................... -- 606
Other....................................................... 8 403
--- -------
Total............................................. $56 $12,640
=== =======
</TABLE>
F-9
<PAGE> 83
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. INDEBTEDNESS
The following indebtedness was outstanding at December 31 (in thousands):
<TABLE>
<CAPTION>
1998 1999
---- ----
<S> <C> <C>
Credit Agreement............................................ $-- $99,250
--- -------
Total............................................. $-- $99,250
=== =======
</TABLE>
In May 1999, Encore entered into a credit agreement with a group of banks,
due as of May 2004. Commitments under the credit agreement totaled $300 million.
The borrowing base, as established in the credit agreement, was $105 million at
December 31, 1999. During 1999, the average interest rate under the credit
agreement was 7.2 percent. Encore pays certain fees based on the unused portion
of the borrowing base. Covenants, in addition to other requirements, require
maintenance of a current working capital ratio of one to one as defined and
adjusted for unused portions of the credit facility.
Encore has two options with respect to interest rate elections on
borrowings under the credit facility. Encore may either elect an interest rate
equal to:
- the alternate base rate plus the applicable credit spread, which is
called the prime basis; or
- a Eurodollar rate, which is the London Interbank Offered Rate, plus the
applicable credit spread, which is called the LIBOR basis.
The applicable credit spread, as defined in the credit agreement, ranges
from .75% to 1.50% based on borrowing base usage. The LIBOR basis option
provides for one-, two-, three-, six-and twelve-month interest periods.
On May 26, 1998 and August 11, 1998, Encore entered into two separate
unsecured credit agreements with a bank under which it could borrow up to a
total of $150 million and provided for interest to be paid at a rate of 7.25%.
During 1998, borrowings of $125 million were made under the credit agreements.
Upon Encore's initial capital call which was made on August 18, 1998, all
amounts outstanding under the credit agreements were paid and the credit
agreements were canceled.
Consolidated cash payments for interest were $3.4 million and $0.3 million,
respectively for 1999 and 1998.
Encore periodically enters into interest rate swap agreements with the
objective of managing interest rate risk. In 1999, we entered into interest rate
swaps with notional amount of $74.1 million as follows:
<TABLE>
<CAPTION>
LIBOR
NOTIONAL TRANSACTION FIXED PAYMENT
AMOUNT EFFECTIVE DATE TERMINATION DATE TYPE DATES DATES
-------- -------------- ---------------- ----------- ----- -------
<S> <C> <C> <C> <C> <C>
$10,250,000.......... October 29, 1999 October 30, 2000 Fixed Rate Swap 6.20% 3 month
LIBOR
$13,083,333.......... November 30, 1999 November 30, 2001 Fixed Rate Swap 6.26% 3 month
LIBOR
$44,250,000.......... September 1, 1999 September 1, 2002 Fixed Rate Swap 6.23% 3 month
LIBOR
$ 6,500,000.......... October 1, 1999 October 1, 2002 Fixed Rate Swap 6.16% 3 month
LIBOR
</TABLE>
F-10
<PAGE> 84
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As a result of our hedging transactions for interest we realized a pre-tax
loss of approximately $0.1 million in 1999.
7. TAXES
INCOME TAXES
The components of the income tax expense is comprised of the following (in
thousands):
<TABLE>
<CAPTION>
(INCEPTION TO DATE)
APRIL 22, 1998 TO
DECEMBER 31, 1998 1999
------------------- ----
<S> <C> <C>
Federal:
Current............................................ $-- $ --
Deferred........................................... -- 1,038
-- ------
Total federal.............................. -- 1,038
-- ------
State:
Current............................................ -- --
Deferred........................................... -- 221
-- ------
Total state................................ -- 221
-- ------
Income tax expense................................... $-- $1,259
== ======
</TABLE>
Reconciliation of income tax expense with tax at the Federal statutory rate
is as follows (in thousands):
<TABLE>
<CAPTION>
(INCEPTION TO DATE)
APRIL 22, 1998 TO
DECEMBER 31, 1998 1999
------------------- ----
<S> <C> <C>
Income (loss) before income taxes.................... $(1,010) $4,264
======= ======
Tax at statutory rate................................ (344) 1,450
State income taxes, net of federal benefit........... -- 190
Valuation allowance.................................. 342 (342)
Other................................................ 2 (39)
------- ------
Income tax expense................................... $ -- $1,259
======= ======
</TABLE>
The major components of the net deferred tax liability are comprised of the
following at December 31 (in thousands):
<TABLE>
<CAPTION>
1998 1999
---- ----
<S> <C> <C>
Depreciation, depletion and amortization.................... $ 6 $ --
Book basis of oil and natural gas properties in excess of
tax basis................................................. -- 1,655
----- ------
Total deferred tax liabilities.................... 6 1,655
----- ------
Net operating loss carry forward............................ 326 342
Depreciation, depletion and amortization.................... -- 29
Valuation allowance for deferred tax assets................. (342) --
Capitalized start-up costs.................................. 22 25
----- ------
Total deferred tax assets......................... 6 396
----- ------
Net deferred income tax liability........................... $ -- $1,259
===== ======
</TABLE>
F-11
<PAGE> 85
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
At December 31, 1999, Encore had a net operating loss carry forward of
$888,000 which can be carried forward to reduce future Federal income taxes
payable, scheduled to expire in 2018. No cash income tax payments were made in
1999 or 1998.
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes were comprised of the following (in
thousands):
<TABLE>
<CAPTION>
(INCEPTION TO DATE)
APRIL 22, 1998 TO
DECEMBER 31, 1998 1999
------------------- ----
<S> <C> <C>
Production, ad valorem and severance................. $-- $5,427
Property............................................. -- 288
Payroll and other.................................... 51 143
--- ------
Total...................................... $51 $5,858
=== ======
</TABLE>
8. STOCKHOLDERS' EQUITY
PRIVATE PLACEMENT OF COMMON STOCK
On August 18, 1998, Encore entered into a Stock Purchase Agreement and a
Stockholders' Agreement (collectively the "Agreements"), with members of
Encore's management ("Management") and non-management investors (the
"Investors"). Under the terms of the Agreements, 294,901 shares of Class B
Common Stock, par value $0.01 per share ( the "Class B") and 73,725 shares of
Class A Common Stock, par value $0.01 per share ("Class A") were authorized to
be issued for a total amount of committed consideration to be invested in Encore
of $298 million by Management and the Investors.
Significant provisions of the Agreements include, among other terms, that
the Class B shares are to be entitled to a preference distribution equal to 7%
of its original cost calculated per annum compounded annually, and, after
receipt of the original cost plus the preference distribution, the Class B
Shares will be entitled to 80% of the total common equity value of Encore with
Class A Common Stock being entitled to 20% of the total common equity value of
Encore. Additionally, Encore is subject to a five-year period from the closing
date of the Agreements to make capital calls for the amount of committed
consideration.
At December 31, 1999 and 1998, 294,852 and 294,751 shares of Class B and
72,522 and 70,019 shares of Class A are issued and outstanding. The remaining
shares of Class B and shares of Class A are reserved for issuance to future
Management members. The total Management capital commitment for Class A and
Class B shares was approximately $8 million. Total Class A and Class B shares
issued, or reserved for future issuance, to management was 73,725 shares and
4,901 shares, respectively. Encore has reserved for issuance pursuant to
employee stock options shares representing 1% of Encore's shares on a fully
diluted basis. There were no options issued or outstanding at December 31, 1999
or 1998.
Additional capital contributions to Encore may be initiated pursuant to
terms of Subscription Agreements entered into by Management and Investors. Each
subscriber has agreed to contribute additional capital upon call by Encore.
Capital calls may be initiated by Encore on an as needed basis for acquisitions
and other general corporate purposes.
During 1999, capital calls totaling $95.7 million were initiated in order
to fund the acquisitions of oil and natural gas properties.
F-12
<PAGE> 86
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
During 1998, one capital call in the amount of $5 million was initiated in
order to fund Encore's administrative and overhead costs. At December 31, 1998,
certain Management members had pre-funded capital call requirements in the
amount of $123,000. These funds were used to fund the start-up cost and expenses
until closing of the Agreements.
PREFERRED STOCK
Encore has authorized a class of undesignated preferred stock consisting of
1,000 shares, none of which are issued and outstanding. The Board of Directors
has not determined the rights and privileges of holders of such preferred stock
and Encore has no current plans to issue any shares of preferred stock.
9. EARNINGS (LOSS) PER SHARE (EPS)
Encore has adopted Statement of Financial Accounting Standards No. 128
("SFAS 128") "Earnings Per Share". Under SFAS 128, Encore must report basic
earnings per share, which excludes the effect of potentially dilutive
securities, and diluted earnings per share, which excludes the effect of all
potentially dilutive securities.
Earnings (loss) per common share for the periods presented is based on
weighted average common shares outstanding for the period.
The following table reflects earnings (loss) per share data for the periods
ended December 31:
<TABLE>
<CAPTION>
1999 EARNINGS SHARES PER SHARE
---- -------- ------ ---------
<S> <C> <C> <C>
Basic
Net Income (in thousands).......................... $3,005
------
Income Available To Common
Stock-Basic (in thousands)....................... $3,005 366,631 $8.20
======
Diluted
Effect Of Dilutive Securities:
Stock Options...................................... -- --
------ -------
Income Available To Common
Stock-Diluted (in thousands)..................... $3,005 366,631 $8.20
====== ======= =====
</TABLE>
<TABLE>
<CAPTION>
(INCEPTION TO DATE )
APRIL 22, 1998 TO DECEMBER 31, 1998 EARNINGS SHARES PER SHARE
----------------------------------- -------- ------ ---------
<S> <C> <C> <C>
Basic
Net Loss (in thousands)............................ $(1,010)
-------
Loss Available to Common
Stock-Basic (in thousands)....................... $(1,010) 195,036 $(5.18)
=======
Diluted
Effect Of Dilutive Securities:
Stock Options...................................... -- --
------- -------
Loss Available To Common
Stock-Diluted (in thousands)..................... $(1,010) 195,036 $(5.18)
======= ======= ======
</TABLE>
F-13
<PAGE> 87
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. EMPLOYEE BENEFIT PLAN
We make contributions to the Encore Acquisition Company 401(k) Plan, which
is a voluntary and contributory plan for eligible employees. Our contributions,
which are based on a percentage of matching employee contributions, totaled
$126,000 in 1999 and $2,000 in 1998.
11. FINANCIAL INSTRUMENTS
The following table sets forth the book value and estimated fair value of
financial instruments (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1998 1999
---------------- --------------------
BOOK FAIR BOOK FAIR
VALUE VALUE VALUE VALUE
----- ----- ----- -----
<S> <C> <C> <C> <C>
Cash and cash equivalents................ $3,467 $3,467 $ 6,497 $ 6,497
Senior debt.............................. -- -- (99,250) (99,250)
Long-term commodity contract............. -- -- -- (5,494)
Interest rate swaps...................... -- -- -- 746
</TABLE>
The book value of cash and equivalents approximates fair value because of
the short maturity of those instruments. The fair value of senior debt is
presented at face value given its floating rate structure.
We use various financial instruments for non-trading purposes, in the
normal course of our business to manage and reduce price volatility and other
market risks associated with our natural gas and petroleum liquids production.
This activity is referred to as hedging. These arrangements are structured to
reduce our exposure to commodity price decreases, but they can also limit the
benefit we might otherwise receive from commodity price increases. Our risk
management activity is generally accomplished through over-the-counter forward
contract. The counterparties to these transactions are principally major
financial institutions and major oil and natural gas and other industrial
companies. We monitor the creditworthiness of the counterparties and do not
anticipate material nonperformance by the counterparties.
As a result of all of our hedging transactions for crude oil we realized a
pre-tax loss of approximately $4.4 million in 1999.
The following table summarizes our open hedging positions as of December
31, 1999:
<TABLE>
<CAPTION>
FINANCIAL TIME
PRODUCT INSTRUMENT PERIOD VOLUME PRICES
------- ---------- ------ ------ ------
<C> <S> <C> <C> <C>
Jan -- Jun
Oil Collar 2000 500 Bbl/d $17.00/Bbl-$26.52/Bbl
Jan -- Dec
Oil Collar 2000 1000 Bbl/d $16.00/Bbl-$19.15/Bbl
Jan -- Dec
Oil Swap 2000 1000 Bbl/d $16.97/Bbl
Jan -- Dec
Oil Swap 2000 500 Bbl/d $18.20/Bbl
Jan -- Dec
Oil Swap 2001 1000 Bbl/d $16.97/Bbl
Jan -- Dec
Oil Swap 2002 1000 Bbl/d $16.97/Bbl
Jan -- Jun
Oil 3-way Collar 2000 500 Bbl/d $16.00/Bbl/$18.50/Bbl/$20.75/Bbl
Jan -- Dec
Oil 3-way Collar 2000 500 Bbl/d $17.00/Bbl/$20.00/Bbl/$23.35/Bbl
Jan -- Dec
Oil 3-way Collar 2000 500 Bbl/d $17.00/Bbl/$20.00/Bbl/$22.26/Bbl
Jan -- Dec
Oil 3-way Collar 2000 500 Bbl/d $19.00/Bbl/$22.00/Bbl/$24.92/Bbl
Jan -- Dec
Oil 3-way Collar 2001 500 Bbl/d $16.00/Bbl/$19.00/Bbl/$21.65/Bbl
</TABLE>
F-14
<PAGE> 88
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A "collar" is a financial instrument or a combination of financial
instruments which establishes a range of prices to be received relating to a set
commodity volume. This arrangement, in effect, allows us to receive no less than
a stated minimum or floor price per unit of volume and no more than a stated
maximum or ceiling price per unit of volume.
