SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
Amendment No. 1
[X] Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2000
[ ] 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
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State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
110 North Marienfeld Street
One Marienfeld Place, Suite 465
Midland, Texas 79701
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(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code: (915) 684-3727
Securities Registered Pursuant to Section 12(b) of the Act: None
Securities Registered Pursuant to Section 12(g) of the Act:
Common Stock, $.01 par value
Common Stock Purchase Warrants
Rights to Purchase Series A Preferred Stock
(Title of Class)
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 by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of voting and non-voting common equity held by
non-affiliates of the Registrant as of March 15, 2001 was approximately
$91,929,861, based on the last sale price of the common stock on the same date.
At March 15, 2001 there were 20,428,858 shares of common stock outstanding.
(i)
FORM 10-K/A
PARALLEL PETROLEUM CORPORATION
TABLE OF CONTENTS
Item No. Page
PART I
Item 1. Business 1
Item 2. Properties 22
Item 3. Legal Proceedings 24
Item 4. Submission of Matters to a Vote
of Security Holders 24
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 25
Item 6. Selected Financial Data 26
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 27
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 38
Item 8. Financial Statements and Supplementary Data 39
Item 9. Changes in and Disagreements with
Accountants on Accounting and Financial
Disclosure 39
PART III
Item 10. Directors and Executive Officers of the Registrant 40
Item 11. Executive Compensation 42
Item 12. Security Ownership of Certain Beneficial Owners
and Management 48
Item 13. Certain Relationships and Related Transactions 50
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 51
Explantory Note:
This amendemnt corrects the description of general and administrative expenses
under Item 7 for the years ended December 31, 2000 and December 31, 1999.
(ii)
Cautionary Statements Regarding Forward-Looking Statements
Some statements contained in our Form 10-K report are "forward-looking
statements". All statements other than statements of historical facts included
in this report, including, without limitation, statements regarding planned
capital expenditures, the availability of capital resources to fund capital
expenditures, estimates of proved reserves, our financial position, business
strategy and other plans and objectives for future operations, are
forward-looking statements. You can identify forward-looking statements by the
use of forward-looking terminology such as "may," "will," "expect," "intend,"
"anticipate," "estimate," "continue," "present value," "future" or "reserves" or
other variations or comparable terminology. Although we believe the assumptions
and expectations reflected in these forward-looking statements are reasonable,
we can't give any assurance that our expectations will prove to be correct or
that we will be able to take any actions that are presently planned. All of
these statements involve assumptions of future events and risks and
uncertainties. Risks and uncertainties associated with forward-looking
statements include, but are not limited to:
risks associated with the drilling of wells;
competition;
future capital requirements and availability of financing;
fluctuations in prices of oil and gas;
governmental regulations;
geological concentration of our reserves; and
general economic conditions.
For these and other reasons, actual results may differ materially from
those projected or implied. We caution you against putting undue reliance on
forward-looking statements or projecting any future results based on such
statements.
Before you invest in our common stock, you should be aware that there are
various risks associated with an investment. We have described some of these
risks in other sections of this annual report and under the section Risk Factors
beginning on page 18 of this annual report.
1
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis are intended to assist you in
understanding our financial position and results of operations for each year in
the three-year period ended December 31, 2000. You should read the following
discussion and analysis in conjunction with our financial statements and the
related notes.
The following discussion contains forward-looking statements. For a
description of limitations inherent in forward-looking statements, see
"Cautionary Statement Regarding Forward-Looking Statements" on page ii.
Basis of Presentation
We account for our 30.675% interest in First Permian using the equity
method of accounting. Under the equity method of accounting, we record our
investment in First Permian at cost on the balance sheet. This is increased or
reduced by our proportionate share of First Permian's income or loss, which is
presented as one amount in the statement of income. Our 30.675% share of First
Permian's oil and gas reserves is presented separately under our oil and gas
reserve information in Note 15 to the Financial Statements.
At December 31, 2000, we had recorded a loss of $500,576 in our investment
in First Permian. Our loss is recorded as a net liability in our investment to
the extent that we had guaranteed $10,000,000 of the debt of First Permian.
