UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended August 31, 1999
-------------------------------------------------
Or
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________________ to ______________________
Commission File Number: 1-13630
--------------------------------------------------------
CEC RESOURCES LTD.
- --------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
Alberta Canada 98-0018241
- --------------------------------------------------------------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1605, 700 6/th/ Ave. S.W., Calgary, Alberta, Canada T2P 0T8
- --------------------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
(403) 265-7605
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(Registrant's telephone number, including area code)
Not Applicable
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(Former name, former address and former fiscal year, if changed since last
report)
- --------------------------------------------------------------------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No ___
---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at October 14, 1999
- ------------------------------------- ----------------------------------------
Common stock, stated value $.20 1,521,400
PART I - FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
CEC RESOURCES LTD.
BALANCE SHEETS
ASSETS
------
August 31 November 30,
1999 1998
---------------- -----------------
(unaudited)
(in Canadian dollars)
(in thousands)
Current assets:
Cash and cash equivalents $ - $ 1,666
Accounts receivable:
Oil and gas sales 421 466
Crown royalty refund and other 470 333
Joint interest partners 24 8
Income tax receivable 58 -
---------------- -----------------
Total current assets 973 2,473
---------------- -----------------
Property and equipment:
Oil and gas assets, full cost method 22,023 16,192
Liquid extraction plant 1,477 1,477
Other property and equipment 200 108
---------------- -----------------
23,700 17,777
Less: Accumulated depreciation, depletion, amortization
and valuation allowance (10,556) (9,015)
---------------- -----------------
Net property and equipment 13,144 8,762
---------------- -----------------
Other assets 1,864 -
---------------- -----------------
$ 15,981 $ 11,235
================ =================
(continued)
- ----------------------------------------------------------------------------------------------------------------------------------
2
CEC RESOURCES LTD.
BALANCE SHEETS - (continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
August 31 November 30,
1999 1998
---------------- --------------
(unaudited)
(in Canadian dollars)
(in thousands)
Current liabilities:
Accounts payable $ 282 $ 237
Income tax payable 2 3
Undistributed oil and gas production receipts
507 113
---------------- ------------
Total current liabilities 791 353
---------------- ------------
Future site restoration costs (Note 5) 221 165
Deferred income taxes (Note 3) 1,739 1,995
Long-term debt 4,850 -
Stockholders' equity:
Preferred stock, authorized unlimited number of
shares, no par value; none issued
Share capital, common stock, authorized unlimited number of shares,
without nominal or par value; 1,521,400 shares issued in 1999 and
1,544,400 in 1998 1,512 1,534
Retained earnings 6,868 7,188
---------------- ------------
Total stockholders' equity 8,380 8,722
---------------- ------------
$ 15,981 $ 11,235
================ ============
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
3
CEC RESOURCES LTD.
STATEMENTS OF INCOME
(Unaudited)
Nine Months Ended August 31, Three Months Ended August 31,
-------------------------------- ---------------------------------
1999 1998 1999 1998
-------------- -------------- -------------- ---------------
(in Canadian dollars)
(in thousands, except per share data)
Revenues:
Oil and gas sales $ 3,684 $ 2,380 $ 1,408 $ 727
Royalties (732) (460) (279) (133)
Alberta royalty tax credit 434 242 159 76
Field services 75 175 19 54
Other 2 27 - 12
-------- --------- --------- --------
Total revenues 3,463 2,364 1,307 736
-------- --------- --------- --------
Costs and expenses:
Lease operating expenses 585 563 231 187
Field services 65 111 25 33
General and administrative 1,522 615 466 256
Depreciation, depletion and amortization 1,597 686 618 212
-------- --------- --------- --------
Total costs and expenses 3,769 1,975 1,340 688
-------- --------- --------- --------
Operating income (306) 389 (33) 48
-------- --------- --------- --------
Interest expense and other 136 (23) 77 (30)
-------- --------- --------- --------
Earnings before income taxes (442) 412 (110) 78
Provision for income taxes (Note 3) (254) 144 (146) 24
-------- --------- --------- --------
Net earnings $ (188) $ 268 $ 36 $ 54
======== ========= ========= ========
Earnings per share:
Basic $ (0.12) $ 0.17 $ 0.02 $ 0.04
======== ========= ========= ========
Fully diluted $ (0.12) $ 0.17 $ 0.02 $ 0.04
======== ========= ========= ========
Average number of common shares outstanding:
Basic 1,529 1,542 1,521 1,539
======== ========= ========= ========
Fully diluted 1,529 1,546 1,523 1,543
======== ========= ========= ========
The accompanying notes are an integral part of these financial statements.
4
CEC RESOURCES LTD.
STATEMENT OF STOCKHOLDERS' EQUITY
For the Nine Months Ended August 31, 1999
(Unaudited)
Retained
Shares Amount Earnings
----------- ------------ -------------
(in Canadian dollars)
(in thousands, except share data)
Balances, November 30, 1998 1,544,400 $ 1,534 $ 7,188
Purchase and cancellation of shares (23,000) (22) (132)
Net earnings - - (188)
---------- -------- -------
Balances, August 31, 1999 1,521,400 $ 1,512 $ 6,868
========== ======== =======
The accompanying notes are an integral part of these financial statements.
5
CEC RESOURCES LTD.