A "swap" is a financial instrument which allows for the exchange of
variable and fixed-rate payment streams based on a specified contract principal
or notional amount of volume.
A "put" is an option contract that gives the holder the right to sell the
underlying commodity at a specified price for a certain fixed period of time.
A "call" is an option contract that gives the holder the right to buy the
underlying commodity at a specified price for a certain fixed period of time.
A "3-way collar" is defined by Encore entering into a cost collar where
Encore pays for the excess premium by selling a put below the floor Encore has
purchased. The effect of the sold put, when combined with a collar, is that if
the price of oil falls below the sold put price, then Encore will receive the
market price plus the spread between the sold put and the floor of the collar.
The fair values (our unrealized pre-tax gain or loss) for 2000 and
thereafter hedged transactions in place as of December 31, 1999 would be a $5.5
million loss for crude oil. This unrealized loss is calculated based on brokers'
forward price quotes and NYMEX forward price quotes as of December 31, 1999,
which for 2000 averaged $22.73 per Bbl for crude oil. The actual gains or losses
we realize from our hedge transactions may vary significantly due to the
fluctuation of prices in the commodity markets. In order to calculate the
unrealized gain/loss, the relevant variables are (1) the type of commodity, (2)
the delivery price and (3) the delivery location. We do not take into account
the time value of money because of the short-term nature of our hedging
instruments. These calculations may be used to analyze the gains and losses we
might realize on our financial hedging contracts and do not reflect the effects
of price changes on our actual physical commodity sales. Crude oil prices
fluctuated between $11.38 per Bbl and $27.98 per Bbl (NYMEX WTI-for delivery at
Cushing, Oklahoma) during 1999.
12. NEW ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative
Instruments and Hedging Activities". This standard requires us to recognize all
of our derivative and hedging instruments in our statements of financial
position as either assets or liabilities and measured at fair value. In
addition, all hedging relationships must be designated, documented and
reassessed periodically. On July 7, 1999, the Financial Accounting Standards
Board delayed the effective date of SFAS 133 for one year. The delay, published
as SFAS No. 137, applies to quarterly and annual financial statements. SFAS 133,
as revised by SFAS No. 137, is effective for all fiscal quarters of all fiscal
years beginning after June 15, 2000. We have not yet quantified the impacts of
adopting SFAS 133 on our financial statements. However, SFAS 133 could increase
volatility in earnings and comprehensive income.
13. SUBSEQUENT EVENTS
On February 23, 2000, Encore executed a purchase and sale agreement to
acquire working interests in 278 wells located in Crockett County Texas
(approximately 130 wells operated, 148 non-operated) for $43 million. The
transaction closed March 30, 2000.
F-15
<PAGE> 89
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
On March 6, 2000, Encore executed a purchase and sale agreement to acquire
working interests in 30 wells, (28 non-operated, 2 operated) located in Stark
County, North Dakota for $35.2 million. The transaction closed March 31, 2000.
On October 6, 2000, the Company filed a registration statement on Form S-1
with the Securities and Exchange Commission for an initial public offering
("IPO") of the Company's common stock. Prior to the IPO, the Company intends to
complete a recapitalization of its current Class A and Class B shares into a
single class of stock. Such recapitalization has not been reflected in the
accompanying financial statements.
SUPPLEMENTAL INFORMATION
OIL & NATURAL GAS PRODUCING ACTIVITIES
The estimates of Encore's proved oil and natural gas reserves, which are
located entirely within the United States, were prepared in accordance with
guidelines established by the Securities and Exchange Commission and the
Financial Accounting Standards Board. Proved oil and natural gas reserve
quantities are based on estimates prepared by Miller and Lents, Ltd., who are
independent petroleum engineers.
Future prices received for production and future production costs may vary,
perhaps significantly from the prices and costs assumed for purposes of these
estimates. There can be no assurance that the proved reserves may not be
developed within the periods indicated or that prices and costs may not remain
constant. Actual production may not equal the estimated amounts used in the
preparation of reserve projections. In accordance with the Securities and
Exchange Commission's guidelines, Encore's estimates of future net cash flows
from the properties and the representative value thereof are made using oil and
natural gas prices in effect as of the dates of such estimates and are held
constant throughout the life of the properties. Average prices used in
estimating net cash flows at December 31, 1999 were $23.50 per barrel for oil
and $2.00 per Mcf for natural gas. The net profits interest on our Cedar Creek
Anticline properties has been deducted from future cash inflows in the
calculation of standardized measure. The Company's reserve quantities have not
been adjusted for the net profits interest. In addition, future net cash flows
have been adjusted for hedge positions outstanding at the end of the year. The
future cash flows are reduced by estimated production costs and development
costs which are based on year-end economic conditions and held constant
throughout the life of the properties and by the estimated effect of future
income taxes based on statutory income tax rates in effect at year end, Encore's
tax basis in its proved oil and natural gas properties and the effect of net
operating loss, investment tax and other carry forwards.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. Oil and natural gas reserve engineering is and must be
recognized as a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in any exact way, and estimates of
other engineers might differ materially from those shown below. The accuracy of
any reserve estimate is a function of the quality of available data and
engineering and estimates may justify revisions. Accordingly, reserve estimates
are often materially different from the quantities of oil and natural gas that
are ultimately recovered. Reserve estimates are integral in management's
analysis of impairments of oil and natural gas properties and the calculation of
depreciation, depletion and amortization on its properties.
F-16
<PAGE> 90
ENCORE ACQUISITION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Estimated net quantities of proved oil and natural gas reserves of Encore
were as follows (in thousands):
<TABLE>
<CAPTION>
NATURAL OIL
OIL GAS EQUIVALENT
(MBbl) (MMcf) (MBOE)
------ ------- ----------
<S> <C> <C> <C>
December 31, 1999
Proved reserves................................ 79,217 12,502 81,301
Proved developed reserves...................... 67,019 10,082 68,699
</TABLE>
The change in proved reserves were as follows for the year ended (in
thousands):
<TABLE>
<CAPTION>
DECEMBER 31, 1999
--------------------------------
NATURAL OIL
OIL GAS EQUIVALENT
(MBbl) (MMcf) (MBOE)
------ ------- ----------
<S> <C> <C> <C>
Reserves at beginning of year.................... -- -- --
Acquisitions of minerals-in-place................ 79,571 12,637 81,678
Extensions and discoveries....................... 1,641 320 1,694
Revisions of estimates........................... -- -- --
Production....................................... (1,995) (455) (2,071)
------ ------ ------
Reserves at end of year.......................... 79,217 12,502 81,301
====== ====== ======
</TABLE>
The standardized measure of discounted estimated future net cash flows and
changes therein related to proved oil and natural gas reserves (in thousands) is
as follows at:
<TABLE>
<CAPTION>
DECEMBER 31, 1999
-----------------
<S> <C>
Future cash inflows......................................... $ 1,633,946
Future production costs..................................... (755,249)
Future development costs.................................... (31,561)
Future income tax expense................................... (258,113)
-----------
Future net cash flows....................................... 589,022
10% annual discount......................................... (329,984)
Standardized measure of discounted estimated future net cash
flows..................................................... $ 259,038
===========
</TABLE>
Primary changes in the standardized measure of discounted estimated future
net cash flows (in thousands) are as follows for the year ended:
<TABLE>
<CAPTION>
DECEMBER 31, 1999
-----------------
<S> <C>
Standardized measure, beginning of year..................... $ --
Net change in sales price, net of production costs........ 13,917
Extensions and discoveries................................ 9,304
Acquisitions of minerals-in-place......................... 349,869
Sales, net of production costs............................ (17,786)
Change in timing and other................................ (18,135)
Net change in income taxes................................ (50,297)
---------
Standardized measure, end of year........................... $ 259,038
=========
</TABLE>
F-17
<PAGE> 91
ENCORE ACQUISITION COMPANY
CONSOLIDATED BALANCE SHEET
AS OF SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
SEPTEMBER 30,
2000
--------------
(UNAUDITED)
(IN THOUSANDS)
<S> <C>
ASSETS
Current Assets:
Cash and cash equivalents................................. $ 1,602
Accounts receivable....................................... 19,482
Inventory and other....................................... 4,358
---------
Total Current Assets........................................ 25,442
---------
Properties and Equipment, at cost -- successful efforts
method:
Producing properties...................................... 317,808
Undeveloped properties.................................... 544
Accumulated depletion, depreciation and amortization...... (19,719)
---------
298,633
---------
Other property and equipment.............................. 1,690
Accumulated depletion, depreciation and amortization...... (501)
---------
1,189
---------
Other Assets:
Debt issuance costs, net.................................. 553
Bond collateral........................................... 484
Commodity contract premiums............................... 4,499
Natural gas imbalances.................................... 486
Other..................................................... 348
---------
Total Other Assets................................. 6,370
---------
Total Assets....................................... $ 331,634
=========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable.......................................... $ 6,650
Accrued liabilities....................................... 14,079
Current portion of note payable........................... 18,190
---------
Total Current Liabilities.......................... 38,919
---------
Long-Term Debt:
Bank debt................................................. 138,500
Note payable.............................................. 4,594
---------
Total Long-Term Debt............................... 143,094
---------
Deferred income taxes....................................... 8,780
---------
Total Liabilities.................................. 190,793
=========
Commitments and Contingencies............................... --
Stockholders' Equity
Preferred stock, $.01 par value, 1,000 shares authorized,
none issued and outstanding............................. --
Class A common stock, $.01 par value, 75,000 shares
authorized 73,725 issued and outstanding................ 1
Class B common stock, $.01 par value, 300,000 shares
authorized 294,901 issued and outstanding............... 3
Additional paid-in capital................................ 298,247
Common stock subscription receivable...................... (175,491)
Notes receivable -- officers and employees................ (21)
Retained earnings......................................... 18,102
---------
Total Stockholders' Equity......................... 140,841
---------
Total Liabilities and Stockholders' Equity......... $ 331,634
=========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-18
<PAGE> 92
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE NINE MONTHS
ENDED SEPTEMBER 30, 2000 AND 1999
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30,
-------------------
1999 2000
---- ----
(UNAUDITED)
(IN THOUSANDS
EXCEPT PER
SHARE DATA)
<S> <C> <C>
Revenues:
Oil....................................................... $ 15,873 $ 65,345
Natural gas............................................... 395 9,566
-------- --------
Total revenues.............................................. 16,268 74,911
Expenses:
Production --
Direct lifting costs................................... 4,430 12,373
Production, ad valorem and severance tax............... 2,824 10,675
General and administrative................................ 2,511 3,845
Depreciation, depletion and amortization.................. 2,966 14,856
-------- --------
Total expenses.............................................. 12,731 41,749
-------- --------
Operating income (loss)..................................... 3,537 33,162
-------- --------
Other income (expenses):
Interest.................................................. (2,148) (7,358)
Other..................................................... 129 416
-------- --------
Total other income (expenses)............................... 2,019 (6,942)
-------- --------
Income (loss) before income taxes........................... 1,518 26,220
Provision for income taxes.................................. (1,067) (10,113)
-------- --------
Net income (loss)........................................... $ 451 $ 16,107
======== ========
Income (loss) per common share:
Basic and diluted........................................... $ 1.24 $ 43.88
Weighted average common shares outstanding.................. 365,044 367,070
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-19
<PAGE> 93
ENCORE ACQUISITION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS
ENDED SEPTEMBER 30, 1999 AND 2000
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30,
--------------------
1999 2000
---- ----
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C>
Operating activities
Net income (loss)........................................... $ 451 $ 16,107
Adjustments to reconcile net income to net cash provided
(used) by operating activities:
Depreciation, depletion and amortization.................. 2,966 14,856
Deferred taxes............................................ 1,067 7,521
Non-cash compensation expense............................. -- 800
Other non-cash charges.................................... 55 94
Changes in operating assets and liabilities:
Accounts receivable....................................... (8,111) (9,587)
Other current assets...................................... (1,785) (2,984)
Other assets.............................................. (1,445) (5,285)
Accounts payable and accrued liabilities.................. 9,074 8,089
--------- --------
Cash provided (used) by operating activities................ 2,272 29,611
Investing activities
Purchases of other property and equipment................. (890) (386)
Acquisition and development of oil and natural gas
properties............................................. (196,093) (82,466)
--------- --------
Cash used by investing activities........................... (196,983) (82,852)
Financing activities
Proceeds from capital calls............................... 95,738 21,510
Repurchase of common stock................................ (16) (95)
Issuance of treasury stock................................ -- 95
Proceeds from notes receivable............................ -- 2
Proceeds from long-term debt.............................. 98,250 88,000
Payments on long-term debt................................ (1,000) (61,166)
--------- --------
Cash provided by financing activities....................... 192,972 48,346
Decrease in cash and cash equivalents....................... (1,739) (4,895)
Cash and cash equivalents, beginning of period.............. 3,467 6,497
--------- --------
Cash and cash equivalents, end of period.................... $ 1,728 $ 1,602
========= ========
Supplemental disclosure of non-cash investing and financing
activities:
Note payable issued for purchase of oil and gas
properties................................................ $ -- $ 35,200
Notes receivable from officers and employees in connection
with capital calls........................................ $ -- $ 23
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-20
<PAGE> 94
ENCORE ACQUISITION COMPANY
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(IN THOUSANDS)
1. FORMATION OF THE COMPANY AND BASIS OF PRESENTATION
Encore Acquisition Company ("Encore"), a Delaware corporation is an
independent (non-integrated) oil and gas company in the United States. We were
organized in April 1998 and are engaged in the acquisition, development,
exploitation and production of crude oil and natural gas properties in North
America. Our producing areas are in the Cedar Creek Anticline located in
Southeastern Montana and Southwestern North Dakota and in Crockett County,
Texas.
2. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
In the opinion of management, the accompanying unaudited consolidated
financial statements contain all adjustments (consisting only of normal
recurring items) necessary to present fairly the financial position of Encore as
of September 30, 2000 and the results of operations and cash flows for the
periods presented. Certain information and footnote disclosures normally
included in financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to the Securities
and Exchange Commission's rules and regulations. The results of operations for
the periods presented are not necessarily indicative of the results to be
expected for the full year. Management believes the disclosures made are
adequate to ensure that the information is not misleading, and suggests that
these financial statements be read in conjunction with Encore's December 31,
1999 audited financial statements.
3. ACQUISITIONS
On March 30, 2000 and March 31, 2000, respectively, we completed
acquisitions of producing properties from Cross Timbers Oil Company ("Cross
Timbers") and Burlington Resources Oil & Gas Company ("Burlington"). The Cross
Timbers acquisition included 282 wells in Crockett County, Texas, 128 of which
we now operate. The Burlington acquisition included six properties in North
Dakota, of which two we now operate. The Cross Timbers properties were purchased
for $43.0 million. The Burlington properties were purchased for $35.2 million,
and the purchase price was financed by a note payable to Burlington for $35.2
million. Capital calls totalling $21.5 million were initiated in March 2000 in
order to fund the Cross Timbers properties.
The Company executed a purchase and sale agreement to acquire working
interests in 160 wells located in Oklahoma and New Mexico (approximately seven
wells operated, 153 non-operated) for $25.4 million. The transaction closed on
August 24, 2000 with an effective date of April 1, 2000.
These acquisitions have been accounted for as purchases. The operating
results of the acquired properties have been included in our consolidated
financial statements since the date of acquisition.
F-21
<PAGE> 95
ENCORE ACQUISITION COMPANY
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
We previously acquired properties in the Cedar Creek Anticline in June,
July and October 1999. The 1999 acquisitions were also accounted for as
purchases, with the operating results of the acquired properties included in our
consolidated financial statements since the date of acquisition. Pro forma
information, as if the 1999 and 2000 acquisitions were consummated on January 1,
1999, is as follows:
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30,
------------------
1999 2000
---- ----
<S> <C> <C>
Revenues.................................................... $65,043 $90,763
Net income.................................................. 7,379 23,636
Earnings per share.......................................... 20.04 64.39
</TABLE>
Encore financed the Burlington acquisition with a $35.2 million note
payable to Burlington. The note payable bears interest at 4% compounded monthly
and is payable in monthly installments, with the last payment due on January 2,
2002. Burlington may demand payment at any time with 45 days notice of all
remaining principal and interest outstanding less a demand premium. In the case
Burlington elects to demand payment, our credit agreement allows Encore
additional borrowings to meet the demand payment. Accordingly, the Burlington
note payable has been classified as a long-term liability at September 30, 2000.
4. STOCKHOLDERS' EQUITY
During 2000, an additional 4,380 shares of Class A common stock were sold
to Company employees. Encore recognizes compensation expense over the vesting
period of the Class A common stock to the extent the estimated fair value of the
Class A common stock exceeds its purchase price on each cash call date. Since no
market exists for Encore's common stock, Encore estimated its fair value based
on an analysis of discounted future cash flows of Encore's oil and natural gas
properties at each cash call date. Using this approach, Encore calculated total
compensation expense of approximately $2.1 million of which $800,000 has been
recorded through September 30, 2000. Encore will record the remaining
compensation expense in general administrative expenses upon successful
completion of the initial public offering.
5. RECAPITALIZATION
When Encore was organized in July 1998, we issued two classes of common
stock, Class A common stock and Class B common stock. The Class A stock, which
was issued to our management stockholders, represents approximately 20% of our
outstanding capital stock. The Class B stock, which was primarily issued to
institutional investors, represents 80% of our outstanding shares. Each of the
management stockholders also purchased Class B stock, and they collectively own
approximately 21.3% of our outstanding capital stock. The two classes are
identical in all respects, except that the purchase price per share for the
Class A shares was substantially less than for the Class B shares, and the Class
B shares are entitled to a preference in dividends and upon liquidation. Before
holders of Class A shares receive any dividends or liquidating distributions,
the holders of the Class B shares must receive as distributions an amount equal
to their total investment in Encore, plus a cumulative return of 7% per annum.
After the holders of the Class B Stock receive this preferential return, the
Class A and Class B Stock will share ratably in all subsequent distributions,
whether as dividends or upon liquidation. This capital structure was designed to
provide our management stockholders with a
F-22
<PAGE> 96
ENCORE ACQUISITION COMPANY
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
20% interest in the incremental value of Encore in excess of the amount
necessary to permit our investor stockholders to recover their investment
together with a 7% return.
Immediately prior to this offering, our Class A and B shares will be
converted into one class of common stock. The conversion will allocate shares
between our management stockholders and investor stockholders on a basis that
gives effect to the Class B preferential return and the Class A subordinated
interest determined on the basis of Encore's valuation in the public offering.
The allocation will not affect the dilution to investors and we do not believe
it will otherwise adversely affect investors in this offering.
Based on a public offering price of $14.00 per share, we estimate that the
Class A shares will be converted into 2,654,840 shares of common stock, or 11.6%
of the outstanding shares immediately prior to this offering, and the Class B
shares will be converted into 20,225,160 shares, or 88.4% of the outstanding
shares.
SUPPLEMENTAL INFORMATION
OIL & NATURAL GAS PRODUCING ACTIVITIES
The estimates of Encore's proved oil and natural gas reserves, which are
located entirely within the United States, were prepared in accordance with
guidelines established by the Securities and Exchange Commission and the
Financial Accounting Standards Board. Proved oil and natural gas reserve
quantities are based on estimates prepared by Miller and Lents, Ltd., who are
independent petroleum engineers, rolled over by Encore to reflect reserve
information at September 30, 2000.
Future prices received for production and future production costs may vary,
perhaps significantly from the prices and costs assumed for purposes of these
estimates. There can be no assurance that the proved reserves will be developed
within the periods indicated or that prices and costs will remain constant.
There can be no assurance that actual production will equal the estimated
amounts used in the preparation of reserve projections. In accordance with the
Securities and Exchange Commission's guidelines, Encore's estimates of future
net cash flows from proved properties and the representative value thereof are
made using oil and natural gas prices in effect as of the dates of such
estimates and are held constant throughout the life of the properties. Average
prices used in estimating net cash flows at September 30, 2000 were as follows:
$28.76, per barrel for oil, and $5.19 for natural gas. The net profits interest
on our Cedar Creek Anticline properties has been deducted from future cash
inflows in the calculation of standardized measure. The Company's reserve
quantities have not been adjusted for the net profits interest. In addition,
future net cash flows have been adjusted for hedge positions outstanding at the
end of the year. The future cash flows are reduced by estimated production costs
and development costs which are based on year-end economic conditions and held
constant throughout the life of the properties and by the estimated effect of
future income taxes based on statutory income tax rates in effect at year end,
Encore's tax basis in its proved oil and natural gas properties and the effect
of net operating loss, investment tax and other carry forwards.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. Oil and natural gas reserve engineering is and must be
recognized as a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in any exact way, and estimates of
other engineers might differ materially from those shown below. The accuracy of
any reserve estimate is a function of the quality of available data and
engineering and
F-23
<PAGE> 97
ENCORE ACQUISITION COMPANY
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
estimates may justify revisions. Accordingly, reserve estimates are often
materially different from the quantities of oil and natural gas that are
ultimately recovered. Reserve estimates are integral in management's analysis of
impairments of oil and natural gas properties and the calculation of
depreciation, depletion and amortization on its properties.
Estimated net quantities of proved oil and natural gas reserves of Encore
were as follows (in thousands):
<TABLE>
<CAPTION>
NATURAL OIL
OIL GAS EQUIVALENT
(MBbl) (MMcf) (MBOE)
------ ------- ----------
<S> <C> <C> <C>
September 30, 2000
Proved Reserves................................... 84,641 67,496 95,890
Proved Developed Reserves......................... 73,703 62,331 84,092
</TABLE>
The changes in proved reserves were as follows for the period ended (in
thousands):
<TABLE>
<CAPTION>
SEPTEMBER 30, 2000
-----------------------------
NATURAL OIL
OIL GAS EQUIVALENT
(MBbl) (MMcf) (MBOE)
------ ------- ----------
<S> <C> <C> <C>
Reserves at beginning of year............................... 79,217 12,502 81,301
Acquisitions of minerals-in-place........................... 3,010 56,902 12,494
Extensions and discoveries.................................. 1,559 191 1,591
Revisions of estimates...................................... 4,046 597 4,146
Production.................................................. (3,191) (2,696) (3,640)
------ ------ ------
Reserves at end of period................................... 84,641 67,496 95,890
====== ====== ======
</TABLE>
The standardized measure of discounted estimated future net cash flows and
changes therein related to proved oil and natural gas reserves (in thousands) is
as follows:
<TABLE>
<CAPTION>
SEPTEMBER 30, 2000
------------------
<S> <C>
Future cash inflows......................................... $2,424,052
Future production costs..................................... (978,081)
Future development costs.................................... (32,511)
Future income tax expense................................... (456,231)
----------
Future net cash flows....................................... 957,229
10% annual discount......................................... (508,772)
----------
Standardized measure of discounted estimated future net cash
flows..................................................... $ 448,457
==========
</TABLE>
F-24
<PAGE> 98
ENCORE ACQUISITION COMPANY
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Primary changes in the standardized measure of discounted estimated future
net cash flows (in thousands) are as follows for the period ended:
<TABLE>
<CAPTION>
SEPTEMBER 30, 2000
------------------
<S> <C>
Standardized measure, beginning of period................... $259,038
Net change in sales prices, net of production costs....... 77,799
Development costs incurred during the year................ 10,682
Revisions of quantity estimates........................... 21,679
Extensions, discoveries and improved recovery, net........ 11,553
Accretion of discount..................................... 32,326
Change in future development costs........................ --
Acquisitions of reserves-in-place......................... 194,266
Sales of reserves in place................................ --
Sales, net of production costs............................ (51,863)
Change in timing and other................................ (21,162)
Net change in income taxes................................ (85,861)
--------
Standardized measure, end of period......................... $448,457
========
</TABLE>
F-25
<PAGE> 99
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of
Encore Acquisition Company:
We have audited the accompanying statements of revenues and direct
operating expense of Shell's interest in certain Montana properties (the
"Properties") acquired by Encore Acquisition Company (the "Company") for each of
the three years in the period ended December 31, 1998. These statements of
revenues and direct operating expenses are the responsibility of the Company's
management. Our responsibility is to express an opinion on these statements of
revenues and direct operating expenses based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the statements of revenues and direct
operating expenses are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the statements of revenues and direct operating expenses. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the statements of
revenues and direct operating expenses. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the statements of revenues and direct operating expenses
referred to above present fairly, in all material respects, the revenues and
direct operating expenses of Shell's interest in the Properties acquired by the
Company for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Dallas, Texas,
October 8, 1999
F-26
<PAGE> 100
CEDAR CREEK ANTICLINE ACQUISITION
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE PERIODS ENDED MAY 31, 1999 AND 1998 AND THE
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
<TABLE>
<CAPTION>
FIVE MONTHS FIVE MONTHS
ENDED ENDED
1996 1997 1998 MAY 31, 1998 MAY 31, 1999
---- ---- ---- ------------ ------------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Oil & natural gas revenues......... $60,418 $56,146 $32,247 $19,336 $14,464
Direct operating expenses
Direct lifting costs............. 17,904 19,418 14,999 6,843 5,987
Production, ad valorem and
severance taxes............... 8,467 6,641 5,440 2,913 2,927
------- ------- ------- ------- -------
Total operating
expenses............... 26,371 26,059 20,439 9,756 8,914
Excess of revenue over direct
operating expenses............... $34,047 $30,087 $11,808 $ 9,580 $ 5,550
======= ======= ======= ======= =======
</TABLE>
F-27
<PAGE> 101
CEDAR CREEK ANTICLINE ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
1. BASIS OF PRESENTATION:
On March 12, 1999, Encore entered into an agreement, effective June 1,
1999, with Shell Western E&P, Inc. and Shell Onshore Ventures, Inc.
