1
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
----------------------------
(Mark One)
/X/ Quarterly report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 For the quarterly period ended March 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 0-13305
--------------------------
PARALLEL PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 75-1971716
(State of other jurisdiction of (I.R.S. Employer Identification
incorporation or organization) Number)
One Marienfeld Place, Suite 465,
Midland, Texas 79701
(Address of principal executive offices) (Zip Code)
(915) 684-3727
(Registrant's telephone number, including area code)
NOT APPLICABLE
(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
The number of outstanding shares of the issuer's common stock, $.01 par
value, was 18,331,858 shares as of May 1, 1999.
================================================================================
2
INDEX
PART I. - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Reference is made to the succeeding pages for the following
financial statements:
- Balance Sheets as of December 31, 1998 and March 31, 1999
- Statements of Operations for the three months ended March 31,
1998 and 1999
- Statements of Cash Flows for the three months ended March 31,
1998 and 1999
- Notes to Financial Statements
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PART II. - OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
/a/ Exhibits
/b/ Reports on Form 8-K
3
PARALLEL PETROLEUM CORPORATION
BALANCE SHEETS
December 31, March 31, 1999
ASSETS 1998* (Unaudited)
- ------------- ------------ --------------
Current assets:
Cash and cash equivalents $ 1,178,819 $ 1,440,167
Accounts receivable:
Oil and gas 1,432,659 1,366,385
Others, net of allowance for doubtful accounts
of $71,358 in 1998 and 1999 247,740 189,572
Affiliate 11,844 1,381
------------ ------------
1,692,243 1,557,338
Other assets 61,504 12,659
------------ ------------
Total current assets 2,932,566 3,010,164
------------ ------------
Property and equipment, at cost:
Oil and gas properties, full cost method 65,565,466 66,428,628
Other 287,586 288,788
------------ ------------
65,853,052 66,717,416
Less accumulated depreciation and depletion 22,279,355 23,183,191
------------ ------------
Net property and equipment 43,573,697 43,534,225
------------ ------------
Other assets, net of accumulated amortization of
$86,917 in 1998 and $95,248 in 1999 58,519 73,039
------------ ------------
$ 46,564,782 $ 46,617,428
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
Current liabilities:
Accounts payable and accrued liabilities:
Trade $ 2,803,539 $ 2,067,027
Affiliate 214 2,467
Preferred stock dividend -- 170,538
------------ ------------
Total current liabilities 2,803,753 2,240,032
------------ ------------
Long-term debt 18,035,889 18,815,889
Deferred income taxes -- --
Stockholders' equity:
Preferred stock - 6% convertible preferred stock - par value
of $.10 per share, (aggregate liquidation preference of $10)
authorized 10,000,000 shares, issued and outstanding
974,500 in 1998 97,450 97,450
Common stock - par value of $.01 per share, authorized
60,000,000 shares, issued and outstanding 18,306,858
in 1998 and 18,331,858 in 1999 183,069 183,319
Additional paid-in surplus 32,341,971 32,188,371
Retained deficit (6,897,350) (6,907,633)
------------ ------------
Total stockholders' equity 25,725,140 25,561,507
Contingencies
------------ ------------
$ 46,564,782 $ 46,617,428
============ ============
*The balance sheet as of December 31, 1998 has been derived from the
Company's audited financial statements. The accompanying notes are an integral
part of these financial statements.
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PARALLEL PETROLEUM CORPORATION
STATEMENTS OF OPERATIONS
Three Months Ended March 31, 1998 and 1999
(Unaudited)
1998 1999
------------ -----------
Oil and gas revenues $ 2,112,563 $ 1,963,089
------------ -----------
Cost and expenses:
Lease operating expense 557,638 513,822
General and administrative 220,389 203,237
Depreciation, depletion and amortization 930,816 903,836
----------- -----------
1,708,843 1,620,895
----------- -----------
Operating income 403,720 342,194
----------- -----------
Other income (expense), net:
Interest income 76 13,276
Other income 13,559 6,623
Interest expense (304,278) (371,071)
Other expense (4,382) (1,305)
----------- -----------
Total other expense, net (295,025) (352,477)
----------- -----------
Income before income taxes 108,695 (10,283)
Income tax expense - deferred 35,869 --
----------- -----------
Net income (loss) $ 72,826 $ (10,283)
=========== ===========
Net income (loss) per common share:
Basic $.004 $(.010)
----- ------
Diluted $.004 $(.010)
----- ------
Weighted average common shares outstanding:
Basic 18,118,733 18,328,525
========== ==========
Diluted 18,779,453 18,328,525
=========== ===========
The accompanying notes are an integral part of these financial statements.