STATEMENTS OF CASH FLOW (Note 2)
(Unaudited)
Nine Months Ended August 31,
----------------------------------
1999 1998
------------ -----------
(in Canadian dollars)
(in thousands)
Net earnings $ (188) $ 268
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Depreciation, depletion and amortization 1,597 686
Future income taxes (256) 120
Other (55) -
Net change in operating assets and liabilities 291 144
-------- -------
Net cash provided by operating activities 1,389 1,218
-------- -------
Cash flows from investing activities:
Additions to oil and gas properties (5,851) (489)
Additions to other assets (1,900) -
-------- -------
Net cash used in investing activities (7,751) (489)
Cash flows from financing activities:
Proceeds from long-term debt 4,850 -
Proceeds from issuance of common stock 513
Purchase of common stock (154) (592)
-------- -------
Net cash provided by (used in) financing activities 4,696 (79)
Net increase (decrease) in cash and cash equivalents (1,666) 650
Cash and cash equivalents at beginning of period 1,666 1,073
-------- -------
Cash and cash equivalents at end of period $ - $ 1,723
======== =======
Supplemental disclosure of cash flow information:
Cash paid (received) during the period for:
Income taxes, net of refunds $ 40 $ (50)
======== =======
The accompanying notes are an integral part of these financial statements.
6
(1) BASIS OF PRESENTATION
The accompanying financial statements are for CEC Resources Ltd.
("Resources" or "Company"). Resources is an independent oil and gas company and
was incorporated on May 31, 1955 under the Business Corporations Act (Alberta )
in Canada and was acquired by the former parent of Columbus Energy Corporation
("Columbus") in 1969 and by Columbus on July 31, 1984. It remained a wholly
owned subsidiary of Columbus until spun-off from Columbus by a rights offering
in February 1995.
These financial statements are prepared in accordance with Canadian
generally accepted accounting principles ("GAAP") and require the use of
management's estimates. These statements contain all adjustments (consisting
only of normal recurring accruals) which, in the opinion of management, are
necessary to present fairly the financial position of the Company as of
August 31, 1999 and November 30, 1998, and the results of its operations and of
its cash flows for the periods presented. The results of operations for interim
periods are not necessarily indicative of results to be expected for the full
year.
Currency
The amounts in these financial statements and notes thereto are in Canadian
dollars, unless otherwise stated.
Cash Equivalents
For purposes of the statements of cash flow, the Company considers all
temporary investments to be cash equivalents. Results of hedging activities,
when employed, are included in cash flow from operations in the statements of
cash flow.
Oil and Gas Properties
The Company follows the full cost method of accounting whereby all costs
associated with the acquisition of, exploration for, and the development of oil
and gas reserves are capitalized. Such costs include land acquisition costs,
geological and geophysical expenditures, drilling costs of productive and non-
productive wells and tangible production equipment. General and administrative
expenses are capitalized to the extent such costs are directly associated with
acquisition, exploration and development of oil and gas properties. Proceeds
from the sale of petroleum and natural gas properties reduce capitalized costs
without recognition of a gain or loss unless such a sale would significantly
alter the rate of depletion and depreciation.
Capitalized costs, including tangible production equipment, are depleted
using the unit of production method based on proved reserves of oil and gas,
before royalties, as estimated by independent engineers. For purposes of the
calculation, oil and gas reserves are converted to a common unit of measure on
the basis of six thousand cubic feet of gas
7
to one barrel of oil. Depreciation of the natural gas liquids processing plant
and other property and equipment are calculated using the straight line method
over their estimated useful lives.
In applying the full cost method, the Company performs a ceiling test which
restricts the net capitalized costs from exceeding an amount equal to the
estimated undiscounted value of future net revenues from proven oil and gas
reserves, based on current prices and costs, after deducting estimated future
operating costs, development costs, general and administrative expenses and
income tax expense.
Estimated future site abandonment and restoration costs are provided using
the unit of production method over the life of proven reserves with the current
year provision included in depreciation, depletion and amortization expense.
Site abandonment and restoration expenditures incurred are recorded as a
reduction of the accumulated accrual.
Field Services Business Segment
The Company receives field service revenue generated by its share of
natural gas processing fees at the Carbon gas plant. The portion of the plant
processing fee revenue attributable to Resources own gas volumes processed by
the plant is not reported as field service revenue, but instead offsets an
identical amount otherwise chargeable to lease operating expenses. The Carbon
plant also processes natural gas belonging to unrelated plant non-owners which
represents the majority of Resources field services revenues.
Resources also derives less significant revenues and net cash flow from
other gathering and compression facilities in which it has ownership. Amounts
applicable to Resources' own gas production volumes have likewise been
eliminated from both revenues and expenses from these operations.
Income Taxes
The liability method is used in measuring income taxes based on temporary
differences including timing differences and other differences between the tax
basis of an asset or liability and its carrying amount in the financial
statements. The method uses the tax rate and the tax law expected to apply to
taxable income in the periods in which the future income tax asset or liability
is expected to be realized. The Company is subject to tax under applicable
Canadian tax law.
Earnings Per Share
Basic earnings per share are calculated using the weighted average number
of shares of common stock outstanding during the period. Fully diluted earnings
per share are calculated assuming the exercise of outstanding dilutive options.