(collectively "Shell"), to acquire certain oil and gas producing properties
("Shell Properties"). The acquisition of the Shell Properties closed on June 1,
1999. The total purchase price was allocated to proved properties. The Shell
Properties consist of interests in approximately 450 producing operated and
nonoperated wells in Montana and North Dakota.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of revenues and expenses during the
reported period. Actual results could differ from those estimates.
The oil and natural gas revenues and direct operating expenses presented
herein relate only to the interests in the Shell Properties and do not represent
all of the oil and natural gas operations of Shell. Oil and natural gas revenues
of the Shell Properties are recorded on the entitlements method. Direct
operating expenses include all costs incurred which are necessary for the
production, marketing and distribution of the products produced from the subject
properties including, without limitation, costs and expenses of field
separation; treatment; dehydration; direct overhead charges (other than costs
associated with general corporate activities); pumper, roustabout and field
supervision labor; meter calibrations; engineering supervision charges; fuel and
electricity; valves, connections and other minor equipment repair; oil and
lubricants; major repairs; rental tools and equipment; pipe inspection;
trucking; reservoir testing; pressure testing; well plugging; site remediation;
operator bonding; insurance charges; salt water disposal; water injection and
pressure maintenance; gas compression; hot oil and hot water treatments; filing
fees; make-up water purchases; electrician charges; mud and chemicals; pulling
and workover units; other miscellaneous supplies and services; and severance, ad
valorem and other production related taxes and charges. In addition, oil and
natural gas production taxes include production and severance taxes and ad
valorem taxes associated with the Shell Properties. Direct operating expenses do
not include charges for depletion, depreciation, amortization and abandonment;
Federal and state income taxes; interest; or corporate general and
administrative expenses because the property interests acquired represent only a
portion of a business and the costs incurred by Shell are not necessarily
indicative of the costs to be incurred by Encore. The accompanying statements of
revenue and direct operating expenses are presented for the periods ended May
31, 1999 and 1998 and each of the three years in the period ended December 31,
1998, 1997 and 1996. The oil and natural gas revenues and direct operating
expenses for the periods presented may not be indicative of the results of
future operations of the properties acquired.
Historical financial information reflecting financial position, results of
operations and cash flows of the Shell Properties is not presented because the
acquisition cost was assigned to the oil and natural gas property interests
acquired. Accordingly, the historical statements of revenues and direct
operating expenses have been presented in lieu of the financial statements
required under Rule 3-05 of Securities and Exchange Commission Regulation S-X.
2. SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED):
The estimates of Encore's proved oil and natural gas reserves, which are
located entirely within the United States, were prepared in accordance with
guidelines established by the Securities and Exchange Commission and the
Financial Accounting Standards Board. Proved oil
F-28
<PAGE> 102
CEDAR CREEK ANTICLINE ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
and natural gas reserve quantities are based on estimates prepared by Miller and
Lents, Ltd., who are independent petroleum engineers.
Future prices received for production and future production costs may vary,
perhaps significantly from the prices and costs assumed for purposes of these
estimates. There can be no assurance that the proved reserves will be developed
within the periods indicated or that prices and costs will remain constant.
There can be no assurance that actual production will equal the estimated
amounts used in the preparation of reserve projections. In accordance with the
Securities and Exchange Commission's guidelines, Encore's estimates of future
net cash flows from Encore's proved properties and the representative value
thereof are made using oil and natural gas prices in effect as of the dates of
such estimates and are held constant throughout the life of the properties.
Average prices used in estimating net cash flows at December 31, 1998, December
31, 1997 and December 31, 1996 were as follows: $10.00, $15.56, and $23.82 per
barrel for oil, respectively, and $1.69, $1.95, and $3.72 per Mcf for natural
gas, respectively.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. Oil and natural gas reserve engineering is and must be
recognized as a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in any exact way, and estimates of
other engineers might differ materially from those shown below. The accuracy of
any reserve estimate is a function of the quality of available data and
engineering and estimates may justify revisions. Accordingly, reserve estimates
are often materially different from the quantities of oil and natural gas that
are ultimately recovered. Reserve estimates are integral in management's
analysis of impairments of oil and natural gas properties and the calculation of
depreciation, depletion and amortization on its properties.
Estimated net quantities of proved oil and natural gas reserves of the
Shell Properties were as follows:
<TABLE>
<CAPTION>
NATURAL OIL
OIL GAS EQUIVALENT
(MBbl) (MMcf) (MBOE)
------ ------- ----------
<S> <C> <C> <C>
December 31, 1996
Proved Reserves.................................. 75,867 12,705 77,985
Proved Developed Reserves........................ 65,039 10,558 66,799
December 31, 1997
Proved Reserves.................................. 68,148 11,315 70,034
Proved Developed Reserves........................ 57,369 9,179 58,899
December 31, 1998
Proved Reserves.................................. 54,357 9,276 55,903
Proved Developed Reserves........................ 44,672 7,218 45,875
</TABLE>
F-29
<PAGE> 103
CEDAR CREEK ANTICLINE ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
The changes in proved reserves were as follows for the years ended:
<TABLE>
<CAPTION>
DECEMBER 31, 1996 DECEMBER 31, 1997 DECEMBER 31, 1998
------------------------- ------------------------- ---------------------------
NATURAL OIL NATURAL OIL NATURAL OIL
OIL GAS EQUIV. OIL GAS EQUIV. OIL GAS EQUIV.
(MBbl) (MMcf) (MBOE) (MBbl) (MMcf) (MBOE) (MBbl) (MMcf) (MBOE)
------ ------- ------ ------ ------- ------ ------ ------- ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Reserves at beginning of
year....................... 79,890 13,557 82,150 75,867 12,705 77,985 68,148 11,315 70,034
Revisions of estimates....... -- -- (3,913) (561) (4,007) (9,530) (1,432) (9,769)
Production................... (4,023) (852) (4,165) (3,806) (829) (3,944) (3,458) (606) (3,559)
------ ------ ------ ------ ------ ------ ------- ------ -------
Reserves at end of period.... 75,867 12,705 77,985 68,148 11,315 70,034 55,160 9,277 56,706
====== ====== ====== ====== ====== ====== ======= ====== =======
</TABLE>
The standardized measure of discounted estimated future net cash flows and
changes therein related to proved oil and natural gas reserves (in thousands) is
as follows at:
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31, DECEMBER 31,
1996 1997 1998
------------ ------------ ------------
<S> <C> <C> <C>
Future cash inflows................... $1,602,717 $ 973,855 $ 531,956
Future production costs............... (684,510) (489,536) (299,862)
Future development costs.............. (28,017) (28,017) (28,017)
---------- --------- ---------
Future net cash flows................. 890,190 456,302 204,078
10% annual discount................... (554,278) (278,559) (123,434)
---------- --------- ---------
Standardized measure of discounted
estimated future net cash flows..... $ 335,912 $ 177,742 $ 80,644
========== ========= =========
</TABLE>
Primary changes in the standardized measure of discounted estimated future
net cash flows (in thousands) are as follows for the years ended:
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31, DECEMBER 31,
1996 1997 1998
------------ ------------ ------------
<S> <C> <C> <C>
Standardized measure, beginning of
year................................ $216,189 $ 335,912 $177,742
Net change in sales prices, net of
production costs.................... 128,328 (143,351) (78,850)
Revisions of quantity estimates....... -- (10,318) (15,571)
Accretion of discount................. 21,619 33,591 17,774
Change in timing and other............ -- (11,384) (9,970)
Sales, net of production costs........ (30,224) (26,708) (10,482)
-------- --------- --------
Standardized measure, end of year..... $335,912 $ 177,742 $ 80,644
======== ========= ========
</TABLE>
The standardized measure of discounted future net cash flow of the Cedar
Creek Anticline properties does not include taxes because taxes do not apply at
the property level.
F-30
<PAGE> 104
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of
Encore Acquisition Company:
We have audited the accompanying statements of revenues and direct
operating expense of Cross Timbers Oil Company's interest in certain Texas
properties (the "Properties") acquired by Encore Acquisition Company for the
years ended December 31, 1999 and 1998. These statements of revenues and direct
operating expenses are the responsibility of Encore's management. Our
responsibility is to express an opinion on these statements of revenues and
direct operating expenses based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the statements of
revenues and direct operating expenses are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the statements of revenues and direct operating expenses. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall presentation of
the statements of revenues and direct operating expenses. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the statements of revenues and direct operating expenses
referred to above present fairly, in all material respects, the revenues and
direct operating expenses of Cross Timbers Oil Company's interest in the
Properties acquired by Encore for the years ended December 31, 1999 and 1998 in
conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Dallas, Texas,
September 1, 2000
F-31
<PAGE> 105
CROCKETT COUNTY ACQUISITION
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE QUARTERS ENDED MARCH 31, 2000 AND 1999 AND THE
YEARS ENDED DECEMBER 31, 1999 AND 1998
<TABLE>
<CAPTION>
QUARTER
YEAR ENDED ENDED
DECEMBER 31, MARCH 31,
--------------- ---------------
1998 1999 1999 2000
---- ---- ---- ----
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Oil and natural gas revenues............................ $9,505 $9,177 $1,938 $2,461
Direct operating expenses:
Direct lifting costs.................................. 1,861 1,639 66 406
Production, ad valorem and severance taxes............ 673 594 64 108
------ ------ ------ ------
Total direct operating expenses............... 2,534 2,233 130 514
Excess of revenue over direct operating expenses........ $6,971 $6,944 $1,808 $1,947
====== ====== ====== ======
</TABLE>
F-32
<PAGE> 106
CROCKETT COUNTY ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
1. BASIS OF PRESENTATION:
On March 30, 2000, Encore purchased 282 wells ("Cross Timbers Properties")
in Crockett County, Texas from Cross Timbers Oil Company ("Cross Timbers"). Of
the wells, 128 are operated by Encore. The remaining properties are operated by
other operators. The wells produce natural gas and gas condensate, which is sold
to Enron.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of revenues and
expenses during the reported period. Actual results could differ from those
estimates.
The oil and natural gas revenues and direct operating expenses presented
herein relate only to the interests in the Cross Timbers Properties and do not
represent all of the oil and natural gas operations of Cross Timbers. Oil and
natural gas revenues of the Cross Timbers Properties are recorded on the
entitlements method. Direct operating expenses include all costs incurred which
are necessary for the production, marketing and distribution of the products
produced from the subject properties including, without limitation, costs and
expenses of field separation; treatment; dehydration; direct overhead charges
(other than costs associated with general corporate activities); pumper,
roustabout and field supervision labor; meter calibrations; engineering
supervision charges; fuel and electricity; valves, connections and other minor
equipment repair; oil and lubricants; major repairs; rental tools and equipment;
pipe inspection; trucking; reservoir testing; pressure testing; well plugging;
site remediation; operator bonding; insurance charges; salt water disposal;
water injection and pressure maintenance; gas compression; hot oil and hot water
treatments; filing fees; make-up water purchases; electrician charges; mud and
chemicals; pulling and workover units; other miscellaneous supplies and
services; and severance, ad valorem and other production related taxes and
charges. In addition, oil and natural gas production taxes include production
and severance taxes and ad valorem taxes associated with Cross Timbers
Properties. Direct operating expenses do not include charges for depletion,
depreciation, amortization and abandonment; Federal and state income taxes;
interest; or corporate general and administrative expenses because the property
interests acquired represent only a portion of a business and the costs incurred
by Cross Timbers are not necessarily indicative of the costs to be incurred by
Encore. The accompanying statements of revenue and direct operating expenses are
presented for the quarters ended March 31, 2000 and 1999 and each of the two
years in the period ended December 31, 1999 and 1998. The oil and natural gas
revenues and direct operating expenses for the periods presented may not be
indicative of the results of future operations of the properties acquired.
Historical financial information reflecting financial position, results of
operations and cash flows of the Cross Timbers Properties is not presented
because the acquisition cost was assigned to the oil and gas property interests
acquired. Accordingly, the historical statements of revenues and direct
operating expenses have been presented in lieu of the financial statements
required under Rule 3-05 of Securities and Exchange Commission Regulation S-X.
2. SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED):
The estimates of Encore's proved oil and natural gas reserves, which are
located entirely within the United States, were prepared in accordance with
guidelines established by the Securities and Exchange Commission and the
Financial Accounting Standards Board. Proved oil and natural gas reserve
quantities are based on estimates prepared by Miller and Lents, Ltd., who are
independent petroleum engineers.