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PARALLEL PETROLEUM CORPORATION
STATEMENTS OF CASH FLOWS
Three Months Ended March 31, 1998 and 1999
(Unaudited)
1998 1999
---------- ----------
Cash flows from operating activities:
Net income (loss) $ 72,826 (10,283)
Adjustments to reconcile net income to
net cash provided by (used in) operating
activities:
Depreciation, depletion and amortization 930,816 903,836
Incomes taxes 35,869 --
Other (increase) decrease, net 6,526 (14,520)
Changes in assets and liabilities:
Decrease (increase) in trade receivables (367,128) 134,905
Increase in subscription receivable (6,000,000) --
(Increase)in prepaid expenses
and other (6,979) 48,845
Decrease in accounts payable
and accrued liabilities (488,706) (734,259)
----------- -----------
Net cash provided by (used in) operating
activities (5,816,776) 328,524
----------- -----------
Cash flows from investing activities:
Additions to property and equipment (4,916,115) (1,119,604)
Proceeds from disposition of property and equipment -- 255,240
----------- -----------
Net cash used in investing
activities (4,916,115) (864,364)
----------- -----------
Cash flows from financing activities:
Proceeds from the issuance of long-term debt 4,450,000 780,000
Stock offering costs (58,859) --
Proceeds from common stock issuance 6,000,000 --
Proceeds from exercise of options and warrants 33,750 17,188
----------- -----------
Net cash provided by financing
activities 10,424,891 797,188
----------- -----------
Net increase (decrease) in cash
and cash equivalents (308,000) 261,348
Beginning cash and cash equivalents 597,149 1,178,819
----------- -----------
Ending cash and cash equivalents $ 289,149 1,440,167
=========== ===========
Non-cash financing activities:
Accrued preferred stock dividend $ -- 170,538
=========== ===========
The accompanying notes are an integral part of these financials.
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PARALLEL PETROLEUM CORPORATION
NOTES TO FINANCIAL STATEMENTS
NOTE 1. OPINION OF MANAGEMENT
The financial information included herein is unaudited. However, such
information includes all adjustments (consisting solely of normal recurring
adjustments) which are, in the opinion of management, necessary for a fair
statement of the results of operations for the interim periods.
Certain information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted in this Form 10-Q pursuant to the rules and
regulations of the Securities and Exchange Commission. These financial
statements should be read in conjunction with the financial statements and notes
thereto included in the Company's 1999 Annual Report and 1998 Form 10-K.
NOTE 2. LONG TERM DEBT
At December 31, 1998, the Company was a party to a loan agreement with a
bank. Pursuant to the loan agreement, the Company was permitted to borrow up to
the lesser of $30,000,000 or the "borrowing base" then in effect. The borrowing
base in effect at December 31, 1998 was $21,100,000, which included (i) a
$19,100,000 revolving credit facility ("Revolving Facility") and (ii) a
$2,000,000 non-revolving line of credit ("Development Facility"). The borrowing
base was subject to reduction each month by a monthly commitment reduction of
$380,000 until April 1, 1999. The borrowing base and monthly commitment
reduction are subject to redetermination every six months on April 1 and October
1 of each year or at such other times as the bank elects. On March 23, 1999, the
Company entered into an agreement with its bank amending certain terms of the
loan agreement. Under the amendment, (i) the principal amount outstanding under
the Development Facility, $1,592,000, was included in the Revolving Facility,
(ii) the borrowing base was redetermined at $18,815,889 (iii) the unpaid
principal balance for the Revolving Facility bears interest at the bank's base
lending rate plus .25%, or 8% at March 31, 1999, and (iv) the monthly commitment
reduction was suspended until May 1, 1999, when the borrowing base and monthly
commitment reduction are scheduled for redetermination by the bank. As of the
date of this Form 10-Q Report, the Company had not received notice from its bank
lender of the redetermined borrowing base or monthly reduction amount. At March
31, 1999 the Company had borrowed all the funds currently available under its
revolving credit facility. Indebtedness under the Revolving Facility matures
July 1, 2001. The loan is secured by substantially all of the Company's oil and
gas properties. Commitment fees of .25% per annum on the difference between the
commitment and the average daily amount outstanding are due quarterly.
The unpaid principal balance for the Revolving Facility bears interest at
the election of the Company at a rate equal to (i) the bank's base lending rate
plus .25% or (ii) the bank's Eurodollar rate plus a margin of 2.5%. Interest
under the Revolving Facility is due and payable monthly.
The loan agreement contains various restrictive covenants and compliance
requirements, which include (1) maintenance of certain financial ratios, (2)
limiting the incurrence of additional indebtedness, and (3) prohibiting payment
of dividends on common stock and (4) prohibiting the payment of dividends on
preferred stock when an event of default under the loan agreement is in
existence.