8
(2) STATEMENTS OF CASH FLOW
The Company elected for 1998 to adopt Canadian Institute of Chartered
Accountants (CICA) 1540, Cash Flow Statements, which require a business
enterprise to provide a statement of cash flow in place of a statement of
changes in financial position. Application of CICA 1540 is required for fiscal
years beginning on or after August 1, 1998. Cash flow information for prior
years is restated to conform to the requirements of CICA 1540 as follows:
Net Cash Provided by Net Cash Provided by
Operating Activities (Used In) Investing Activities
-------------------- ------------------------------
(In Canadian Dollars) (In Canadian Dollars)
Nine Months Ended August 31, 1999 (In Thousands) (In Thousands)
- ---------------------------------
As previously reported $ 835 $ (106)
Restatement 383 (383)
-------- ----------
As Restated $ 1,218 $ (489)
======== ==========
(3) INCOME TAXES
The provision for income taxes consists of the following (in thousands):
Nine Months Ended August 31, Three Months Ended August 31,
---------------------------- -----------------------------
1999 1998 1999 1998
----------- --------------- ------------- --------------
Current:
Federal $ 2 $ 24 $ 23 $ 1
Alberta - - - -
------ ------ ------ ------
2 24 23 1
====== ====== ====== ======
Future:
Federal (160) 68 (83) 13
Alberta (96) 52 (86) 10
------ ------ ------ ------
(256) 120 (169) 23
------ ------ ------ ------
Total income tax expense $ (254) $ 144 $ (146) $ 24
====== ====== ====== ======
9
Total tax provision has resulted in effective tax rates which differ from
statutory Federal income tax rates. The reasons for these differences are
illustrated by the following table:
Percent of Pretax Earnings
Nine Months Ended August 31,
---------------------------
1999 1998
------------ -------------
Federal Canadian and provincial statutory rates 45 % 45 %
Resource allowance 28 (27)
Crown royalties, net of credits (19) 16
Statutory rate change
Adjustments of prior year amounts and other 3 1
------ -----
Effective rate 57 % 35 %
====== =====
The tax effect of significant temporary differences representing deferred
tax assets and liabilities and charges were as follows (in thousands):
Current Year
Dec. 1, 1998 Activity August 31,1999
------------- ------------ --------------
Deferred tax liabilities:
Temporary differences, principally oil
and gas properties $ 1,995 $ (256) $ 1,739
============ ============ =============
For Canadian income tax purposes Resources has tax pools available at
August 31, 1999 to reduce future taxable income. These pools include oil and gas
property expenses of $4,235,000, development and exploration expenses of
$1,042,000, earned depletion base of $1,170,000 and undepreciated capital costs
of $2,465,000. The tax attributes of carryforward pools are included to
determine the temporary differences shown as deferred tax liabilities. These
attributes generally do not expire.
(4) RELATED PARTY TRANSACTIONS
Resources incurred certain direct and indirect general and administrative
costs for services provided by its former Parent in lieu of expanding the number
of its own full-
10
time employees. These costs were primarily for labor, related benefits and other
overhead costs as provided by an agreement between the parties. These costs were
$54,000 and $271,000 for the first nine months of 1999 and 1998, respectively.
Effective March 31, 1999, this management agreement was terminated.
(5) COMMITMENTS
The majority of the Company's natural gas is contracted to gas marketing
companies on a deliverability basis and sold at published index prices less
applicable transportation and marketing charges. The Company has temporarily
assigned its firm transportation agreements through October, 1999 and has
retained the option to obtain additional firm transportation service. At
August 31, 1999, the Company had seven forward priced hedge contracts. These
contracts allow the Company to receive fixed prices for a percentage of its
production. The terms of these transactions are as follows:
Daily Quantity Contract Quantity Fixed Price/
Period GigaJoules GigaJoules GigaJoule
- -------------------- ---------------- ------------------- -------------
Apr 99 - Oct 99 1,055 226,000 $2.390
Dec 98 - Oct 01 1,055 1,125,000 $2.570
Apr 99 - Oct 99 1,000 214,000 $2.310
Apr 99 - Oct 99 500 107,000 $2.220
Nov 99 - Oct 00 1,000 366,000 $2.720
Nov 99 - Mar 00 750 113,250 $3.620
Apr 00 - Oct 00 750 160,500 $2.925
The unrecognized loss on these contracts totaled $806,000 based on
August 31, 1999 market values.
The Company estimates that future costs of site abandonment and restoration
of well sites, gas processing plants and other facilities will be $434,362 as of
August 31, 1999 in addition to $221,000 already accrued as a liability. The
estimated costs are being recognized on a unit-of-production basis over the life
of the properties.
(6) ACQUISITION OF OIL AND GAS PROPERTIES
Between December 1998 and April 1999, Resources purchased producing oil and
gas properties and natural gas gathering and compression facilities in Alberta,
Canada. These acquisitions were accounted for as a purchase and considered
"material" by management for purposes of pro forma disclosure. The following pro
forma statement presents incremental results of operations for the current year
and for the corresponding period of the preceding year as though the
acquisitions had occurred at the beginning of
11
the periods being reported on. Revenues and expenses subsequent to the purchase
dates have been included in 1999 operating results and are not included in the
incremental results.