F-33
<PAGE> 107
CROCKETT COUNTY ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
Future prices received for production and future production costs may vary,
perhaps significantly from the prices and costs assumed for purposes of these
estimates. There can be no assurance that the proved reserves will be developed
within the periods indicated or that prices and costs will remain constant.
There can be no assurance that actual production will equal the estimated
amounts used in the preparation of reserve projections. In accordance with the
Securities and Exchange Commission's guidelines, Encore's estimates of future
net cash flows from proved properties and the representative value thereof are
made using oil and natural gas prices in effect as of the dates of such
estimates and are held constant throughout the life of the properties. Average
prices used in estimating net cash flows at December 31, 1999 and December 31,
1998 were as follows: $25.50, and $11.95 per barrel for oil, respectively, and
$2.63, and $2.27 per Mcf for natural gas, respectively. The future cash flows
are reduced by estimated production and development costs based on year-end
economic conditions and held constant throughout the life of the properties. The
standardized measure of discounted future net cash flow of the Crockett County
properties does not include taxes because taxes do not apply at the property
level.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. Oil and natural gas reserve engineering is and must be
recognized as a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in any exact way, and estimates of
other engineers might differ materially from those shown below. The accuracy of
any reserve estimate is a function of the quality of available data and
engineering and estimates may justify revisions. Accordingly, reserve estimates
are often materially different from the quantities of oil and natural gas that
are ultimately recovered. Reserve estimates are integral in management's
analysis of impairments of oil and natural gas properties and the calculation of
depreciation, depletion and amortization on its properties.
Estimated net quantities of proved oil and natural gas reserves of the
Properties were as follows:
<TABLE>
<CAPTION>
NATURAL OIL
OIL GAS EQUIVALENT
(MBbl) (MMcf) (MBOE)
------ ------- ----------
<S> <C> <C> <C>
December 31, 1998
Proved reserves................................. 77 38,779 6,540
Proved developed reserves....................... 77 32,315 5,463
December 31, 1999
Proved reserves................................. 73 37,535 6,329
Proved developed reserves....................... 73 31,146 5,264
</TABLE>
F-34
<PAGE> 108
CROCKETT COUNTY ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
The changes in proved reserves were as follows for the years ended:
<TABLE>
<CAPTION>
DECEMBER 31, 1998 DECEMBER 31, 1999
----------------------------- -----------------------------
NATURAL OIL NATURAL OIL
OIL GAS EQUIVALENT OIL GAS EQUIVALENT
(MBbl) (MMcf) (MBOE) (MBbl) (MMcf) (MBOE)
------ ------- ---------- ------ ------- ----------
<S> <C> <C> <C> <C> <C> <C>
Reserves at beginning of
year..................... 75 35,493 5,990 77 38,779 6,540
Revisions of estimates..... 21 7,539 1,278 15 2,487 430
Production................. (19) (4,253) (728) (19) (3,731) (641)
--- ------ ----- --- ------ -----
Reserves at end of
period................... 77 38,779 6,540 73 37,535 6,329
=== ====== ===== === ====== =====
</TABLE>
The standardized measure of discounted estimated future net cash flows and
changes therein related to proved oil and natural gas reserves (in thousands) is
as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1998 DECEMBER 31, 1999
----------------- -----------------
<S> <C> <C>
Future cash inflows....................... $ 89,038 $100,618
Future production costs................... (27,521) (31,388)
Future development costs.................. (4,421) (4,421)
-------- --------
Future net cash flows..................... 57,096 64,809
10% annual discount....................... (23,274) (27,367)
-------- --------
Standardized measure of discounted
estimated future net cash flows......... $ 33,822 $ 37,442
======== ========
</TABLE>
Primary changes in the standardized measure of discounted estimated future
net cash flows (in thousands) are as follows for the years ended:
<TABLE>
<CAPTION>
DECEMBER 31, 1998 DECEMBER 31, 1999
----------------- -----------------
<S> <C> <C>
Standardized measure, beginning of year... $38,030 $33,822
Net change in sales prices, net of
production costs..................... (6,993) 5,706
Revisions of quantity estimates......... 7,171 2,991
Accretion of discount................... 3,803 3,382
Sales, net of production costs.......... (6,971) (6,944)
Change in timing and other.............. (1,218) (1,515)
------- -------
Standardized measure, end of year......... $33,822 $37,442
======= =======
</TABLE>
F-35
<PAGE> 109
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of
Encore Acquisition Company:
We have audited the accompanying statements of revenues and direct
operating expenses of Burlington Resources Oil and Gas Company's interest in
certain North Dakota properties (the "Properties") acquired by Encore
Acquisition Company for the years ended December 31, 1999 and 1998. These
statements of revenues and direct operating expenses are the responsibility of
Encore's management. Our responsibility is to express an opinion on these
statements of revenues and direct operating expenses based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the statements of
revenues and direct operating expenses are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the statements of revenues and direct operating expenses. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall presentation of
the statements of revenues and direct operating expenses. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the statements of revenues and direct operating expenses
referred to above present fairly, in all material respects, the revenues and
direct operating expenses of Burlington Resources Oil and Gas Company's interest
in the Properties acquired by Encore for the years ended December 31, 1999 and
1998, in conformity with accounting principles generally accepted in the United
States.
ARTHUR ANDERSEN LLP
Dallas, Texas,
September 1, 2000
F-36
<PAGE> 110
LODGEPOLE ACQUISITION
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE QUARTERS ENDED MARCH 31, 2000 AND 1999 AND FOR THE
YEARS ENDED DECEMBER 31, 1999 AND 1998
<TABLE>
<CAPTION>
QUARTER
YEAR ENDED ENDED
DECEMBER 31, MARCH 31,
----------------- ---------------
1998 1999 1999 2000
---- ---- ---- ----
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Oil and natural gas revenues.......................... $14,455 $19,803 $3,215 $6,674
Direct operating expenses:
Direct lifting costs................................ 255 252 92 117
Production, ad valorem and severance taxes.......... 761 994 192 320
------- ------- ------ ------
Total direct operating expenses............. 1,016 1,246 284 437
Excess of revenue over direct operating expenses...... $13,439 $18,557 $2,931 $6,237
======= ======= ====== ======
</TABLE>
F-37
<PAGE> 111
LODGEPOLE ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
1. BASIS OF PRESENTATION:
On March 31, 2000, Encore purchased six properties ("Burlington
Properties") in North Dakota from Burlington Resources Oil & Gas Company
("Burlington"). Of the properties, two are operated by Encore and those
properties represent only 2.5% of the total value of the properties. These
properties produce only oil.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of revenues and
expenses during the reported period. Actual results could differ from those
estimates.
The oil and natural gas revenues and direct operating expenses presented
herein relate only to the interests in the Burlington Properties and do not
represent all of the oil and natural gas operations of Burlington. Oil and
natural gas revenues of the Burlington Properties are recorded on the
entitlements method. Direct operating expenses include all costs incurred which
are necessary for the production, marketing and distribution of the products
produced from the subject properties including, without limitation, costs and
expenses of field separation; treatment; dehydration; direct overhead charges
(other than costs associated with general corporate activities); pumper,
roustabout and field supervision labor; meter calibrations; engineering
supervision charges; fuel and electricity; valves, connections and other minor
equipment repair; oil and lubricants; major repairs; rental tools and equipment;
pipe inspection; trucking; reservoir testing; pressure testing; well plugging;
site remediation; operator bonding; insurance charges; salt water disposal;
water injection and pressure maintenance; gas compression; hot oil and hot water
treatments; filing fees; make-up water purchases; electrician charges; mud and
chemicals; pulling and workover units; other miscellaneous supplies and
services; and severance, ad valorem and other production related taxes and
charges. In addition, oil and natural gas production taxes include production
and severance taxes and ad valorem taxes associated with Burlington Properties.
Direct operating expenses do not include charges for depletion, depreciation,
amortization and abandonment; Federal and state income taxes; interest; or
corporate general and administrative expenses because the property interests
acquired represent only a portion of a business and the costs incurred by
Burlington are not necessarily indicative of the costs to be incurred by Encore.
The accompanying statements of revenue and direct operating expenses are
presented for the quarter ended March 31, 2000 and each of the two years in the
period ended December 31, 1999 and 1998. The oil and natural gas revenues and
direct operating expenses for the periods presented may not be indicative of the
results of future operations of the properties acquired.
Historical financial information reflecting financial position, results of
operations and cash flows of the Burlington Properties is not presented because
the acquisition cost was assigned to the oil and gas property interests
acquired. Accordingly, the historical statements of revenues and direct
operating expenses have been presented in lieu of the financial statements
required under Rule 3-05 of Securities and Exchange Commission Regulation S-X.
2. SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED):
The estimates of Encore's proved oil and natural gas reserves, which are
located entirely within the United States, were prepared in accordance with
guidelines established by the Securities and Exchange Commission and the
Financial Accounting Standards Board. Proved oil and natural gas reserve
quantities are based on estimates prepared by Miller and Lents, Ltd., who are
independent petroleum engineers.
F-38
<PAGE> 112
LODGEPOLE ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
Future prices received for production and future production costs may vary,
perhaps significantly from the prices and costs assumed for purposes of these
estimates. There can be no assurance that the proved reserves will be developed
within the periods indicated or that prices and costs will remain constant.
There can be no assurance that actual production will equal the estimated
amounts used in the preparation of reserve projections. In accordance with the
Securities and Exchange Commission's guidelines, Encore's estimates of future
net cash flows from proved properties and the representative value thereof are
made using oil and natural gas prices in effect as of the dates of such
estimates and are held constant throughout the life of the properties. Average
prices used in estimating net cash flows at December 31, 1999 and December 31,
1998 were as follows: $25.05, and $11.51 per barrel for oil, respectively, and
$2.47 and $2.12 per Mcf for natural gas, respectively. The future cash flows are
reduced by estimated production and development costs based on year-end economic
conditions and held constant throughout the life of the properties. The
standardized measure of discounted future net cash flow for the Lodgepole
properties does not include taxes because taxes do not apply at the property
level.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. Oil and natural gas reserve engineering is and must be
recognized as a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in any exact way, and estimates of
other engineers might differ materially from those shown below. The accuracy of
any reserve estimate is a function of the quality of available data and
engineering and estimates may justify revisions. Accordingly, reserve estimates
are often materially different from the quantities of oil and natural gas that
are ultimately recovered. Reserve estimates are integral in management's
analysis of impairments of oil and natural gas properties and the calculation of
depreciation, depletion and amortization on its properties.
Estimated net quantities of proved oil and natural gas reserves of the
Burlington Properties were as follows:
<TABLE>
<CAPTION>
NATURAL OIL
OIL GAS EQUIVALENT
(MBbl) (MMcf) (MBOE)
------ ------- ----------
<S> <C> <C> <C>
December 31, 1998
Proved reserves.................................... 2,628 1,359 2,854
Proved developed reserves.......................... 2,628 1,359 2,854
December 31, 1999
Proved reserves.................................... 2,427 1,154 2,619
Proved developed reserves.......................... 2,427 1,154 2,619
</TABLE>
The changes in proved reserves were as follows for the years ended:
<TABLE>
<CAPTION>
DECEMBER 31, 1998 DECEMBER 31, 1999
----------------------------- --------------------------------
NATURAL OIL NATURAL OIL
OIL GAS EQUIVALENT OIL GAS EQUIVALENT
(MBbl) (MMcf) (MBOE) (MBbl) (MMcf) (MBOE)
------ ------- ---------- ------ ------- ----------
<S> <C> <C> <C> <C> <C> <C>
Reserves at beginning of year....... 3,692 1,958 4,018 2,628 1,359 2,854
Revisions of estimates.............. 371 (112) 352 945 345 1,003
Production.......................... (1,435) (487) (1,516) (1,146) (550) (1,238)
------ ----- ------ ------ ----- ------
Reserves at end of period........... 2,628 1,359 2,854 2,427 1,154 2,619
====== ===== ====== ====== ===== ======
</TABLE>
F-39
<PAGE> 113
LODGEPOLE ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
The standardized measure of discounted estimated future net cash flows and
changes therein related to proved oil and natural gas reserves (in thousands) is
as follows at:
<TABLE>
<CAPTION>
DECEMBER 31, 1998 DECEMBER 31, 1999
----------------- -----------------
<S> <C> <C>
Future cash inflows....................... $33,130 $63,640
Future production costs................... (5,504) (8,762)
Future development costs.................. (311) (311)
------- -------
Future net cash flows..................... 27,315 54,567
10% annual discount....................... (3,218) (7,380)
------- -------
Standardized measure of discounted
estimated future net cash flows......... $24,097 $47,187
======= =======
</TABLE>
Primary changes in the standardized measure of discounted estimated future
net cash flows (in thousands) are as follows for the years ended:
<TABLE>
<CAPTION>
DECEMBER 31, 1998 DECEMBER 31, 1999
----------------- -----------------
<S> <C> <C>
Standardized measure, beginning of year... $ 49,669 $ 24,097
Net change in sales prices, net of
production costs..................... (18,027) 23,588
Revisions of quantity estimates......... 2,884 18,523
Accretion of discount................... 4,967 2,410
Sales, net of production costs.......... (13,439) (18,557)
Change in timing and other.............. (1,957) (2,874)
-------- --------
Standardized measure, end of year......... $ 24,097 $ 47,187
======== ========
</TABLE>
F-40
<PAGE> 114
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders of
Encore Acquisition Company:
We have audited the accompanying statements of revenues and direct
operating expenses of Pioneer Natural Resources USA, Inc.'s interest in certain
southwestern United States properties (the "Properties") acquired by Encore
Acquisition Company for the year ended December 31, 1999. These statements of
revenues and direct operating expenses are the responsibility of Encore's
management. Our responsibility is to express an opinion on these statements of
revenues and direct operating expenses based on our audit.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the statements of
revenues and direct operating expenses are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the statements of revenues and direct operating expenses. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall presentation of
the statements of revenues and direct operating expenses. We believe that our
audit provides a reasonable basis for our opinion.