Effective October 25, 2000, we were released from this guarantee and , although
we continue to utilize the equity method of accounting, our financial statements
no longer include First Permian's losses because we are released from our
guarantee. To the extent First Permian generates income in excess of losses, we
will then recognize our share of the net income on our financial statements.
General
Our primary objectives are to build oil and gas reserves, production, cash
flow and earnings per share by exploring for new oil and gas reserves, acquiring
oil and gas properties and optimizing production from existing oil and gas
properties. Management seeks to achieve these objectives by:
using advanced technologies to conduct exploratory activities;
acquiring producing properties we believe add incremental value to our
asset base;
keeping debt levels low;
concentrating activities in core areas to achieve economies of scale; and
emphasizing cost controls.
Since 1992, our primary focus has been exploratory drilling using 3-D
seismic technology. Our long term business strategy is to increase our reserve
base by using this and other advanced technologies. Additionally, we intend to
exploit our existing properties and to acquire properties we believe can be
exploited by developing reserves not previously produced.
2
We undertake projects only when we believe 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. We also endeavor
to maximize the present value of our projects by accelerating production of our
reserves consistent with prudent reservoir management and prevailing energy
prices.
Following this strategy, we have discovered oil and gas reserves using 3-D
seismic technology in the Horseshoe Atoll Reef Trend of west Texas and the
Yegua/Frio/Wilcox gas trend onshore the gulf coast of Texas. Additionally, we
have acquired producing oil and gas properties in the Permian Basin of west
Texas. Capital used to acquire these properties has been provided primarily by
secured bank financing, sales of our equity securities and cash flows from
operations.
Operating Performance
Our operating performance is influenced by several factors, the most
significant of which are the prices we receive for our oil and gas and our
production volumes. The world price for oil has overall influence on the prices
that we receive for our 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 we receive are influenced by:
seasonal demand;
weather;
hurricane conditions in the Gulf of Mexico;
availability of pipeline transportation to end users;
proximity of our wells to major transportation pipeline infrastructures;
and
to a lesser extent, world oil prices.
Additional factors influencing our overall operating performance include:
production expenses;
overhead requirements; and
costs of capital.
Our oil and gas exploration, development and acquisition activities require
substantial and continuing capital expenditures. Historically, the sources of
financing to fund our capital expenditures have included:
cash flow from operations,
sales of our equity securities, and
bank borrowings.
Our oil and gas producing activities are accounted for using the full cost
method of accounting. Under this method, we capitalize 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 11 to the Financial
3
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
are individually assessed for impairment. The cost of any impaired property is
transferred to the balance of oil and gas properties being depleted.
Depletion per equivalent unit of production EBO was $8.18 versus $8.30 in
1999 and $8.07 in 1998. The decrease per BOE in 2000 was a result of a decrease
of $2,890,373 in the net oil and gas properties depletable base coupled with a
disproportionate decrease in total beginning of the year reserves of 289,156
BOEs.
Results of Operations
Our business activities are characterized by frequent, and sometimes
significant, changes in our:
reserve base;
sources of production;
product mix (oil versus gas volumes); and
the prices we receive for our oil and gas production.
Year-to-year or other periodic comparisons of the results of our operations
can be difficult and may not fully and accurately describe our condition. The
following table shows selected operating data for each of the three years ended
December 31, 2000, 1999 and 1998.