The incremental pro forma results below are not indicative of the results
that would have occurred if the acquisitions had been in effect for the entire
periods presented. The pro forma results are not intended to be a projection of
future results. Financial information showing the incremental pro forma results
of the acquisition is presented below:
Nine Months Ending August 31, Three Months Ending August 31,
----------------------------- ------------------------------
1999 1998 1999 1998
------------- -------------- ------------- ---------------
(in Canadian dollars)
(in thousands, except per share data)
Revenues $ 168 $ 1,080 $ - $ 324
Direct Operating Expenses 64 510 - 182
Depreciation & Depletion 109 682 - 210
Interest Expense 40 237 - 78
Income Tax Expense (a) (15) (122) - (45)
Net Income (30) (227) - (101)
Earnings per share (0.02) (0.15) - (0.07)
(a) Income taxes at Company's effective rate for the applicable period.
(7) GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA AND THE UNITED STATES
The financial statements have been prepared in accordance with Canadian
GAAP and differ in certain respects from financial statements which the Company
would have made had its financial statements been prepared in accordance with
United States GAAP. Differences between the two methods which affect these
financial statements are:
(a) Under U.S. GAAP, cash (and cash equivalents) includes bank deposits,
money market instruments, and commercial paper with original
maturities of three months or less. Canadian GAAP permits the
inclusion in cash of temporary investments with maturities greater
than 90 days. The differences in measurement had no impact on
classifications in the balance sheets.
(b) Basic earnings per share using U.S. GAAP is the same as basic earnings
per share using Canadian GAAP. Under U.S. GAAP, fully diluted
earnings per share are reported using the "treasury stock
method." Under Canadian GAAP, fully diluted earnings per share assumes
that cash proceeds from the deemed exercise of stock options are
invested by the
12
Company in such a way as to earn a reasonable return. The number of
shares used in the calculation is the same for both methods.
(c) Under U.S. GAAP, the full cost accounting method requires that
capitalized costs less related accumulated depletion and deferred
income taxes may not exceed the sum of (1) the present value
(discounted at 10%) of future net revenues from estimated production
of proved oil and gas reserves; plus (2) the cost of properties not
being amortized, if any, plus (3) the lower of cost or estimated fair
value of unproved properties included in the costs being amortized if
any, less (4) income tax effects related to differences in the book
and tax basis of oil and gas properties. Using U.S. GAAP, there would
not have been an impairment to the full cost pool.
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The discussion below summarizes the Company's financial condition and
results of operations and should be read in conjunction with the financial
statements and related notes. The financial related comments contained in this
section are derived from financial statements prepared in accordance with
Canadian GAAP.
The information presented below contains forward-looking statements within
the meaning of the U.S. Private Securities Litigation Reform Act of 1995.
Statements that are not historical facts contained in this report are forward-
looking statements that involve risks and uncertainties that could cause actual
results to differ from projected results. Such statements address activities,
events or developments that the Company expects, believes, projects, intends or
anticipates will or may occur, including such matters as future capital,
development and exploration expenditures (including the amount and nature
thereof), drilling or deepening of wells, reserve estimates (including estimates
of future net revenues associated with such reserves and the present value of
future net revenues), future production of oil and natural gas, business
strategies, expansion and growth of the Company's operations, cash flow and
anticipated liquidity, prospect development and property acquisition, obtaining
financial or industry partners for prospect or program development, or marketing
of oil and natural gas. Factors that could cause actual results to differ
materially are described, among other places in the Company's 1998 Form 10-K and
under the caption "Management's Discussion and Analysis of Financial Condition
and Results of Operations". Without limiting the factors so described, factors
include, among others: general economic conditions, the market price of oil and
natural gas, the risks associated with exploration, the Company's ability to
find, acquire, market, develop and produce new properties, operating hazards
attendant to the oil and natural gas business, uncertainties in the estimation
of proved reserves and in the projection of future rates of production and
timing of development expenditures, the strength and financial resources of the
Company's competitors, the Company's ability
13
to find and retain skilled personnel, climatic conditions, labor relations,
availability and cost of material and equipment, environmental risks, the
results of financing efforts and regulatory developments. The Company disclaims
any obligation to update or revise any forward-looking statement to reflect
events or circumstances occurring hereafter or to reflect the occurrence of
anticipated or unanticipated events.
Results of Operations
Three months ended August 31, 1999 compared to three months ended August 31,
l998.
Total revenues for the third quarter of 1999 were $1,307,000, a 77%
increase from the prior year period amount of $737,000. The increase was due
primarily to higher natural gas production, including production resulting from
the Company's Acquisitions, and higher natural gas, oil and plant liquid prices.
Net income in the third quarter of 1999 was $36,000 compared to $54,000 in the
third quarter of 1998. The decrease was primarily due to increased general and
administrative expenses, increased depletion, depreciation and amortization
expenses, offset by higher natural gas, oil and plant liquid revenues, lease
operating cost efficiencies and a deferred tax benefit.
The following table show comparative revenue, sales volumes, average prices
and percentage changes between periods, for natural gas, oil and plant liquids
for the third quarters of 1999 and 1998:
Three Months Ended August 31,
---------------------------------------
1999 1998 % Change
--------- --------- -----------
Natural gas revenues M$ 1,100 537 105%
Oil revenues M$ 151 117 30%
Natural gas liquids revenues M$ 156 73 114%
Natural gas sales volumes:
Millions of cubic feet 411 271 52%
MCF/day 4,471 2,947
Oil sales volumes:
Barrels 5,869 6,884 -15%
Barrels/day 64 75
Natural gas liquids sales volumes:
Barrels 8,289 6,199 34%
Barrels/day 90 67
Average price received:
Natural gas - $/MCF 2.67 1.98 35%
Oil - $/BBL 25.78 16.96 52%
Plant liquids - $/BBL 18.84 11.75 60%
14
Average daily oil and plant liquid production in the third quarter of 1999
were 64 and 90 barrels, respectively. Average daily gas production for the third
quarter of 1999 was 4,471 mcf. This is an increase of 42% on a barrel of oil
equivalent ("boe") basis compared to the same period in 1998.