NOTE 3. PREFERRED STOCK
The Company has outstanding 974,500 shares of its 6% Convertible Preferred
Stock, $0.10 par value per share (the "Preferred Stock"). Cumulative annual
dividends of $0.60 per share are payable semi-annually on June 15 and December
15 of each year. Each share of Preferred Stock may be converted, at the option
of the holder, into 2.8571 shares of common stock at an initial conversion price
of $3.50 per share, subject to adjustment in certain events. The preferred stock
has a liquidation preference of $10 per share and has no voting rights, except
as required by law.
The Company may redeem the Preferred Stock, in whole or part, after October
20, 1999, for $10 per share plus accrued and unpaid dividends.
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NOTE 4: FULL COST CEILING TEST
The Company uses the full cost method to account for its oil and gas
producing activities. Under the full cost method of accounting, the net book
value of oil and gas properties, less related deferred income taxes, may not
exceed a calculated "ceiling." The ceiling limitation is the discounted
estimated after-tax future net revenues from proved oil and gas properties. In
calculating future net revenues, current prices and costs are generally held
constant indefinitely. The net book value, less related deferred income taxes,
is compared to the ceiling on a quarterly and annual basis. Any excess of the
net book value, less related deferred income taxes, is generally written off as
an expense. Under the Securities and Exchange Commission rules and regulations,
the excess above the ceiling is not written off if, subsequent to the end of the
quarter or year but prior to the release of the financial results, prices
increased sufficiently such that an excess above the ceiling would not have
existed if the increased prices were used in the calculations.
During the fourth quarter of 1998, the Company recognized a non-cash
impairment charge of $14,757,028, or $12,269,834 net of tax, related to its oil
and gas reserves and unproved properties. The impairment of oil and gas assets
was primarily the result of the effect of significantly lower oil and natural
gas prices on both proved and unproved oil and gas properties. At March 31,
1999, the Company's net book value of oil and gas, less related deferred income
taxes, was below the calculated ceiling. As a result, the Company was not
required to record a reduction of its oil and gas properties under the full cost
method of accounting.
NOTE 5. NET INCOME PER COMMON SHARE
In 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No., 128, "Earnings per Share" ("FAS 128"). FAS
128 replaced the calculation of primary and fully diluted earnings per share
with basic and diluted earnings per share. Unlike primary earnings per share,
basic earnings per share excludes any dilutive effects of option, warrants and
convertible securities and is computed by dividing income available to common
stockholders by the weighted average number of common shares outstanding for the
period. Diluted earnings per share is computed similarly to the previously
reported fully diluted earnings per share and reflects the assumed conversion of
all potentially dilutive securities.
Three Months Ended
March 31,
1998 1999
---------- ----------
Basic EPS Computation:
Numerator -
Net income $ 72,826 $ (10,283)
Preferred stock dividends -- (170,538)
---------- ----------
Net income available to common Stockholders 72,826 (180,821)
========== ==========
Denominator -
Weighted average common shares outstanding 18,118,733 18,328,525
---------- ----------
Basic EPS $ .004 $ (.010)
========== ==========
Diluted EPS Computation
Numerator -
Net income $ 72,826 $ (10,283)
Preferred stock dividends -- (170,538)
---------- ----------
Net income available to common Stockholders 72,826 (180,821)
========== ==========
Denominator -
Weighted average common shares outstanding 18,118,733 18,328,525
Employee stock options 641,160 --
Warrants 22,060 --
---------- ----------
18,781,953 18,328,525
---------- ----------
Diluted EPS $ .004 $ (.010)
========== ==========
8
Employee stock options to purchase shares of common stock and convertible
preferred stock were outstanding during the three-month period ended March 31,
1999 but were not included in the computation of diluted net loss per share
because either (i) the employee stock options' exercise price was greater than
the average market price of the common stock of the Company, (ii) the effect of
the assumed conversion of the Company's preferred stock to common stock would be
antidilutive, or (iii) the Company had a net loss from continuing operations
and, therefore, the effect would be antidilutive.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
The following discussion and analysis should be read in conjunction with
the Company's Financial Statements and the related notes thereto.
OVERVIEW
The Company's long term business strategy is to increase the Company's
reserve base by utilizing 3-D seismic technology to obtain exploratory drilling
returns on capital invested with developmental drilling risks.
The Company intends to exploit its existing properties and acquire those
properties, which it believes can be exploited by developing reserves not
previously produced. The Company undertakes projects only when it believes the
project has the potential for initial cash flow adequate to return the project's
capital expenditures within a short period of time, generally less than 36
months. The Company also endeavors to maximize the present value of its projects
by accelerating production of its reserves consistent with prudent reservoir
management.
As part of this business strategy, the Company has made acquisitions of oil
and gas producing properties in the Permian Basin of West Texas and has
discovered oil and gas reserves through the use of 3-D seismic technology in the
Horseshoe Atoll Reef Trend of West Texas and the Yegua/Frio Gas Trend onshore
the Gulf Coast of Texas. Capital utilized to acquire such reserves has been
provided primarily by secured bank financing, sales of the Company's equity
securities and cash flow from operations.