4
Year Ended December 31,
-------------------------------------------
2000 1999(1) 1998(2)
---------- ----------- -----------
Production and prices:
Oil (Bbls) 165,137 163,696 185,474
Natural gas (Mcf) 2,821,815 2,708,516 3,275,882
EBO (Bbls) 635,440 615,115 731,454
Oil price (per Bbl) $ 28.88 $ 17.32 $ 12.49
Gas price (per Mcf) $ 4.38 $ 2.27 $ 2.04
Ratio of oil to gas price 6.59/1 7.63/1 6.12/1
Increase (decrease) in production
volumes over prior year 3% (16%) (1%)
Results of operations per EBO:
Oil and gas revenues $ 26.96 $ 14.59 $ 12.31
Costs and expenses:
Production costs 4.88 3.83 3.33 -
General and administrative 1.88 1.31 1.17
Provision for losses on trade receivables - .14 .06
Depreciation, depletion and amortization 8.25 8.49 8.16
Impairment of oil and gas properties - 2.77 20.17
--------- ---------- ----------
Total costs and expenses 15.01 16.54 32.89
--------- ---------- ----------
Operating income (loss) 11.97 (1.95) (20.58)
Equity interest in earnings (loss) of
First Permian, L.L.C. (0.79) 0.32 -
Interest expense, net (1.76) (2.39) (1 .89)
Other income, net .19 .03 .46
--------- ---------- ----------
Pretax income (loss) per EBO $ 9.61 $ (3.99) $ (22.01)
========= ========== ==========
-------------------
(1) Results include a noncash charge of $1,705,000 related to the impairment of
oil and gas properties incurred in the fourth quarter of 1999, primarily a
result of a decrease in year-end reserves.
(2) Results include a noncash charge of $14,757,028 related to the impairment
of oil and gas properties incurred in the fourth quarter of 1998, primarily
a result of low oil and gas prices at year-end.
The following table shows the percentage of total revenues represented by
each item reflected on our statements of operations for the periods indicated.
5
Year Ended December 31,
-------------------------------------
2000 1999(1) 1998(2)
------- -------- -------
Oil and gas revenues 100.0% 100.0% 100.0%
Costs and expenses:
Production costs 18.1 26.2 27.0
General and administrative 6.9 8.9 9.5
Provision for loss on trade receivables - 1.0 .5
Depreciation, depletion and
amortization 30.6 58.2 66.3
Impairment of oil and gas properties - 19.0 163.9
------- ------- -------
Total costs and expenses 55.6 113.3 267.2
------- ------- -------
Total costs and expenses
Operating income (loss) 44.4 (13.3) (167.2)
Equity interest in earnings (loss) of
First Permian, L.L.C. (2.9) 2.2 -
Interest expense, net (6.5) (16.4) (15.3)
Other income, net .7 .2 3.8
------- ------- -------
Pretax income (loss) 35.7 (27.3) (178.7)
Income tax (expense) benefit (0.8) - 34.4
------- ------- -------
Net income (loss) 34.9% (27.3%) (144.3%)
------- ------- -------
-------------------
(1) Results include a noncash charge of $1,705,000 related to the impairment of
oil and gas properties incurred in the fourth quarter of 1999, primarily a
result of a decrease in year-end reserves.
(2) Results include a noncash charge of $14,757,028 related to the impairment
of oil and gas properties incurred in the fourth quarter of 1998, primarily
a result of low oil and gas prices at year-end.
Years Ended December 31, 2000 and December 31, 1999
Oil and Gas Revenues. Parallel's total oil and gas revenues for 2000 were
$17,134,502, an increase of $8,160,461, or approximately 91%, from $8,974,041
for 1999. The increase in revenues for 2000 when compared with 1999 is related
to a 3% increase in production volumes and an 85% increase in the average price
per EBO we received for our oil and gas sales.
Production. On an equivalent barrel basis, production volumes in 2000
totaled 635,440 EBOs compared with 615,115 EBOs in 1999. The 3% increase in
production was primarily due to increased drilling activity in 2000, which
resulted in more wells being placed in production.
Production Costs. The rise in production costs for 2000, when compared with
1999, was primarily the result of increased production taxes associated with
increased revenues and, to a lesser degree, a slight increase in production
volumes. Production costs increased $745,802 or 32%, to $3,099,534 for the
twelve months ended December 31, 2000, from $2,353,732 for the same period of
6
1999. Production costs as a percentage of revenues decreased primarily because
of higher oil and gas prices, which resulted in higher revenues. Average
production costs per EBO increased 27% to $4.88 for the twelve months ended
December 31, 2000 compared to $3.83 in the same period of 1999, primarily
because of increased production taxes.