The Company's continued success with the exploitation of properties
acquired during 1999 and current development activity has resulted in
increasing production for three successive quarters. Exploration activities are
expected to continue for the balance of 1999.
Average oil prices increased 52% from $16.96 per barrel in the third
quarter of 1998 to $25.78 in 1999. Average plant liquid prices increased 60%
from $11.75 in the third quarter of 1998 to $18.84 in 1999. Average natural gas
prices increased 35% from $1.98 per mcf for the third quarter of 1998 to $2.67
per mcf in 1999.
Royalty expense consists primarily of Crown Royalties as well as smaller
amounts of freehold and gross overriding royalties. The Company is eligible for
the Alberta Royalty Tax Credit ("ARTC") which varies inversely with prevailing
prices for oil and gas sales in Alberta. For the third quarter of 1999 the net
Crown Royalty rate was 6% compared to 5% in 1998.
Lease operating expenses totaled $231,000 or $2.79 per boe for the third
quarter of 1999 compared to $187,000 or $3.20 per boe in the prior year period.
This reduction in per boe expense is due to efficiencies realized from operating
the Company's East Carbon properties and the fact that lease operating
expenses for 1998 were higher due to well workovers at the Company's Hoffer
properties.
Field netbacks commonly reported by Canadian energy companies equate to oil
and gas sales less royalties and lease operating expenses. Resources' average
field netback increased significantly for the third quarter of 1999 to $12.78
per boe compared to $8.29 for the third quarter of 1998 primarily due to the
positive revenue and lease operating expense variances previously discussed.
Resources has always followed the U.S. practice of converting its natural
gas to boe based on the heating value ratio of six mcf of natural gas to one
barrel of oil. A ratio of 10:1 which historically has more closely approximated
price ratios, is used by nearly all Canadian public companies.
If natural gas had been converted to boe using the Canadian practice of a
10:1 ratio, then reported field netbacks would have been $19.12 and $12.01 per
boe for the third quarter of 1999 and 1998, respectively.
General and administrative expenses, net of third party reimbursements, for
the third quarter of 1999 totaled $466,000, a $210,000 or 82% increase for the
same period of
15
1998. The increase in general and administrative expense was primarily due to
the hiring of full time employees
Interest and other expenses were $77,000 in the third quarter of 1999, a
$107,000 increase from the prior year period. Interest expense increased as a
result of incurring long-term debt in 1999 to partially fund acquisitions. See
"Acquisitions" and "Liquidity and Capital Resources". The Company's average
borrowing rate for the third quarter of 1999 was 7.0%.
Depletion, depreciation and amortization expense for the third quarter of
1999 totaled $618,000, an increase of $406,000 or 191% from the 1998 level.
Depletion expense increased primarily due to increased gas sales and a
downward adjustment to CEC's 1998 year end developed non-producing and proved
undeveloped natural gas reserves that resulted in an increased depletion rate
per boe in 1999 compared to 1998.
Nine months ended August 31, 1999 compared to nine months ended August 31, 1998.
Revenues for the nine months ended August 31, 1999 totaled $3,463,000
million, a 46% increase from the prior year period. The increase was due
primarily to increased natural gas and plant liquid production, including
production resulting from the Company's acquisitions and higher natural gas, oil
and plant liquid prices. The net loss in the first nine months of 1999 was
$188,000 compared to net income of $268,000 in the first nine months of 1998.
The decrease was primarily due to increased general and administrative expenses,
increased depletion, depreciation and amortization expenses partially offset by
higher oil, natural gas and plant liquid revenues.
The following table shows comparative revenue, sales volume, average prices
and percentage changes between periods, for natural gas, oil, and plant liquids
for the first nine months of 1999.
16
Nine Months Ended August 31,
------------------------------------
1999 1998 % Change
--------- --------- ------------
Natural gas revenues M$ 2,934 1,716 71%
Oil revenues M$ 385 367 5%
Natural gas liquids revenues M$ 365 297 23%
Natural gas sales volumes:
Millions of cubic feet 1,115 889 25%
MCF/day 4,069 3,244
Oil sales volumes:
Barrels 18,395 19,797 -7%
Barrels/day 67 72
Natural gas liquids sales volumes:
Barrels 23,802 20,206 18%
Barrels/day 87 74
Average price received:
Natural gas - $/MCF 2.63 1.93 36%
Oil - $/BBL 20.91 18.51 13%
Plant liquids - $/BBL 15.34 14.69 4%
Average daily oil and plant liquid production for the first nine months of
1999 were 67 and 87 barrels, respectively. Average daily gas production for the
first nine months of 1999 was 4,069 mcf. This is an increase of 21% on a boe
equivalent basis compared to the same period in 1998.
The Company's continued success with the exploitation of properties
acquired during 1999 and current development activity has resulted in
increasing production for three successive quarters. Exploration activities are
expected to continue for the balance of 1999.