The Company's operating performance is influenced by several factors, the
most significant of which are the prices received for its oil and gas and the
Company's production volumes. The world price for oil has overall influence on
the prices that the Company receives for its oil production. The prices received
for different grades of oil are based upon the world price for oil, which is
then adjusted based upon the particular grade. Typically, light oil is sold at a
premium, while heavy grades of crude are discounted. Gas prices the Company
receives are primarily influenced by seasonal demand, weather, hurricane
conditions in the Gulf of Mexico, availability of pipeline transportation to end
users and proximity of the Company's wells to major transportation pipeline
infrastructure and, to a lesser extent, world oil prices. Additional factors
influencing operating performance include production expenses, overhead
requirements, and cost of capital.
For the three months ended March 31, 1999, the average sales price received
by the Company for its crude oil production averaged $12.18 per barrel compared
with $14.08 per barrel at March 31, 1998 and $12.49 per barrel at December 31,
1998. The average sales price for natural gas during this same period was $2.03
per mcf compared with $2.09 per mcf at March 31, 1998 and $2.04 per mcf at
December 31, 1998.
The Company's oil and gas producing activities are accounted for using the
full cost method of accounting. Accordingly, the Company capitalizes all costs
incurred in connection with the acquisition of oil and gas properties and the
exploration for and development of oil and gas reserves. See Note 4 of Notes to
Financial Statements. These costs include lease acquisition costs, geological
and geophysical expenditures, costs of drilling both productive and
non-productive wells, and overhead expenses directly related to land acquisition
and exploration and development activities. Proceeds from the disposition of oil
and gas properties are accounted for as a reduction in capitalized costs, with
no gain or loss recognized unless such disposition involves a material change in
reserves, in which case the gain or loss is recognized.
Depletion of the capitalized costs of oil and gas properties, including
estimated future development costs, is provided using the equivalent
unit-of-production method based upon estimates of proved oil and gas reserves
and production, which are converted to a common unit of measure based upon their
relative energy content. Unproved oil and gas properties are not amortized, but
9
are individually assessed for impairment. The cost of any impaired property is
transferred to the balance of oil and gas properties being depleted.
The Company's production and results of operations vary from quarter to
quarter. Based on its scheduled drilling activities, the Company does not
currently anticipate that its production volumes in 1999 will increase
significantly compared to its production volumes in the prior year. However,
normal operating considerations and other factors could result in decreased
production for the year.
RESULTS OF OPERATIONS
Because of the Company's ever-changing reserve base and sources of
production, year to year or quarter to quarter comparisons of the Company's
results of operations can be difficult. This situation is further complicated by
significant changes in product mix (oil vs. gas volumes) and related price
fluctuations for both oil and gas. For these reasons, the table below compares
the Results of Operations on the basis of equivalent barrels of oil ("EBO") for
the period indicated. An EBO means one barrel of oil equivalent using the ratio
of six Mcf of gas to one barrel of oil.
THREE MONTHS ENDED THREE MONTHS ENDED
------------------------------------ ------------------------
9-30-98 12-31-98 3-31-99 3-31-98 3-31-99
-------- --------- -------- --------- ---------
Production and prices:
Oil (Bbls) 48,321 49,294 44,619 43,375 44,619
Natural gas (Mcf) 869,215 868,131 697,593 719,905 697,593
Equivalent barrels of oil(EBO) 193,190 193,982 160,884 163,359 160,884
Oil price (per Bbl) $12.15 $10.36 $12.18 $14.08 $12.18
Gas price (per Mcf) $ 2.25 $ 1.59 $ 2.03 $ 2.09 $ 2.03
Price per EBO $13.15 $ 9.77 $12.20 $12.93 $12.20
Results of operations per EBO
Oil and gas revenues $13.15 $ 9.77 $12.20 $12.93 $12.20
Costs and expenses:
Lease operating expense 3.22 3.31 3.19 3.41 3.19
General and administrative 1.18 1.30 1.26 1.35 1.26
Depreciation and depletion 5.77 14.73 5.62 5.70 5.62
Impairment of oil and
gas properties .00 76.07 .00 .00 .00
------ ------ ------ ------ ------
Total costs and expenses 10.17 95.41 10.07 10.46 10.07
------ ------ ------ ------ ------
Operating income 2.98 (85.64) 2.13 2.47 2.13
Interest expense, net (2.05) (1.73) (2.22) (1.86) (2.22)
Other income, net .03 1.49 .03 .06 .03
------ ------ ------ ------ ------
Pretax income .96 (85.88) (.06) .67 (.06)
Income tax (expense) benefit (.32) 16.94 .00 (.22) .00
------ ------ ------ ------ ------
Net income .64 (68.94) (.06) .45 (.06)
------ ------ ------ ------ ------
Income before working
capital adjustments $ 6.73 $ 4.92 $ 5.56 $ 6.37 $ 5.56
====== ====== ====== ====== ======
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The following table sets forth for the periods indicated the percentage of
total revenues represented by each item reflected on the Company's statements of
operations.