General and Administrative Expenses. General and administrative expenses
increased $385,593, or 48%, to $1,191,527 for the year ended December 31, 2000,
from $805,934 in 1999. The increase was primarily related to increases in
legal and public reporting costs. General and administrative expenses as a
percentage of revenues decreased to 6.9% for the year ended December 31, 2000
versus 8.9% for the same period in 1999. This decrease is primarily a result of
higher oil and gas prices, which increased revenues.
Depreciation, Depletion and Amortization Expense. DD&A expenses for 2000
increased $15,705 to $5,239,205 versus $5,223,500 in 1999. This increase was
primarily the result of a 3% increase in production volumes. DD&A expense as a
percentage of revenues decreased primarily because of higher oil and gas
revenues.
Impairment of Oil and Gas Properties. During 2000, we did not recognize any
impairment charge. During the fourth quarter of 1999, we recognized a noncash
impairment charge of $1,705,000 related to our oil and gas reserves and unproved
properties. The impairment of oil and gas assets in 1999 was primarily the
result of a decrease in our year-end proved reserves.
Under full cost accounting rules, each quarter we are required to perform a
ceiling test calculation. The full cost pool carrying values cannot exceed a
company's future net revenues from its proved reserves, discounted at 10% per
annum using constant current product prices, and the lower of cost or market of
unproved properties.
The ceiling test was computed using the net present value of reserves at
December 31, 2000 based on prices of $25.00 per Bbl of oil and $10.18 per Mcf of
natural gas. The prices used to compute the ceiling test in 1999 were $24.75 per
Bbl and $2.20 per Mcf.
Net Interest Expense. Net interest expense decreased $349,127, or 24%, to
$1,120,080 for the year ended December 31, 2000 compared with $1,469,207 for the
same period of 1999. This decrease was principally a result of lower average
borrowings from our revolving line of credit facility and an increase in
interest income.
Income Tax Benefit (Expense). For the year ended December 31, 2000, we
recognized tax expense of $130,000. For the year ended December 31, 1999, we did
not recognize an income tax benefit or expense.
Our effective tax rate for 2000 was approximately 2.1% versus 0% in 1999.
You should read Note 5 to the Financial Statements on page F-14, included in
Item 8 - Financial Statements and Supplementary Data, for further discussion of
our income tax provisions and benefits.
Net Income (Loss) and Operating Cash Flow. Our net income, before preferred
stock dividends, was $5,977,328 for the year ended December 31, 2000 compared
with a net loss of $2,450,457 for the year ended December 31, 1999. We realized
net income in 2000 primarily because of substantially higher oil and gas prices,
which increased revenues, and a 3% increase in production volumes. The 1999 loss
was primarily caused by a fourth quarter 1999 noncash impairment charge to oil
and gas properties totaling $1,705,000 and decreased revenues resulting from a
decline in production volumes.
7
Operating cash flow for 2000 increased approximately $7,566,877, or 177%,
to $11,847,109 compared with $4,280,232 for the year ended December 31, 1999.
Years Ended December 31, 1999 and December 31, 1998
Oil and Gas Revenues. Our total oil and gas revenues for 1999 were
$8,974,041, a decrease of $27,541, or less than 1%, from $9,001,582 for 1998.
The decrease in revenues for 1999, compared with 1998, is related to a 16%
decline in production volumes, which was partially offset by higher oil and gas
prices.
Production. On an equivalent barrel basis, 1999 production totaled 615,115
EBOs compared with 731,454 EBOs in 1998. The decrease in production was
primarily due to normal production declines associated with producing wells and
decreased drilling activity in 1999, which affected our ability to replace oil
and gas produced during the year.
Production Costs. The decrease in production costs for 1999, when compared
with 1998, was primarily the result of a decrease in production volumes.
Production costs decreased $80,926, or 3%, to $2,353,732 for the twelve months
ended December 31, 1999, from $2,434,658 for the same period of 1998. Production
costs as a percentage of revenues decreased primarily because of higher oil and
gas prices. Average production costs per EBO increased 15% to $3.83 for the
twelve months ended December 31, 1999 compared with $3.33 in the same period of
1998, primarily because of lower production volumes and the fixed costs
associated with producing wells.