Average oil prices increased 13% from $18.51 per barrel in the first 9
months of 1998 to $20.91 in 1999. Average plant liquids prices increased 4% from
$14.69 for the first nine months of 1998 to $15.34 in 1999. Average natural gas
prices increased 36% from $1.93 per mcf for the first nine months of 1998 to
$2.63 in 1999.
Royalty expense consists primarily of Crown Royalties as well as smaller
amounts of freehold and gross overriding royalties. The Company is eligible for
the Alberta Royalty Tax Credit ("ARTC") which varies inversely with prevailing
prices for
17
oil and gas sales in Alberta. For the first nine months of 1999 and 1998 the net
Crown Royalty rate was 6%.
Lease operating expenses totaled $585,000 or $2.57 per boe for the first
nine months of 1999 compared to $563,000 or $2.99 per boe in the prior year
period. This reduction in per boe expense is due to efficiencies realized from
operating the Company's East Carbon properties and the fact that lease operating
expenses for 1998 were higher due to well workovers at the Company's Hoffer
properties.
Field netbacks commonly reported by Canadian energy companies equate to oil
and gas sales less royalties and lease operating expenses. Resources' average
field netback increased significantly for the first nine months of 1999 to
$12.28 per boe compared to $8.50 per boe for the first nine months of 1998
primarily due to the positive revenue and lease operating expense variances
previously discussed.
Resources has always followed the U.S. practice of converting its natural
gas to boe based on the heating value ratio of six mcf of natural gas to one
barrel of oil. A ratio of 10:1 which historically has more closely approximated
price ratios, is used by nearly all Canadian public companies.
If natural gas volume had been converted to boe using the Canadian practice
of a 10:1 ratio, then reported field netbacks would have been $18.22 and $12.40
per boe for the first nine months of 1999 and 1998, respectively.
General and administrative expenses, net of third party reimbursements, for
the first nine months of 1999 totaled $1,522,000, a $908,000 or 148% increase
from the same period in 1998. The increase in general and administrative expense
was primarily due to the hiring of full time employees, partially offset by a
reduction in charges for management services provided by Columbus under a
management contract which was terminated March 31, l999.
Interest and other expenses increased to $136,000 for the first nine months
of 1999, a $159,000 increase from the prior year period. Interest expense
increased as a result of incurring long-term debt in 1999 to partially fund
acquisitions. See "Acquisitions" and "Liquidity and Capital Resources". The
Company's average interest rate for the first nine months of 1999 was 7.25%.
Depletion, depreciation and amortization expense for the nine month period
ended August 31, l999 totaled $1,597,000, a increase of $911,000 or 133% from
the 1998 level. Depletion expense increased primarily due to increased gas sales
and a downward adjustment to CEC's 1998 year end developed non-producing and
proved undeveloped natural gas reserves that resulted in an increased depletion
rate boe in 1999 compared to 1998. For the first nine months of 1999 the
depletion rate was $6.29 per boe, compared to $3.20 per boe for the same period
in 1998.
18
Acquisitions
In December 1998 the Company acquired for $2.3 million working interests in
16 natural gas wells, associated natural gas gathering and compression
facilities and undeveloped lands in the East Carbon Field (Wayne-Rosedale),
located in Alberta, Canada from Neutrino Resources, Ltd. The acquisition was
funded with cash and bank financing. The acquisition increased the Company's
working interest ownership in the East Carbon Field from 33-1/3% to 64%. The
Company estimates that as of November 30, 1998, the remaining proved reserves
before royalty of the acquired properties are approximately 51,000 barrels of
oil and natural gas liquids and approximately 2.3 billion cubic feet of natural
gas.
In March 1999, the Company acquired for $800,000 a 100% working interest in
one natural gas well, associated natural gas gathering facilities and
underdeveloped lands in the East Carbon Field, located in Alberta, Canada from
Westdrum Energy Ltd. and C. & D. Oil and Gas Ltd. The acquisition was funded
with bank financing. The Company estimates that as of March 1, 1999, the
remaining proved reserves before royalty of the acquired property are
approximately 19,000 barrels of oil and natural gas liquids and approximately
720,000 mcf of natural gas.
In March 1999, the Company acquired for $2.1 million working interests in
17 natural gas wells, associated natural gas gathering and compression
facilities in the East Carbon Field, located in Alberta, Canada from Cometra
Energy (Canada) Ltd. The acquisition was funded with bank financing. The
acquisition increased the Company's working interest ownership in the East
Carbon Field from 64% to 97%. The Company estimates that as of March 1, 1999,
the remaining proved reserves before royalty of the
19
acquired properties are approximately 48,000 barrels of oil and natural gas
liquids and approximately 2.1 billion cubic feet of natural gas.
In April 1999, the Company acquired for $125,000 working interests in 13
natural gas wells, associated natural gas gathering and compression facilities
and undeveloped lands in the East Carbon Field, located in Alberta, Canada from
Springroad Resources, Inc. The acquisition was funded with bank financing. The
acquisition increased the Company's working interest ownership in the East
Carbon Field from 97% to approximately 100%. The Company estimates that as of
March 1, 1999, the remaining proved reserves before royalty of the acquired
properties are approximately 4,000 barrels of oil and natural gas liquids and
approximately 180,000 mcf of natural gas.