THREE MONTHS ENDED THREE MONTHS ENDED
------------------------------------ -----------------------
9-30-98 12-31-98 3-31-99 3-31-98 3-31-99
-------- -------- -------- -------- --------
Oil and gas revenues 100.0% 100.0% 100.0% 100.0% 100.0%
Costs and expenses:
Production costs 24.5 33.9 26.1 26.4 26.1
General and administrative 9.0 13.3 10.3 10.4 10.3
Depreciation, depletion and
amortization 43.8 150.8 46.0 44.1 46.0
Impairment of oil and gas
properties .0 778.6 .0 .0 .0
------ ------ ------ ------ ------
Total costs and expense 77.3 976.6 82.4 80.9 82.4
------ ------ ------ ------ ------
Operating income 22.7 (876.6) 17.6 19.1 17.6
------ ------ ------ ------ ------
Interest expense, net (15.6) (17.7) (18.2) (14.4) (18.2)
Other income, net .2 15.3 .2 .5 .2
------ ------ ------ ------ ------
Pretax income 7.3 (879.0) (.4) 5.2 (.4)
Income tax (expense) benefit (2.4) 173.4 .0 (1.7) .0
------ ------ ------ ------ ------
Net income 4.9% (705.6)% (.4)% 3.5% (.4)%
====== ====== ====== ====== ======
THREE MONTHS ENDED MARCH 31, 1998 AND 1999:
Oil and Gas Revenues. Oil and gas revenues decreased $149,474, or 7%, to
$1,963,089 for the three months ended March 31, 1999, from $2,112,563 for the
same period of 1998. The decrease was primarily the result of a 6% decrease in
the average sales price per EBO. The Company received $12.20 per EBO in the
three months ended March 31, 1999 compared with $12.93 per EBO for the same
period of 1998. In addition, oil and gas decreased 2,475 EBO, or 2%.
Approximately 80% of the decrease in revenues were attributable to the decrease
in the average sales price and approximately 20% of the decrease was
attributable to a decrease in oil and gas production volumes.
Production Costs. Production costs decreased $43,816, or 8%, to $513,882
during the first three months of 1999, compared with $557,638 for the same
period of 1998. Average production costs per EBO decreased 6%, to $3.19 for the
first three months in 1999 compared to $3.41 for the same period in 1998,
primarily a result of adding lower cost oil and gas production.
General and Administrative Expenses. General and administrative expenses
decreased by $17,152 or 8% to $203,237 for the first three months of 1999, from
$220,389 for the same period of 1998. The decrease was primarily due to a
decrease in communications expense and membership fees. General and
administrative expenses were $1.26 per EBO in the first three months of 1999
compared to $1.35 per EBO in the first three months of 1998. Future general and
administrative costs are expected to remain fairly stable with no material
increases expected in any particular category.
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense ("DD&A") decreased by $26,980, or 3%, to $903,836 for
the first three months of 1999 compared with $930,816 for the same period of
1998. As a percentage of revenues, the DD&A rate increased by 2% when compared
with the prior year first quarter, a result of decreased production volumes, a
decrease in the average sales price per EBO received by the Company and a
decrease in the DD&A rate per EBO. The DD&A rate per EBO decreased to $5.62 for
the first quarter 1999 compared with $5.70 per EBO for the first quarter of
1998. The decrease in the DD&A rate per EBO is attributable to a revision in the
Company's proven reserve estimates, primarily the result of lower oil and gas
prices in effect at December 31, 1998 compared with prices in effect at December
31, 1997, and a non-cash impairment charge incurred in the fourth quarter of
1998 that reduced the Company's full cost pool.
11
Historically, the Company has reviewed its estimates of proven reserve
quantities on an annual basis. However, due to the current uncertainty of oil
and gas prices, the Company conducts internal reviews of its estimated proven
reserves on a more frequent basis and makes necessary adjustment to its DD&A
rate accordingly. The Company believes periodic reviews and adjustments, if
necessary, will result in a more accurate reflection of its DD&A rate during the
year and minimize possible year-end adjustments.
Net Interest Expense. Interest expense increased $53,593, or 18%, to
$357,795 for the three months ended March 31, 1999 compared with $304,202 for
the same period of 1998; due principally to increased borrowings against the
Company's revolving line of credit during 1998, when substantially lower oil and
gas prices adversely affected cash flow.