In our opinion, the statements of revenues and direct operating expenses
referred to above present fairly, in all material respects, the revenues and
direct operating expenses of Pioneer Natural Resources USA, Inc.'s interest in
the Properties acquired by Encore for the year ended December 31, 1999, in
conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Dallas, Texas,
September 15, 2000
F-41
<PAGE> 115
INDIAN BASIN/VERDEN ACQUISITION
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE PERIODS ENDED JUNE 30, 2000 AND 1999
AND THE YEAR ENDED DECEMBER 31, 1999
<TABLE>
<CAPTION>
SIX MONTHS SIX MONTHS
ENDED ENDED
1999 JUNE 30, 1999 JUNE 30, 2000
---- ------------- -------------
(UNAUDITED)
<S> <C> <C> <C>
Oil and natural gas revenues....................... $9,433 $4,395 $4,882
Direct operating expenses:
Direct lifting costs............................. 2,257 1,195 1,259
Production, ad valorem and severance taxes....... 942 532 481
------ ------ ------
Total direct operating expenses.................... 3,199 1,727 1,740
Excess of revenue over direct operating expenses... $6,234 $2,668 $3,142
====== ====== ======
</TABLE>
F-42
<PAGE> 116
INDIAN BASIN/VERDEN ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
1. BASIS OF PRESENTATION:
On September 1, 2000, Encore purchased properties ("Pioneer properties") in
the southwestern United States from Pioneer Natural Resources USA, Inc.
("Pioneer") for $25.4 million.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of revenues and
expenses during the reported period. Actual results could differ from those
estimates.
The oil and natural gas revenues and direct operating expenses presented
herein relate only to the interests in the Pioneer Properties and do not
represent all of the oil and natural gas operations of Pioneer. Oil and natural
gas revenues of the Pioneer Properties are recorded on the entitlements method.
Direct operating expenses include all costs incurred which are necessary for the
production, marketing and distribution of the products produced from the subject
properties including, without limitation, costs and expenses of field
separation; treatment; dehydration; direct overhead charges (other than costs
associated with general corporate activities); pumper, roustabout and field
supervision labor; meter calibrations; engineering supervision charges; fuel and
electricity; valves, connections and other minor equipment repair; oil and
lubricants; major repairs; rental tools and equipment; pipe inspection;
trucking; reservoir testing; pressure testing; well plugging; site remediation;
operator bonding; insurance charges; salt water disposal; water injection and
pressure maintenance; gas compression; hot oil and hot water treatments; filing
fees; make-up water purchases; electrician charges; mud and chemicals; pulling
and workover units; other miscellaneous supplies and services; and severance, ad
valorem and other production related taxes and charges. In addition, oil and
natural gas production taxes include production and severance taxes and ad
valorem taxes associated with the Pioneer Properties. Direct operating expenses
do not include charges for depletion, depreciation, amortization and
abandonment; Federal and state income taxes; interest; or corporate general and
administrative expenses because the property interests acquired represent only a
portion of a business and the costs incurred by Pioneer are not necessarily
indicative of the costs to be incurred by Encore. The accompanying statements of
revenue and direct operating expenses are presented for the periods ended June
30, 2000 and 1999 and the year ended December 31, 1999. The oil and natural gas
revenues and direct operating expenses for the periods presented may not be
indicative of the results of future operations of the properties acquired.
Historical financial information reflecting financial position, results of
operations and cash flows of the Pioneer Properties is not presented because the
acquisition cost was assigned to the oil and gas property interests acquired.
Accordingly, the historical statements of revenues and direct operating expenses
have been presented in lieu of the financial statements required under Rule 3-05
of Securities and Exchange Commission Regulation S-X.
2. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED):
The estimates of Encore's proved oil and natural gas reserves, which are
located entirely within the United States, were prepared in accordance with
guidelines established by the Securities and Exchange Commission and the
Financial Accounting Standards Board. Proved oil and natural gas reserve
quantities are based on estimates prepared by Miller and Lents, Ltd., who are
independent petroleum engineers.
Future prices received for production and future production costs may vary,
perhaps significantly from the prices and costs assumed for purposes of these
estimates. There can be no assurance that the proved reserves will be developed
within the periods indicated or that
F-43
<PAGE> 117
INDIAN BASIN/VERDEN ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
prices and costs will remain constant. There can be no assurance that actual
production will equal the estimated amounts used in the preparation of reserve
projections. In accordance with the Securities and Exchange Commission's
guidelines, Encore's estimates of future net cash flows from proved properties
and the representative value thereof are made using oil and natural gas prices
in effect as of the dates of such estimates and are held constant throughout the
life of the properties. Average prices used in estimating net cash flows at
December 31, 1999 were $24.40 per barrel for oil and $2.08 per Mcf for natural
gas. The future cash flows are reduced by estimated production costs and
development costs which are based on year-end economic conditions and held
constant throughout the life of the properties. The standardized measure of
discounted net cash flow for the Indian Basin/Verden properties does not include
taxes because taxes do not apply at the property level.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. Oil and natural gas reserve engineering is and must be
recognized as a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in any exact way, and estimates of
other engineers might differ materially from those shown below. The accuracy of
any reserve estimate is a function of the quality of available data and
engineering and estimates may justify revisions. Accordingly, reserve estimates
are often materially different from the quantities of oil and natural gas that
are ultimately recovered. Reserve estimates are integral in management's
analysis of impairments of oil and natural gas properties and the calculation of
depreciation, depletion and amortization on its properties.
Estimated net quantities of proved oil and natural gas reserves of the
Pioneer Properties were as follows:
<TABLE>
<CAPTION>
NATURAL OIL
OIL GAS EQUIVALENT
(MBbl) (MMcf) (MBOE)
------ ------- ----------
<S> <C> <C> <C>
December 31, 1999
Proved reserves................................... 318 19,288 3,533
Proved developed reserves......................... 318 19,288 3,533
</TABLE>
The change in proved reserves were as follows for the year ended:
<TABLE>
<CAPTION>
DECEMBER 31, 1999
-----------------------------
NATURAL OIL
OIL GAS EQUIVALENT
(MBbl) (MMcf) (MBOE)
------ ------- ----------
<S> <C> <C> <C>
Reserves at beginning of year....................... 234 22,070 3,912
Revisions of estimates.............................. 231 645 339
Production.......................................... (147) (3,427) (718)
---- ------ -----
Reserves at end of period........................... 318 19,288 3,533
==== ====== =====
</TABLE>
F-44
<PAGE> 118
INDIAN BASIN/VERDEN ACQUISITION
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
The standardized measure of discounted estimated future net cash flows and
changes therein related to proved oil and natural gas reserves (in thousands) is
as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
1999
------------
<S> <C>
Future cash inflows......................................... $ 46,823
Future production costs..................................... (17,263)
Future development costs.................................... (6)
--------
Future net cash flows....................................... 29,554
10% annual discount......................................... (10,700)
--------
Standardized measure of discounted estimated future net cash
flows..................................................... $ 18,854
========
</TABLE>
Primary changes in the standardized measure of discounted estimated future
net cash flows (in thousands) are as follows for the year ended:
<TABLE>
<CAPTION>
DECEMBER 31,
1999
------------
<S> <C>
Standardized measure, beginning of year..................... $16,691
Net change in sales prices, net of production costs....... 5,253
Revisions of quantity estimates........................... 1,889
Accretion of discount..................................... 1,669
Sales, net of production costs............................ (6,234)
Change in timing and other................................ (414)
-------
Standardized measure, end of year........................... $18,854
=======
</TABLE>
F-45
<PAGE> 119
ANNEX
A
<TABLE>
<S> <C> <C>
MILLER AND LENTS, LTD. MARTIN G. MILLER
INTERNATIONAL OIL AND GAS CONSULTANTS (1948-1980)
[50 Years Logo] TWENTY-SEVENTH FLOOR MAX R. LENTS
1100 LOUISIANA KENNETH B. FORD
HOUSTON, TEXAS 77002-5216 JAMES C. PEARSON
TELEPHONE 713 651-9455 GREGORY W. ARMES
TELEFAX 713 654-9914 S. J. STIEBER
e-mail: [email protected] LARRY M. GRING
JAMES A. COLE
September 11, 2000 CHRISTOPHER A. BUTTA
R. W. FRAZIER
WILLIAM P. KOZA
CHARLES G. GUFFEY
MICHAEL S. YOUNG
GEORGE SCHAEFER
GARY B. KNAPP
LUCY B. KING
R. LEE COMER
CARL D. RICHARD
LESLIE A. FALLON
STEVEN C. MILLS
GUY M. MILLER
THUY T. TRAN
ROBERT J. OBERST
</TABLE>
Encore Acquisition Partners, Inc.
777 Main Street, Suite 1400
Fort Worth, Texas 76102
Re: Encore Acquisition Partners, Inc.
Reserves and Future Net Revenue
As of June 30, 2000
SEC Case
Gentlemen:
At your request, we estimated the proved reserves and projected future net
revenue as of June 30, 2000, attributable to the Encore Acquisition Partners,
Inc. (Encore) net interests in properties located in southeastern Montana, North
Dakota, and Texas. The properties include approximately 1,007 active producing
and injection wells of which 653 are operated by Encore.
We performed our evaluations, designated as the SEC Case, using unescalated
prices, operating expenses, and capital expenditures provided by Encore. The
aggregate results of our evaluation are as follows:
RESERVES AND FUTURE NET REVENUE
AS OF JUNE 30, 2000
<TABLE>
<CAPTION>
FUTURE NET REVENUE
NET RESERVES -----------------------------
------------------- DISCOUNTED AT
OIL, GAS, UNDISCOUNTED, 10% PER YEAR,
RESERVE CATEGORY MBbls MMcf $M $M
---------------- -------- -------- ------------- -------------
<S> <C> <C> <C> <C>
Proved Producing.............. 72,352.4 41,105.3 1,213,668.6 518,186.6
Proved Nonproducing........... 152.9 1,753.7 8,747.4 4,853.8
Proved Undeveloped............ 12,210.5 8,766.6 215,454.0 65,940.4
-------- -------- ----------- ---------
Total Proved........ 84,715.8 51,625.6 1,437,870.0 588,980.8
</TABLE>
A-1
<PAGE> 120
Encore Acquisition Partners, Inc.
September 11, 2000
Page 2
Proved reserves and future net revenue were estimated in accordance with
the standards of the Securities and Exchange Commission Regulation S-X, Rule
4-10. The Securities and Exchange Commission definition of proved reserves is
shown in the Appendix. Gas volumes for each property are stated at the pressure
and temperature bases appropriate for the sales contract or state regulatory
authority. Total gas reserves were obtained by summing the reserves for all the
individual properties and are therefore stated herein at a mixed pressure base.
No provisions for the possible consequences, if any, of product sales imbalances
were included in our projections since we have received no relevant data.
Future net revenue as used herein is defined as the total revenue
attributable to (1) Encore's working interest less royalties, overriding
royalties, production and ad valorem taxes, operating costs, net proceeds
interest payments, and future capital expenditures and (2) Encore's royalty
interest less production and ad valorem taxes. Our projections of future net
revenue are shown both undiscounted and discounted at 10 percent per annum. The
effects of depreciation, depletion, or Federal Income Tax are not considered. We
assumed that abandonment costs would be equal to salvage values at abandonment.
Future costs, if any, for restoration of producing properties to satisfy
environmental standards are not deducted from estimates of future net revenue as
such are beyond the scope of our assignment. Estimates of future net revenue and
discounted future net revenue are not intended and should not be interpreted to
represent fair market value for the estimated reserves.
Encore provided benchmark prices of $32.50 per barrel and $4.33 per Mcf
that represent market prices on June 30, 2000 in accordance with Securities and
Exchange Commission guidelines. Price adjustments were made for each property
based on differentials between benchmark and actual prices as estimated by
Encore and include considerations such as gas Btu, oil gravity, and
transportation charges. Operating costs were based on actual costs as of June
30, 2000 as provided by Encore. Costs were held constant for the remaining
economic life of each property. Future capital was unescalated.