General and Administrative Expenses. General and administrative expenses
decreased $49,854, or 6%, to $805,934 for the year ended December 31, 1999, from
$855,788 for the same period of 1998. The decrease in general and administrative
expenses was primarily related to a decrease in property insurance costs and
legal expenses. General and administrative expenses as a percentage of revenues
decreased to 8.9% for the year ended December 31, 1999 versus 9.5% for the same
period in 1998. This decrease is primarily a result of higher oil and gas prices
and a 6% decline in general and administrative expenses.
Depreciation, Depletion and Amortization Expense. DD&A expenses for 1999
decreased $742,721, or 12%, to $5,223,500 versus $5,966,221 in 1998. This
decrease was a result of lower production volumes. DD&A expense as a percentage
of revenues decreased primarily because of lower production volumes.
Impairment of Oil and Gas Properties. During the fourth quarter of 1999, we
recognized a noncash impairment charge of $1,705,000 related to our oil and gas
reserves and unproved properties. The impairment of oil and gas assets was
primarily the result of a decrease in our year-end proved reserves. We
recognized an impairment charge in 1998 of $14,757,028, or $12,269,834 net of
tax, related to our oil and gas reserves and unproved properties. The impairment
of oil and gas assets in 1998 was primarily the result of the effect of
significantly lower oil and natural gas prices on both proved and unproved oil
and gas properties.
Under full cost accounting rules, each quarter we are required to perform a
ceiling test calculation. The full cost pool carrying values cannot exceed a
company's future net revenues from its proved reserves, discounted at 10% per
annum using constant current product prices, and the lower of cost or market of
unproved properties.
8
The ceiling test was computed using the net present value of reserves at
December 31, 1999 based on prices of $24.75 per Bbl of oil and $2.20 per Mcf of
natural gas. The prices used to compute the ceiling test in 1998 were $10.50 per
Bbl and $2.00 per Mcf.
Net Interest Expense. Net interest expense increased $90,875, or 6%, to
$1,469,207 for the year ended December 31, 1999, from $1,378,332 for the same
period of 1998. This increase was principally a result of an increase in average
borrowings from our revolving line of credit facility.
Income Tax Benefit (Expense). For the year ended December 31, 1999, we did
not recognize an income tax benefit or expense because we generated net tax
losses during the year. For the year ended December 31, 1998, we recognized a
tax benefit of $3,100,027. At December 31, 1999 and 1998, we reviewed our
deferred tax assets and, in light of the current economic conditions in the oil
and gas industry, the outlook for future commodity prices, and our expected
operational results in future periods, we believe that some of our net operating
losses may expire unused. Therefore, we established a valuation allowance
against them of $4,248,480 and $2,530,196 for 1999 and 1998, respectively.
Our effective tax rate for 1999 was approximately 0% versus a 19% benefit
in 1998. You should read Note 5 to the Financial Statements on page F-14,
included in Item 8 - Financial Statements and Supplementary Data, for further
discussion of our income tax provisions and benefits.
Net Income (Loss) and Operating Cash Flow. Our net loss, before preferred
stock dividends, was $2,450,457 for the year ended December 31, 1999 compared
with a net loss of $12,995,910 for the year ended December 31, 1998. The 1999
loss was primarily caused by a fourth quarter 1999 noncash impairment charge to
oil and gas properties totaling $1,705,000 as a result of a decrease in proved
reserves and a decline in production volumes. This compares with a fourth
quarter 1998 noncash impairment charge to oil and gas properties totaling
$14,757,028, the result of significantly lower oil and gas prices at year-end
1998.
Factors contributing to the net loss were partially offset by a 19%
increase in 1999 oil and gas prices, on an EBO basis, when compared with 1998
prices.
Operating cash flow for 1999 decreased approximately $347,000, or 8%, to
$4,280,232 compared with $4,627,312 for the year ended December 31, 1998. Other
sources of funds included net proceeds of $17,188 from the exercise of stock
options, net proceeds of $3,117,295, excluding offering costs, from the private
placement of common stock, net proceeds from property sales totaling $1,111,525
and bank borrowings under our credit facility.