Net Income and Operating Cash Flow. Net income decreased $83,109, or 114%,
to $(10,283) for the three months ended March 31, 1999, compared to $72,826 for
the three months ended March 31, 1998. Operating cash flow decreased $145,958,
or 14%, to $893,553 for the three months ended March 31, 1999 compared to
$1,039,511 for the three months ended March 31, 1998. The decrease in net income
and operating cash flow resulted from a 7% decrease in oil and gas revenues, and
an 18% increase in interest expense partially offset by an 8% decrease in
production costs, an 8% decrease in general and administrative costs, and a 3%
decrease in DD&A.
LIQUIDITY AND CAPITAL RESOURCES
Working capital increased $641,319 as of March 31, 1999 compared to
December 31, 1998. Current assets exceeded current liabilities by $770,132 at
March 31, 1999 compared to $128,813 at December 31, 1998. Current assets
increased primarily due to an increase of $261,348 in cash offset by a decrease
of $48,845 in prepaid expenses and a decrease in accounts receivable of
$134,905. The Company continues to employ 3-D seismic technology in conjunction
with its drilling activities, which are concentrated on certain gas prospects
located onshore, the Texas Gulf Coast.
The Company incurred net property costs of $864,364 primarily for its oil
and gas property acquisition, development, and enhancement activities for the
three months ended March 31, 1999. Such costs were financed by the utilization
of the Company's cash provided by operations, proceeds from the sale of certain
properties, cash provided by its line of credit and net proceeds from the
issuance of preferred stock.
Based on the Company's projected oil and gas revenues and related expenses,
management believes that its internally generated cash flow will be sufficient
to fund its normal operations, interest expense or on bank debt and preferred
stock dividends. The Company continually reviews and considers alternative
methods of financing.
TRENDS AND PRICES
The Company's revenues, cash flows and borrowing capacity are affected by
changes in oil and gas prices. The markets for oil and gas have historically
been, and will continue to be, volatile. Prices for oil and gas typically
fluctuate in response to relatively minor changes in supply and demand, market
uncertainty, seasonal, political and other factors beyond the control of the
Company. The Company is unable to accurately predict domestic or worldwide
political events or the effects of such other factors on the prices received by
the Company for its oil and gas. The Company historically has not entered into
transactions to hedge against changes in oil and gas prices, but may elect to
enter into hedging transactions in the future to protect against fluctuations in
oil and gas prices.
Industry conditions deteriorated significantly during 1998 and the first
three months of 1999 as a result of declining oil prices and weakening gas
prices. There is an excess supply of, and reduced demand for, crude oil
worldwide. This excess supply has placed downward pressure on oil prices in the
United States as well as worldwide. Natural gas prices also declined in 1998,
primarily because cold weather failed to develop in key demand areas. In April
1999, the price the Company received for its oil production increased to
approximately $16.00 per barrel while the gas price received was approximately
$2.00 per mcf. There is substantial uncertainty regarding future oil and gas
prices. There can be no assurance that oil and gas prices will not decline in
the future.
Because of the recent and sustained deterioration in prices the Company
receives for oil and gas produced, the capital normally available to the Company
12
from its cash flow and bank borrowings has been significantly reduced. In
January, 1998, the Company was receiving approximately $17.00 per barrel of oil
and $2.70 per Mcf of gas for the oil and gas it produced. Since then, oil prices
have been as low as $10.00 per barrel, the lowest level seen since the Company
was formed in 1979. At January 1, 1999, the Company received approximately
$10.50 per barrel of oil and $2.00 per Mcf of gas. Primarily as a result of the
decline in prices of oil and gas, the Company experienced a significant decline
in operating cash flow and revenues. In April, 1999, oil prices increased to
approximately $16.00 per barrel of oil, while gas prices have remained at
approximately $2.00 per Mcf. There can be no assurance that oil and gas prices
will not decline in the future.
The Company's capital expenditure budget for 1999 is highly dependent on
future oil and gas prices and will be consistent with internally generated cash
flows. If the prices received for oil and gas production improve, increasing
cash flow, or if the Company is successful in raising additional capital, 1999
planned drilling activity maybe increased.
During 1998, the average sales price received by the Company for its oil
was approximately $12.49 per barrel while the average sales prices for the
Company's gas was approximately $2.04 per thousand cubic feet ("Mcf"). At March
31, 1999, the average price received by the Company for its oil production was
approximately $12.18 per Bbl, while the average price received by the Company,
at that same date, for its gas production was approximately $2.03 per Mcf.
INFORMATION SYSTEMS FOR THE YEAR 2000
The Company places a high priority on resolving the computer or embedded
chip problems related to the Year 2000 that might cause operational disruptions.