On August 12, 1999, the Company entered into an agreement to acquire all of
the stock of Denver based Bonneville Fuels Corporation ("Bonneville"), an oil
and gas exploration and production company with working interests in
approximately 290 oil and natural gas wells and over 150,000 net acres located
in Colorado, Kansas, New Mexico, Texas, and Utah. Bonneville is a wholly owned
subsidiary of Bonneville Pacific Corporation. The purchase price for the stock
of Bonneville is approximately $24,000,000, subject to adjustments, plus debt of
approximately $6,500,000 remaining at Bonneville.
Net proved reserves of Bonneville are estimated at approximately 250,000
barrels of oil and approximately 40 billion cubic feet of natural gas. Current
net production from the properties to be acquired is approximately 13,000 mcf of
gas per day and 200 barrels of oil per day.
Carbon Energy Corporation ("Carbon"), a Colorado corporation, has been
formed and will receive from Yorktown Energy Partners III ("Yorktown"), equity
funds in the amount of $24,750,000 which will be used to purchase Bonneville
stock. Yorktown will purchase Carbon common stock at U.S. $5.50 per share. It is
intended that Carbon common stock will be listed on the American Stock Exchange.
Shareholders of CEC will be offered the opportunity to exchange their shares of
CEC for shares of Carbon on the basis of one share of CEC for one share of
Carbon. At the completion of the exchange offer, CEC will become a subsidiary of
Carbon. Closing of the Bonneville purchase is scheduled for October 31, 1999.
The exchange offer will commence later this year after effectiveness of a
registration statement to be filed with the Security and Exchange Commission.
Those arrangements are covered by an Exchange and Financing Agreement among
Carbon, CEC and Yorktown Energy III, L.P.
Carbon on a consolidated basis with both Bonneville and CEC, will have
reserves of oil and natural gas more than four times larger than CEC; and Carbon
will have, in addition to CEC's Canadian operations, a base of operations in the
western region of the U.S. with potential for development of the acquired
properties and additional acquisitions in the U.S. and Canada. Reserves of the
combined companies will be approximately 52 bcf of gas and 475,000 barrels of
oil and natural gas liquids. The combined companies will have daily production
in excess of 18,000 mcf of gas per day and nearly 400 barrels of oil per day.
20
Exploration Activities
Under the full cost method of accounting, all exploration costs associated
with continuing efforts to acquire or review prospects including outside
geological and seismic consultants are capitalized. A total of $201,000 of
exploration costs were capitalized during the first nine months of 1999 compared
to $40,000 in the first nine months of 1998.
Liquidity and Capital Resources
The principal sources of the Company's funds are cash flows from operating
activities and available borrowings under the Company's financing commitment.
For the first nine months of 1999, net cash from operating activities was
$1,389,000 compared to $1,218,000 for the same period in 1998. The increase is
primarily due to increased oil and gas sales, a positive net change in operating
assets and liabilities, partially offset by general and administrative expenses.
Net cash used in investing activities was $7,751,000 for the first nine months
of 1999 compared to $489,000 in 1998. This increase was primarily due to
acquisitions in the East Carbon Area and a deposit related to the Bonneville
Fuels acquisition. "See Acquisitions". Net cash provided by financing activities
in the first nine months of 1999 was $4,696,000 which was primarily due to the
proceeds from long-term debt, partially offset by the acquisition of 23,000
shares of the Company's common stock. Net cash used in financing activities in
the first nine months of 1998 was $79,000 due to the acquisition of 83,000
shares of the Company's common stock partially offset by the issuance of 70,000
shares of the Company's common stock.
In December 1998, Resources received a financing commitment from Canadian
Imperial Bank of Commerce ("CIBC"). The purpose of the loan is to provide
financing for the acquisition of oil and gas reserves and for normal operating
requirements. The loan is secured by the Company's oil and gas assets. The
interest rate on outstanding borrowings is the CIBC Prime Rate plus 3/4%. The
initial commitment was a $2.5 million revolving loan. In March 1999, the
commitment was increased to a $5.0 million revolving loan. In October 1999, the
commitment was increased to a $6.5 million revolving loan. The commitment will
be reduced to $5.75 million upon closing of the Bonneville Fuels acquisition
"See Acquisitions". The revolving phase of the loan will expire on April 30,
2000 and may be renewed by CIBC. If the revolving commitment is not renewed by
CIBC, the loan would be converted into a term loan and will be permanently
reduced by way of consecutive monthly principal payments over a period not to
exceed 36 months. Borrowings under the loan during 1999 have resulted in
increased interest expense during 1999 compared to 1998.
Income Taxes
In 1997, the Company adopted CICA 3465, Income Taxes. Since 1993, Resources
had paid current taxes to Revenue Canada based on its taxable income after
utilization, to the extent allowed, of its tax pool carry forwards. Currently
payable taxable income for future periods is dependent upon the level and type
of capital expenditures incurred in those future periods as well as percentage
limitations for utilization of existing tax pools. For 1999, the Company
anticipates little or no current income tax liability based upon current and
anticipated 1999 activity. For 1998, Federal and provincial taxes were $41,000.
21
Exchange Rate of the Canadian Dollar
All dollar amounts in this report are in Canadian dollars except where
otherwise indicated. The following table sets forth the rates of exchange for
the Canadian dollar, expressed in United States dollars:
Nine Months Ended August 31,
------------------------------------
1999 1998
--------------- ----------------
Rate at end of period 0.6685 0.6361
Average rate during period 0.6657 0.6880
High 0.6894 0.7105
Low 0.6440 0.6343
On September 30, 1999, the noon buying rate in Canadian dollars was .6803
U.S.= $1.00 Canadian.