Future production and net revenue forecasts for properties are included as
exhibits to this report and are identified in the Index to Exhibits. The summary
section shows combined and proved reserves for all fields and contains cash
flows by reserve category. The remaining exhibits are grouped into three main
Encore production regions: (1) Cedar Creek Anticline, (2) Crockett County,
Texas, and (3) Lodgepole.
Cedar Creek Anticline (CCA) is a 100-mile-long by 6-mile-wide structure
located in southeastern Montana and western North Dakota. Primary producing
formations are the Red River at 8,800 feet, the Stony Mountain at 8,600 feet,
and the Interlake at 8,300 feet. The productive intervals are geologically
continuous, but CCA has been subdivided into several regulatory fields. A large
portion of properties owned by Encore in the CCA fields are burdened by net
proceeds interest (NPI) payments. Exhibits for CCA properties are summarized by
keycodes that represent units or areas of common interest at which NPI payments
are calculated. A keycode is the lowest level at which NPI payments are
calculated. The one-line summary of reserves and future net revenues for
individual wells, by keycode, are prior to deducting NPI payments. NPI payments
are deducted at the keycode total lines. The modeling and calculation of NPI
payments were provided by Encore and were not verified by Miller and Lents, Ltd.
as such was beyond the scope of our evaluation.
A-2
<PAGE> 121
Encore Acquisition Partners, Inc.
September 11, 2000
Page 3
Crockett County, Texas properties are located in the Val Verde Basin of
West Texas with production from four regulatory fields: Ozona, Hunt-Baggett,
Davidson Ranch, and Henderson. Primary producing formations are the Strawn
carbonates at 8,500 feet and the Canyon sandstones at 7,500 feet. The fields are
typically developed on 40-acre spacing. Exhibits are summarized by property
designation; i.e., operated, non-operated, or royalty; field, and reserve
category.
Lodgepole properties consist of both working and overriding royalty
interests in six fields located in Stark County, North Dakota near the city of
Dickinson. The primary producing formation is the Mississippian-age Waulsortian
mound. Of the six evaluated, the major field is the Eland, Lodgepole Unit, which
has a 200-foot-thick oil column extending over 4,133 acres. In this unit, water
is injected in the bottom water portion of the reservoir to maintain pressure,
and oil is produced from wells completed high on the structure. Exhibits for the
six properties in this production region are summarized by unit.
Proved producing reserves were based primarily on extrapolation of
historical performance trends. We relied mainly on production rate versus time
decline curves. In those wells producing at high water-cuts, water-oil ratios
versus cumulative production trends were used to estimate reserves. Estimates
and projections for proved nonproducing and proved undeveloped reserves were
based on volumetric calculations or analogies. Reserve estimates from analogies
and volumetric calculations are often less certain than reserve estimates based
on well performance obtained over a period during which a substantial portion of
the reserves were produced.
In conducting this evaluation, we relied upon production histories, well
test data, well logs, and other engineering and geological data supplied by
Encore. To a lesser extent, non-confidential data existing in the files of
Miller and Lents, Ltd. and data from commercial services and of public record
were used. The operating expenses, ownership interests, reversion provisions,
current payout status, NPI payments, and product prices were provided by Encore.
We also relied upon Encore's representations to us of planned schedules and the
estimated costs for future well work. None of this information was independently
verified as such was beyond the scope of our assignment.
The evaluations presented in this report, with the exception of those
parameters specified by others, reflect our informed judgment based on accepted
standards of professional investigation but are subject to those generally
recognized uncertainties associated with interpretation of geological,
geophysical, and engineering information. Government policies and market
conditions different from those employed in this study may cause the total
quantity of oil or gas to be recovered, actual production rates, prices
received, or operating and capital costs to vary from those presented in this
report.
A-3
<PAGE> 122
Encore Acquisition Partners, Inc.
September 11, 2000
Page 4
Miller and Lents, Ltd. is an independent oil and gas consulting firm. No
director, officer, or key employee of Miller and Lents, Ltd. has any financial
ownership in Encore or any affiliate of Encore. Our compensation for the
required investigations and preparation of this report is not contingent upon
the results obtained and reported, and we have not performed other work that
would affect our objectivity. Production of this report was supervised by an
officer of the firm who is a professionally qualified and licensed Professional
Engineer in the State of Texas with more than five years of relevant experience
in the estimation, assessment, and evaluation of oil and gas reserves.
Very truly yours,
MILLER AND LENTS, LTD.
By /s/ CARL D RICHARD
Carl D. Richard
By /s/ JAMES C PEARSON
James C. Pearson
Chairman
CDR/psh
A-4
<PAGE> 123
APPENDIX
PROVED RESERVES DEFINITIONS
IN ACCORDANCE WITH
SECURITIES AND EXCHANGE COMMISSION REGULATION S-X
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e., prices
and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements but not on
escalations based upon future conditions.
1. Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes (a) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any, and
(b) the immediately adjoining portions not yet drilled but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir.
2. Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in
the proved classification when successful testing by a pilot project or
the operation of an installed program in the reservoirs provides support
for the engineering analysis on which the project or program was based.
3. Estimates of proved reserves do not include the following:
a. Oil that may become available from known reservoirs but is
classified separately as indicated additional reserves.
b. Crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as to geology,
reservoir characteristics, or economic factors.
c. Crude oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects.
d. Crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite, and other such sources.
Depending upon their status of development, proved reserves are subdivided
into proved developed reserves and proved undeveloped reserves.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to
be recovered though existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as proved
developed reserves only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
<PAGE> 124
PROVED UNDEVELOPED OIL AND GAS RESERVES
Proved Undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
<PAGE> 125
------------------------------------------------------
------------------------------------------------------
No dealer, salesperson or other person is authorized to give any
information or to represent anything not contained in this prospectus. You must
not rely on any unauthorized information or representations. This prospectus is
an offer to sell only the shares offered hereby, but only under circumstances
and in jurisdictions where it is unlawful to do so. The information contained in
this prospectus is current only as of its date.
----------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Summary................................... 1
Risk Factors.............................. 8
Special Note Regarding Forward-Looking
Statements.............................. 15
Use of Proceeds........................... 17
Dividend Policy........................... 17
Recapitalization.......................... 17
Dilution.................................. 18
Capitalization............................ 19
Pro Forma Financial Statements............ 20
Selected Consolidated Financial Data...... 27
Management's Discussion and Analysis of
Financial Condition and Results of
Operations.............................. 29
Business.................................. 37
Properties................................ 42
Regulatory Matters........................ 46
Management................................ 49
Committees of the Board of Directors...... 51
Compensation.............................. 52
Certain Transactions...................... 55
Security Ownership of Management and
Certain Beneficial Holders.............. 57
Description of Capital Stock.............. 59
Shares Available for Future Sale.......... 61
Underwriting.............................. 63
Notice to Canadian Residents.............. 65
Legal Matters............................. 66
Experts................................... 66
Where You Can Find More Information....... 66
Glossary of Oil and Natural Gas Terms..... 67
Index to Consolidated Financial
Statements.............................. 70
Report of Independent Public
Accountants............................. F-1
Miller and Lents, Ltd. Report............. A-1
</TABLE>
----------------------
Through and including , 2001 (the 25th day after the date of
this prospectus), all dealers effecting transactions in these securities,
whether or not participating in this offering, may be required to deliver a
prospectus. This is in addition to a dealer's obligation to deliver a prospectus
when acting as an underwriter and with respect to an unsold allotment or
subscription.
------------------------------------------------------
------------------------------------------------------
------------------------------------------------------
------------------------------------------------------
7,150,000 Shares
ENCORE ACQUISITION COMPANY
Common Stock
-----------------------------
[ENCORE LOGO]
-----------------------------
GOLDMAN, SACHS & CO.
CREDIT SUISSE FIRST BOSTON
DAIN RAUSCHER WESSELS
PETRIE PARKMAN & CO.
Representatives of the Underwriters
------------------------------------------------------
------------------------------------------------------
<PAGE> 126
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13 OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
The estimated expenses in connection with the issuance and distribution of
the securities being registered, other than underwriting discounts and
commissions are set forth in the following table. Encore will pay all expenses
of issuance and distribution. Each amount, except for the SEC and New York Stock
Exchange fees, is estimated.
<TABLE>
<S> <C>
SEC registration fees....................................... $ 26,500
NASD filing fee............................................. $ 10,500
New York Stock Exchange application listing fee............. $ 200,000
Transfer agent's and registrar's fees and expenses.......... $ 3,600
Printing and engraving expenses............................. $ 100,000
Legal fees and expenses..................................... $ 200,000
Accounting fees and expenses................................ $ 400,000
Engineering fees and expenses............................... $ 50,000
Miscellaneous............................................... $ 9,400
----------
Total............................................. $1,000,000
==========
</TABLE>
---------------
ITEM 14 INDEMNIFICATION OF DIRECTORS AND OFFICERS
Our Certificate of Incorporation provides that no director or officer shall
be personally liable to us or our stockholders for monetary damages for breach
of fiduciary duties as a director for any act or omission; provided, however,
that the director may be liable for any claim resulting from an act or omission
that has not met the standard of conduct permissible under the Delaware General
Corporation Law to indemnify the director or officer for the amount claimed.
Our Certificate of Incorporation and our Bylaws provide that we shall
indemnify any person who was or is a party or is threatened to be made a party
to any threatened, pending or completed action, suit or proceeding, whether
civil, criminal, administrative or investigative (other than an action by or in
our right) by reason of the fact that he is or was a director or officer of
Encore, or is or was serving at our request as a director, officer, employee or
agent of another corporation, partnership, joint venture, trust or other
enterprise, against expenses (including attorneys' fees), judgments, fines and
amounts paid in settlement actually and reasonably incurred by him in connection
with such action, suit or proceeding if he acted in good faith and in a manner
he reasonably believed to be in or not opposed to our best interests, and with
respect to any criminal action or proceeding, had no reasonable cause to believe
his conduct was unlawful. Subject to the foregoing, we shall indemnify any
person who was or is a party or is threatened to be made a party to any
threatened, pending or completed action or suit by or in our right to procure a
judgment in our favor by reason of the fact that he is or was a director or
officer, or is or was serving at our request as a director, officer, employee or
agent of another corporation, partnership, joint venture, trust or other
enterprise against expenses (including attorneys' fees) actually and reasonably
incurred by him in connection with the defense or settlement of such action or
suit if he acted in good faith and in a manner he reasonably believed to be in
or not opposed to our best interests and except that no indemnification shall be
made in respect of any claim, issue or matter as to which such person shall have
been adjudged to be liable to Encore unless and only to the extent that the
Delaware Court of Chancery or the court in which such action or suit was brought
shall determine upon application that, despite the adjudication of liability but
in view of all the circumstances of the case, such person is fairly and
reasonably entitled to indemnity for such expenses which the Delaware Court of
Chancery or such other court shall deem proper. Pursuant to our Certificate of
Incorporation and Bylaws, we
II-1
<PAGE> 127
may purchase and maintain insurance on behalf of any person who is or was a
director or officer, or is or was a director or officer of Encore serving at our
request as a director, officer, employee or agent of another corporation,
partnership, joint venture, trust, employee benefit plan or other enterprise
against any liability asserted against him and incurred by him in any such
capacity, or arising out of his status as such, whether or not we would have the
power or the obligation to indemnify him against such liability. Under the
Certificate of Incorporation and Bylaws, we may, to the extent authorized from
time to time by our Board of Directors, provide rights to indemnification and
the advancement of expenses to our employees and agents similar to those rights
conferred in our Certificate of Incorporation and Bylaws to our directors and
officers.
We have entered into indemnification agreements with our directors and
officers, which indemnify each person to the fullest extent permitted by
Delaware law and obligate us to purchase and maintain insurance or similar
protection on behalf of our directors and officers against personal liability
against him or incurred by or on behalf of him in the capacity as a director or
officer of Encore. Any insurance policy providing liability coverage for
directors and officers of Encore shall continue until as long as the director or
officer serves in such capacity. Pursuant to the agreements, we also agree to
hold harmless and indemnify each person against expenses incurred by reason of
the fact that the person is or was a director, officer, employee or agent of us,
unless his acts were committed in bad faith, were the result of active and
deliberate dishonesty, or resulted in personal financial profit or other
advantage to which he was not legally entitled.
ITEM 15 RECENT SALES OF UNREGISTERED SECURITIES
Since our inception, we issued and sold the following securities to certain
individual and institutional investors, including certain of our directors,
officers and key employees, in transactions exempt from the registration
requirements of the Securities Act pursuant to Section 4(2) thereunder:
On August 18, 1998, Encore entered into a Stock Purchase and a
Stockholders' Agreement (collectively the "Agreements"), with five members of
Encore's management ("Management") and four non-management investors (the
"Investors"). Under the terms of the Agreements, 292,592 shares of Class B
Common Stock, par value $0.01 per share (the "Class B") and 64,141 shares of
Class A Common Stock, par value $0.01 per share ("Class A") were issued for a
total amount of committed consideration to be invested in Encore of $298 million
by Management and the Investors. Subsequent to August 18, 1998 an additional
15,111 shares of Class A Common Stock and 2,536 shares of Class B Common Stock
were sold for an aggregate of approximately $2.7 million in cash and commitments
to 23 key employees of Encore. Encore repurchased an aggregate of 5,526 shares
of Class A and 227 shares of Class B stock from two former employees. As of
September 30, 2000, 294,901 shares of Class B and 73,725 shares of Class A were
issued and outstanding. The remaining shares of Class B and shares of Class A
are reserved for issuance to future Management members. Each purchaser
represented that he or it was purchasing the shares for investment and each such
person had sufficient knowledge and experience to evaluate the merits and risks
of such investment.