Its Year 2000 project addresses the inability of computer software; hardware or
equipment with embedded microprocessors that are time sensitive to process
correctly dates data beginning on January 1, 2000. This problem results from
computer programs using two digits rather than four to define an applicable
year.
In planning and developing the project, the Company considered both its
information technology, or IT, systems and non-IT systems. IT systems generally
include computer equipment and software. Alarm systems, fax machines, monitors
for field operations and other miscellaneous systems, which may contain embedded
technology, are considered non-IT systems. These types of systems are more
difficult to assess and repair than IT systems.
The scope of the project includes:
. conducting an inventory of software, hardware and embedded systems
equipment;
. assessing the potential for failure and the associated risk;
. prioritizing the need for remediation, repairing or replacing significant
non-compliant items; and
. testing any modifications to ensure Year 2000 compliance.
Additionally, the project assesses the risks associated with the Year 2000
compliance of material business partners.
The assessment phase of the Company's Year 2000 project is at varying
stages of completion as it pertains to IT and non-IT systems and applications.
The Company has begun a comprehensive analysis of the operational problems and
costs that would be reasonably likely to result from the failure by it and
significant third parties to complete efforts necessary to achieve Year 2000
compliance on a timely basis.
The Company believes its most significant risks will be in two areas:
. measuring the quantities of oil and natural gas produced; and
. receiving timely payment from the purchasers of its gas and oil.
The Company also depends upon third parties for most of its non-information
technology systems such as:
. telephones;
13
. facsimile machines;
. air conditioning;
. heating;
. elevators in the office building; and
. other equipment which may have embedded technology such as
microprocessors.
Many systems owned or controlled by third parties and that the Company is
dependent upon, including non-information technology systems, may or may not be
Year 2000 compliant. Written inquiries have been sent to these third parties,
but most of this technology is outside of the Company's control and it is
difficult to assess or remedy any non-compliance that could adversely affect the
Company's ability to conduct business.
In December, 1998, letters were mailed to significant vendors, service
providers and business partners to determine the extent to which interfaces with
such entities are vulnerable to Year 2000 issues and whether the products and
services purchased from or provided by such entities are Year 2000 compliant.
Written assurances have been obtained from the Company's bank lender, major
purchasers of production and its accounting software provider indicating that
they are or will be Y2K compliant by the end of the year. However, the Company
is mindful that its own level of readiness is partially dependent on the ability
of these and other third parties to be fully compliant. The failure of third
parties to be Y2K compliant creates a likelihood that the Company will also
experience Y2K interruptions through a "ripple effect" stemming from external
forces.
The remedial phase of the project is also at varying stages of completion.
The remedial phase includes the upgrade and/or replacement of software
applications and hardware systems. Most of the software providers for the
Company's personal computers have confirmed their readiness for the Year 2000 or
have provided updates to correct most identified Year 2000 problems. Based on
identification and assessment efforts to be completed by the end of the second
quarter of 1999, the Company plans to replace or upgrade critical hardware and
software to become Year 2000 compliant. This phase of the project is also
expected to be completed by the end of the second quarter of 1999. Other
activities either underway or scheduled include the testing of its desktop
computers and local area network and conducting an inventory of embedded systems
in field locations that could affect its operations.
It is impossible to accurately predict all potential Y2K problems and the
magnitude of any adverse effects on the Company. Because of these uncertainties,
the Company is developing a contingency plan to minimize potential business
interruptions. In preparing contingency plans, the Company assumes that many
third parties will not be Y2K compliant. The Company's remediation efforts are
expected to reduce significantly the Company's level of uncertainty about Year
2000 compliance and the possibility of interruptions of normal business
operations. After completion of the Year 2000 review and testing, which is
currently expected to be completed by June 30, 1999, the Company will further
develop a contingency plan as required. This plan is expected to be completed by
September 30, 1999.
The following table summarizes the current overall status of the Company's
project and lists anticipated completion dates for each phase of the project.
Phase
----------------------------------------------------------------------------------------
Component Inventory Assessment Remediation
- -------------------------------------------------------------------------------------------------------------
Business Partners January 31, 1999 May 31, 1999 June 30, 1999
Software April 30, 1999 May 31, 1999 June 30, 1999
Hardware April 30, 1999 May 31, 1999 June 30, 1999
Embedded Systems April 30, 1999 May 31, 1999 June 30, 1999
14
To date, only minor costs have been incurred for project planning.
Substantially all of the personnel working on the project to identify, assess,
remediate and test Year 2000 issues are existing employees. Therefore, labor
costs incurred in connection with the project are expected to be minimal. Based
on current information, the Company does not anticipate that the costs
associated with any necessary in-house modifications will be material to its
operations or financial condition. The total cost of the project is expected to
range from $10,000 to $20,000.