Capital Resources and Liquidity
Our capital resources consist primarily of cash flows from our oil and gas
properties and bank borrowings supported by our oil and gas reserves. Our level
of earnings and cash flows depends on many factors, including the price of oil
and natural gas.
Our primary source of cash during 2000 was funds generated from operations.
Such funds were used primarily for exploration and development expenditures,
preferred stock dividend payments and the repayment of borrowings under our bank
credit facility.
During 2000, we spent $6,645,737 on exploration and development, seismic
data processing and leasehold acquisitions. Long term debt, excluding current
maturities, decreased by $676,000 to $11,624,000. At December 31, 2000, Parallel
had $2,000,826 in cash and total assets of $46,456,437. The
9
unused borrowing base available from our revolving credit facility was
approximately $3,100,000 at December 31, 2000.
Bank Facility
On December 18, 2000, we entered into a new loan agreement with Bank
United, Midland, Texas, to refinance the outstanding indebtedness under the loan
agreement with our former bank lender, and to provide funds for working capital.
The loan agreement provides for a revolving credit facility under which we may
borrow up to the lesser of $30.0 million or the borrowing base amount in effect
from time to time. At December 31, 2000, the borrowing base in effect was $15.5
million, and $12.4 million, bearing interest at 9.5%, was outstanding under the
credit facility. The interest rate on amounts drawn under the revolving credit
facility is, at our election, either the bank's base rate or the eurodollar rate
plus a margin of 2.75% during the related eurodollar interest rate period. The
borrowing base is redetermined by the bank semi-annually on or about May 1 and
November 1 of each year, or at other times as the bank elects. The borrowing
base automatically reduces by $323,000 each month beginning January 1, 2001. If
the outstanding principal amount of our loan ever exceeds the borrowing base, we
are required to either provide additional collateral to the bank or prepay the
principal of the note in an amount at least equal to such excess. Unless there
is a borrowing base deficiency and we prepay the amount of the deficiency,
interest only is payable monthly. The revolving credit facility matures on
October 1, 2003.
Commitment fees of .25% per annum on the difference between the revolving
commitment and the average daily amount of the loan are due quarterly.
Our obligations to the bank are secured by substantially all of our oil and
gas properties. Our bank borrowings have been incurred to finance our property
acquisition, 3-D seismic surveys, enhancement and drilling activities.
In addition to customary affirmative covenants, the loan agreement contains
various restrictive covenants and compliance requirements, including:
maintaining certain financial ratios;
limitations on incurring additional indebtedness;
prohibiting the payment of dividends on our common stock;
limitations of the disposition of assets; and
permitting liens (other than in favor of the lender) to exist on any of our
properties.
If we have borrowing capacity under our loan agreement, we intend to
borrow, repay and reborrow under the revolving credit facility from time to time
as necessary, subject to borrowing base limitations, to fund:
3-D seismic surveys;
lease option exercises;
drilling activities on our properties in the Yegua/Frio/Wilcox gas trend;
developmental drilling on our Permian Basin properties, when economically
feasible;
10
other drilling expenditures and acquisition opportunities; and
general corporate purposes.
Preferred Stock
At December 31, 2000, we had 974,500 shares of 6% convertible preferred
stock outstanding. The preferred stock:
requires us to pay dividends of $.60 per annum, semi-annually on June 15
and December 15 of each year.
can be converted into common stock at any time, at the option of the
holder, into 2.8751 shares of common stock at an initial conversion price
of $3.50 per share, subject to adjustment in certain events.
is redeemable at our option, in whole or in part, for $10 per share, plus
accrued dividends.
has no voting rights, except as required by applicable law, and, except
that as long as any shares of preferred stock remain outstanding, the
holders of a majority of the outstanding shares of the preferred stock may
vote on any proposal to change any provision of the preferred stock which
materially and adversely affects the rights, preferences or privileges of
the preferred stock.
is senior to the common stock with respect to dividends and on liquidation,
dissolution or winding up of Parallel.
has a liquidation value of $10 per share, plus accrued and unpaid
dividends.