No Underwriters were involved in connection with the sales of securities
referred to in this Item 15.
All shares of Class A and Class B common stock will be converted into a
single class of common stock in connection with the recapitalization to be
effected in connection with this offering. See "Recapitalization" in the
Prospectus. Such conversion will be exempt from registration under Section
3(a)(9) of the Securities Act.
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<PAGE> 128
ITEM 16 EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Exhibits
<TABLE>
<CAPTION>
EXHIBIT
NO. EXHIBIT
------- -------
<C> <S>
1 -- Form of Underwriting Agreement.+
3.1 -- Form of Second Amended and Restated Certificate of
Incorporation of Encore Acquisition Company.*
3.2 -- Form of Second Amended and Restated By-Laws of Encore
Acquisition Company.*
3.3 -- Deleted exhibit.
4.1 -- Specimen certificate of Encore Acquisition Company.+
4.2 -- Registration Rights Agreement dated as of August 18, 1998
among Encore Acquisition Partners, Inc. and the
stockholder named therein.+
4.3 -- Stockholders' Agreement of Encore Acquisition Partners,
Inc. dated as of August 18, 1998.+
4.4 -- Stock Purchase Agreement among Encore Acquisition
Partners, Inc. and the Investor Stockholders and the
Management Stockholders dated as of August 18, 1998.+
5.1 -- Opinion of Kelly, Hart & Hallman, P.C.*
10.1 -- Credit Agreement dated as of May 7, 1999, by and among
Encore Operating, L.P., Encore Acquisition Partners,
Inc., and a syndicate of banks led by NationsBank, N.A.,
First Union National Bank, and BankBoston, N.A.+
10.2 -- Letter Agreement effective as of August 24, 2000 amending
the Credit Agreement.+
10.3 -- Pledge Agreement by Encore Acquisition Partners, Inc. in
favor NationsBank, N.A. dated as of May 7, 1999.+
10.4 -- Form of 2000 Incentive Stock Plan of Encore Acquisition
Company.+
10.5 -- Management Stock Ownership Plan effective as of August
18, 1998.+
10.6 -- Form of Indemnity Agreement.+
10.7 -- Confidentiality and Non-Compete Agreement between Encore
Acquisition Partners, Inc. and I. Jon Brumley dated as of
August 18, 1998.+
10.8 -- Confidentiality and Non-Compete Agreement between Encore
Acquisition Partners, Inc. and Jon S. Brumley dated as of
August 18, 1998.+
10.9 -- Confidentiality and Non-Compete Agreement between Encore
Acquisition Partners, Inc. and Gene Carlson dated as of
August 18, 1998.+
10.10 -- Confidentiality and Non-Compete Agreement between Encore
Acquisition Partners, Inc. and Kyle Schultz dated as of
August 18, 1998.+
10.11 -- Confidentiality and Non-Compete Agreement between Encore
Acquisition Partners, Inc. and Morris B. Smith dated as
of August 1, 2000.+
10.12 -- Purchase and Sale Agreement between Shell Western E&P
Inc. and Shell Onshore Ventures Inc., as sellers, and
Encore Operating, L.P., as buyer, dated as of March 12,
1999.+
10.13 -- Amendment to Purchase and Sale Agreement between Shell
Western E&P Inc. and Shell Onshore Ventures Inc., as
sellers, and Encore Operating, L.P., as buyer, dated as
of May 26, 1999.+
</TABLE>
II-3
<PAGE> 129
<TABLE>
<CAPTION>
EXHIBIT
NO. EXHIBIT
------- -------
<C> <S>
10.14 -- Second Amendment to Purchase and Sale Agreement between
Shell Western E&P Inc. and Shell Onshore Ventures Inc.,
as sellers, and Encore Operating, L.P., as buyer, dated
as of May 28, 1999.+
10.15 -- Purchase and Sale Agreement dated February 23, 2000
between Cross Timbers Oil Company and Encore Operating,
L.P.+
21.1 -- Subsidiaries of Encore Acquisition Company.*
23.1 -- Consent of Arthur Andersen LLP.*
23.2 -- Consent of Kelly, Hart & Hallman, P.C. (included in its
opinion filed as Exhibit 5.1).
23.3 -- Consent of Miller and Lents, Ltd.*
24 -- Power of Attorney (included on the signature page of the
original filing).
27 -- Financial Data Schedule (included in SEC filing only).+
</TABLE>
---------------
+ Previously filed.
*Amended Exhibit.
ITEM 17 UNDERTAKINGS
The undersigned registrant hereby undertakes to provide to the underwriters
at the closing specified in the underwriting agreement, certificates in such
denominations and registered in such names as required by the underwriters to
permit prompt delivery to each purchaser.
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
registrant pursuant to the foregoing provisions, or otherwise, the registrant
has been advised that in the opinion of the SEC such indemnification is against
public policy as expressed in the Securities Act of 1933 and is, therefore,
unenforceable. In the event that a claim for indemnification against such
liabilities (other than the payment by the registrant of expenses incurred or
paid by a director, officer or controlling person of the registrant in the
successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities being
registered, the registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against public
policy as expressed in the Securities Act of 1933 and will be governed by the
final adjudication of such issue.
The undersigned registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act
of 1933, the information omitted from the form of prospectus filed as part
of this registration statement in reliance upon Rule 430A and contained in
a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or
(4) or 497(h) under the Securities Act of 1933 shall be deemed to be part
of this registration statement as of the time it was declared effective.
(2) For purposes of determining any liability under the Securities Act
of 1933, each post-effective amendment that contains a form of prospectus
shall be deemed to be a new registration statement relating to the
securities offered therein, and the offering of such securities at that
time shall be deemed to be the initial bona fide offering thereof.
II-4
<PAGE> 130
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
registrant has duly caused this Amendment to Registration Statement on Form S-1
to be signed on its behalf by the undersigned, thereunto duly authorized, in the
City of Fort Worth, State of Texas, on January 15, 2001.
ENCORE ACQUISITION COMPANY
By: /s/ I. JON BRUMLEY
----------------------------------
I. Jon Brumley
Chairman, President,
Chief Executive Officer and
Director
POWER OF ATTORNEY
The undersigned directors and officers of Encore Acquisition Company hereby
constitute and appoint each of I. Jon Brumley and Morris B. Smith, with full
power to act and with full power of substitution and resubstitution, our true
and lawful attorney-in-fact and agent with full power to execute in our name and
behalf in the capacities indicated below any and all amendments (including
post-effective amendments and amendments thereto) to this Registration Statement
and to file the same, with all exhibits and other documents relating thereto and
any registration statement relating to any offering made pursuant to this
Registration Statement that is to be effective upon filing pursuant to Rule
462(b) under the Securities Act with the SEC and hereby ratify and confirm all
that such attorney-in-fact or his substitute shall lawfully do or cause to be
done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, as amended,
this registration statement has been signed by the following persons in the
capacities and on the dates indicated below:
<TABLE>
<CAPTION>
NAME TITLE DATE
---- ----- ----
<C> <S> <C>
/s/ I. JON BRUMLEY Chairman, President, Chief January 15, 2001
----------------------------------------------------- Executive Officer and
I. Jon Brumley Director
/s/ JON S. BRUMLEY* Executive Vice January 15, 2001
----------------------------------------------------- President -- Business
Jon S. Brumley Development, Secretary,
Assistant Treasurer and
Director
/s/ KYLE M. SCHULTZ* Executive Vice January 15, 2001
----------------------------------------------------- President --
Kyle M. Schultz Exploitation and
Director
/s/ MORRIS B. SMITH* Chief Financial Officer, January 15, 2001
----------------------------------------------------- Treasurer, Executive
Morris B. Smith Vice President and
Principal Financial
Officer
/s/ ROBERT C. REEVES* Vice President, Controller January 15, 2001
----------------------------------------------------- and Principal Accounting
Robert C. Reeves Officer
</TABLE>
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<PAGE> 131
<TABLE>
<CAPTION>
NAME TITLE DATE
---- ----- ----
<C> <S> <C>
/s/ KENNETH A. HERSH* Director January 15, 2001
-----------------------------------------------------
Kenneth A. Hersh
/s/ ARNOLD L. CHAVKIN* Director January 15, 2001
-----------------------------------------------------
Arnold L. Chavkin
/s/ HOWARD H. NEWMAN* Director January 15, 2001
-----------------------------------------------------
Howard H. Newman
*By: /s/ I. JON BRUMLEY
------------------------------------------------
I. Jon Brumley
Attorney-in-Fact
</TABLE>
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<PAGE> 132
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NO. EXHIBIT
------- -------
<C> <S>
1 -- Form of Underwriting Agreement.+
3.1 -- Form of Second Amended and Restated Certificate of
Incorporation of Encore Acquisition Company.*
3.2 -- Form of Second Amended and Restated By-Laws of Encore
Acquisition Company.*
3.3 -- Deleted Exhibit.
4.1 -- Specimen certificate of Encore Acquisition Company.+
4.2 -- Registration Rights Agreement dated as of August 18, 1998
among Encore Acquisition Partners, Inc. and the
stockholder named therein.+
4.3 -- Stockholders' Agreement of Encore Acquisition Partners,
Inc. dated as of August 18, 1998.+
4.4 -- Stock Purchase Agreement among Encore Acquisition
Partners, Inc. and the Investor Stockholders and the
Management Stockholders dated as of August 18, 1998.+
5.1 -- Opinion of Kelly, Hart & Hallman, P.C.*
10.1 -- Credit Agreement dated as of May 7, 1999, by and among
Encore Operating, L.P., Encore Acquisition Partners,
Inc., and a syndicate of banks led by NationsBank, N.A.,
First Union National Bank, and BankBoston, N.A.+
10.2 -- Letter Agreement effective as of August 24, 2000 amending
the Credit Agreement.+
10.3 -- Pledge Agreement by Encore Acquisition Partners, Inc. in
favor NationsBank, N.A. dated as of May 7, 1999.+
10.4 -- Form of 2000 Incentive Stock Plan of Encore Acquisition
Company.+
10.5 -- Management Stock Ownership Plan effective as of August
18, 1998.+
10.6 -- Form of Indemnity Agreement.+
10.7 -- Confidentiality and Non-Compete Agreement between Encore
Acquisition Partners, Inc. and I. Jon Brumley dated as of
August 18, 1998.+
10.8 -- Confidentiality and Non-Compete Agreement between Encore
Acquisition Partners, Inc. and Jon S. Brumley dated as of
August 18, 1998.+
10.9 -- Confidentiality and Non-Compete Agreement between Encore
Acquisition Partners, Inc. and Gene Carlson dated as of
August 18, 1998.+
10.10 -- Confidentiality and Non-Compete Agreement between Encore
Acquisition Partners, Inc. and Kyle Schultz dated as of
August 18, 1998.+
10.11 -- Confidentiality and Non-Compete Agreement between Encore
Acquisition Partners, Inc. and Morris B. Smith dated as
of August 1, 2000.+
10.12 -- Purchase and Sale Agreement between Shell Western E&P
Inc. and Shell Onshore Ventures Inc., as sellers, and
Encore Operating, L.P., as buyer, dated as of March 12,
1999.+
10.13 -- Amendment to Purchase and Sale Agreement between Shell
Western E&P Inc. and Shell Onshore Ventures Inc., as
sellers, and Encore Operating, L.P., as buyer, dated as
of May 26, 1999.+
10.14 -- Second Amendment to Purchase and Sale Agreement between
Shell Western E&P Inc. and Shell Onshore Ventures Inc.,
as sellers, and Encore Operating, L.P., as buyer, dated
as of May 28, 1999.+
</TABLE>
<PAGE> 133
<TABLE>
<CAPTION>
EXHIBIT
NO. EXHIBIT
------- -------
<C> <S>
10.15 -- Purchase and Sale Agreement dated February 23, 2000
between Cross Timbers Oil Company and Encore Operating,
L.P.+
21.1 -- Subsidiaries of Encore Acquisition Company.*
23.1 -- Consent of Arthur Andersen LLP.*
23.2 -- Consent of Kelly, Hart & Hallman, P.C. (included in its
opinion filed as Exhibit 5.1).
23.3 -- Consent of Miller and Lents, Ltd.*
24 -- Power of Attorney (included on the signature page of the
original filing).+
27 -- Financial Data Schedule (included in SEC filing only).+
</TABLE>
---------------
+ Previously filed.
*Amended Exhibit.