The failure to correct a material Year 2000 problem could result in an
interruption in, or a failure of, certain normal business activities or
operations that could materially and adversely affect the Company's operations,
liquidity and financial condition. Because of the uncertainty surrounding Year
2000 issues, primarily those associated with third party suppliers and material
business partners; the Company is unable to determine at this time whether Year
2000 failures will have a material impact on its operations. However, the
project is expected to reduce the risk of Year 2000 issues significantly,
particularly regarding the compliance and readiness of the Company's material
vendors, suppliers and business partners. The Company believes that the timely
completion of this project will reduce the possibility of significant
interruptions of normal business operations.
This is a flexible plan that will change to address additional Y2K issues
as new problems are identified. As a result, any time and costs estimates and
the assessment of risks associated with Y2K issues are subject to revision as
needed to meet the Company's goal to be Y2K compliant.
FORWARD-LOOKING STATEMENTS
In addition to historical information contained herein, this Form 10-Q
Report contains forward-looking statements subject to various risks and
uncertainties that could cause the Company's actual results to differ materially
from those in the forward-looking statements. Forward-looking statements can be
identified by the use of forward-looking terminology such as "may," "will,"
"expect," "intend," "anticipate," "estimate," "continue," "present value,"
"future," "reserves" or other variations thereof or comparable terminology.
Factors, that could cause or contribute to such differences could include, but
are not limited to, those relating to the Company's growth strategy, outstanding
indebtedness, changes in interest rates, dependence on weather conditions,
seasonality, expansion and other activities of competitors, changes in federal
or state environmental laws and the administration of such laws, and the general
condition of the economy and its effect on the securities market. While the
Company believes its forward-looking statements are based upon reasonable
assumptions, there are factors that are difficult to predict and that are
influenced by economic and other conditions beyond the Company's control.
Investors are directed to consider such risks and other uncertainties discussed
in documents filed by the Company with the Securities and Exchange Commission.
ITEM 3. QUANTITATIVE AND QUALITIVE DISCLOSURES ABOUT MARKET RISK
The Company does not have or trade in derivative financial instruments and
does not have firmly committed sales transactions. The Company has not entered
into hedging arrangements and does not have any delivery commitments. While
hedging arrangements reduce exposure to losses as a result of unfavorable price
changes, they also limit the ability to benefit from favorable market price
changes.
The Company's major market risk exposure is in the pricing applicable to
its oil and natural gas production. Realized pricing is primarily driven by the
prevailing domestic price for crude oil and spot prices applicable to the region
in which the Company produces natural gas. Historically, prices received for oil
and gas production have been volatile and unpredictable. Pricing volatility is
expected to continue. Oil prices ranged from a monthly low of $9.74 per barrel
to a monthly high of $11.04 per barrel during first quarter 1999. Natural gas
prices the Company received during first quarter 1999 ranged from a monthly low
of $1.73 per Mcf to a monthly high of $2.06 per Mcf. A significant decline in
the prices of oil and natural gas could have a material adverse effect on the
Company's financial condition and results of operations.
The Company's only financial instrument sensitive to changes in interest
rates is its bank debt. The Company's annual interest costs in 1999 will
fluctuate based on short-term interest rates. As the interest rate is variable
15
and reflects current market conditions, the carrying value approximates the fair
value. The table below shows principal cash flows and related weighted average
interest rates by expected maturity dates. Weighted average interest rates were
determined using weighted average interest paid and accrued in December, 1998.
1999 2000 2001 Total Fair Value
----- ----- ---- ----- ----------
(in 000's, except interest rates)
Variable rate debt:
Revolving Facility (secured) $18,036 $18,036 $18,036
Average interest rate 7.50% 7.50% 7.50%
PART II - OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
3.1 Certificate of Incorporation of Registrant. (Incorporated by reference
to Exhibit 3.1 to Form 10-K of the Registrant for the fiscal year
ended December 31, 1998)
3.2 Bylaws of Registrant (Incorporated by reference to Exhibit 3.2 to Form
10-K of the Registrant for the fiscal year ended December 31, 1995)
4.1 Certificate of Designations, Preferences and Rights of Serial Preferred
Stock - 6% Convertible Preferred Stock (Incorporated by reference to
Exhibit 4.1 to Form 10-Q of the Registrant for the fiscal quarter
ended September 30, 1998)
*27. Financial Data Schedule
(b) Reports on Form 8-K
No reports were filed on Form 8-K during the quarter ended
March 31, 1999.
- -----------------------
* Filed herewith.
16
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
PARALLEL PETROLEUM CORPORATION
BY: /s/ THOMAS R. CAMBRIDGE
Date: May 14, 1999 ------------------------------
Thomas R. Cambridge
Chairman of the Board of Directors
and Chief Executive Officer
Date: May 14, 1999 BY: /s/ LARRY C. OLDHAM
------------------------------
Larry C. Oldham,
President and Principal
Financial Officer