Year 2000 Issues
The Year 2000 issue is the result of computer programs being written using
two digits rather than four, or other methods, to define the applicable year.
Computer programs that have date sensitive software may recognize a date using
"00" as the year 1900, rather than the year 2000. This could result in a system
failure or miscalculations causing disruptions of operations, including among
other things, a temporary inability to price transactions, send invoices or
engage in similar normal business activities. In addition to affecting mainframe
and mid-range computer systems, this problem potentially impacts computer chips
integrated in security, plant automation, and pipeline control and metering
systems.
Resources is currently completing an external review of all Year 2000
issues by contacting and/or sending out questionnaires to all of its natural gas
purchasers, gathering system and plant operators, downstream pipeline operators,
equipment and service providers, operators of its oil and gas properties,
financial institutions and vendors providing payroll and medical benefits and
services. The preliminary phase of this review has been completed. Based upon
this review, a schedule of revisions (if any) to existing systems as well as
requisite contingency plans will be designed and implemented.
Resources utilizes a service bureau for its accounting processing. The oil
and gas accounting system utilized by the service bureau is Year 2000 compliant.
Resources has selected an accounting system and is in the process of bringing
all accounting services and processing in-house. The oil and gas accounting
system selected is Year 2000 compliant. Resources is also dependent upon
personal computer based software programs and files that may not be Year 2000
compliant. Resources has set a revised deadline of November 1999 to be
internally compliant with Year 2000 specifications.
22
Management expects costs for Resources to become Year 2000 compliant will
not be significant. Resources does not believe that any loss of revenue will
occur as a result of the Year 2000 problem. However, despite Resosurces's
efforts to identify and remedy Year 2000 problems, there may be related failures
that disrupt Resources's business temporarily. In addition, the timetable for
Resources's planned completion of its own Year 2000 modifications and the
estimated costs to accomplish this are management's best estimates. These
assessments involve many assumptions concerning future events, including the
continued availability of certain resources, particularly personnel able to
locate, reprogram or replace, and test Resources's hardware and software in
accordance with Resources's established schedule. There can be no guarantee that
Resources's estimates will prove accurate, and actual results could differ
significantly because of the non-compliance of third parties of business
importance to Resources.
Item 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk represents the risk of loss that may impact the financial
position, results of operation or cash flow of the Company due to adverse
changes in financial and commodity market prices and rates.
Market and Commodity Risk
The Company's major market risk exposure is in the pricing applicable to
its oil and natural gas production. Pricing is primarily driven by the
prevailing prices for oil and gas in Central Alberta. Historically, prices
received for oil and gas production have been volatile and unpredictable.
Pricing volatility is expected to continue. A significant decline in the prices
of oil or natural gas could have a material adverse effect on the Company's
financial condition and results of operations.
As described in Note 5 to the Financial Statements, from time to time, the
Company enters into commodity derivatives contracts and fixed-price physical
contracts to manage its exposure to oil and gas prices volatility and to support
oil and natural gas prices at targeted levels. The Company primarily uses
futures swap instruments to hedge its commodity prices. Realized gains or losses
from price risk management activities are recognized in oil and gas sales
revenues in the period in which the associated production occurs.
Inflation and Changes in Prices
While certain of its costs are affected by the general level of inflation,
factors unique to the oil and natural gas industry result in independent price
fluctuations. Over the past five years, significant fluctuations have occurred
in oil and natural gas prices.
23
Although it is particularly difficult to estimate future prices of oil and
natural gas, price fluctuations have had, and will continue to have, a material
effect on the Company.
In regard to interest rate risk, the Company has established a $6.5 million
credit facility with a Canadian bank as described in "Liquidity and Capital
Resources" under Item 2 "Management's Discussion of Analysis of Financial
Condition and Results of Operations". The interest rate for borrowings under
this facility is variable. In regard to foreign currency risk, the Company's
operations are primarily conducted in Canada. The Company does not use financial
instruments relating to currency and exchange rates. For information on the
exchange rate of the Canadian dollar, refer to "Exchange Rate of the Canadian
Dollar" under Item 2 "Management's Discussion and Analysis of Financial
Condition and Results of Operations".
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
There are no material legal proceedings pending or, to our knowledge,
threatened against the Company.
Item 6. Exhibits and Reports on Form 8-k
(a) Exhibits
10.1 - Stock Purchase Agreement dated as of August 11, 1999 by
and between Bonneville Pacific Corporation as seller and
CEC Resources Ltd. as buyer.
10.2 - Exchange and Financing Agreement dated as of October 14,
1999 among Carbon Energy Corporation, CEC Resources Ltd,
and Yorktown Energy Partners III, L.P.
11 - Computation of per share earnings
27 - Financial Data Schedule
24
SIGNATURES
----------
Pursuant to the requirements of the Securities Exchange act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CEC RESOURCES LTD.
Registrant
DATE: October 15, 1999 /s/ Patrick R. McDonald
------------------------ ----------------------------------
President and
Chief Executive Officer
(a duly authorized officer)
DATE: October 15, 1999 /s/ Kevin D. Struzeski
------------------------ ----------------------------------
Treasurer
(Chief Financial Officer)
25