Future Capital Requirements
Our capital expenditure budget for 2001 is highly dependent on future oil
and gas prices and the availability of other sources of funding. These
expenditures will be governed by the following factors:
internally generated cash flows;
availability of borrowing under our current credit facility;
additional sources of financing; and
future drilling successes.
In 2001, we intend to drill lower risk prospects that could have a
meaningful effect on our reserve base and cash flows. In selected cases, we may
elect to reduce our interests in higher risk, higher impact projects. We may
also sell certain non-core producing properties to raise funds for capital
expenditures.
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Outlook
The oil and gas industry is capital intensive. We make, and anticipate that
we will continue to make, substantial capital expenditures in the exploration
for, development and acquisition of oil and gas reserves. Historically, our
capital expenditures have been financed primarily with:
internally generated cash from operations;
funds provided from bank borrowings; and
proceeds from sales of equity securities.
The continued availability of these capital sources depends upon a number
of variables, including:
our proved reserves,
the volumes of oil and gas we produce from existing wells;
the prices at which we sell oil and gas; and
our ability to acquire, locate and produce new reserves.
Each of these variables materially affects our borrowing capacity. We may,
from time to time, seek additional financing in the form of:
increased bank borrowings;
sales of Parallel's securities;
sales of non-core properties; or
other forms of financing.
We do not currently have agreements for any future financing and there can
be no assurance as to the availability or terms of any such financing.
Trends and Prices
Changes in oil and gas prices significantly affect our revenues, cash flows
and borrowing capacity. 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 our control. We are unable to accurately
predict domestic or worldwide political events or the effects of other factors
on the prices we receive for our oil and gas. Historically, we have not entered
into transactions to hedge against changes in oil and gas prices, but we may
elect to enter into hedging transactions in the future to protect against
fluctuations in oil and gas prices.
During 2000, the average sales price we received for our oil production was
approximately $28.88 per Bbl, as compared with $17.32 in 1999, while the average
sales price for our gas was approximately $4.38 per Mcf in 2000, as compared
with $2.27 per Mcf in 1999. At March 15, 2001, we were receiving an average of
approximately $25.25 per Bbl for our oil production and approximately $5.00 per
Mcf for our gas production.
12
Inflation
Inflation has not had a significant impact on our financial condition or
results of operations. We do not believe that inflation poses a material risk to
our business.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities. (FAS No. 133), which establishes standards for
derivative instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. FAS No. 133 requires an entity
recognize all derivatives as either assets or liabilities in the statement of
financial position and measure those instruments at fair value. It establishes
conditions under which a derivative may be designated as a hedge and establishes
standards for reporting changes in the fair value of a derivative. We adopted
FAS No. 133, as amended by FAS No. 138, Accounting for Certain Derivative
Instruments and Certain Hedging Activities, an amendment of FASB Statement No.
133, effective January 1, 2001. After assessing our contracts, we are not aware
of any freestanding or embedded derivative instruments that would need to be
recorded as either assets or liabilities in the Financial Statements as of
January 1, 2001, in accordance with FAS No. 133.
S-1
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
PARALLEL PETROLEUM CORPORATION
April 5, 2001 By: /s/ Thomas R. Cambridge
---------------------------------
Thomas R. Cambridge, Chief
Executive Officer and
Chairman of the Board of Directors
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
/s/ Thomas R. Cambridge Chief Executive Officer April 5, 2001
----------------------- and Chairman of the
Thomas R. Cambridge Board of Directors
(Principal Executive
Officer)
/s/ Larry C. Oldham
----------------------- President and Treasurer April 5, 2001
Larry C. Oldham (Principal Financial and
Accounting Officer)
/s/ Dewayne E. Chitwood
----------------------- Director April 5, 2001
Dewayne E. Chitwood
s/ Ernest R. Duke
----------------------- Director April 5, 2001
Ernest R. Duke
/s/ Charles R. Pannill
----------------------- Director April 5, 2001
Charles R. Pannill