U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________
FORM 10-QSB
/X/ Quarterly Report Under Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the Quarterly Period Ended June 30, 1998
or
/ / Transition Report Under Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the Transition Period From __________ to ___________
______________________
Commission File Number 0-7406
______________________
PrimeEnergy Corporation
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
84-0637348
(IRS employer identification number)
One Landmark Square, Stamford, Connecticut 06901
(Address of principal executive offices)
(203) 358-5700
(Registrant's telephone number, including area code)
(Former name, former address and former fiscal year, if changed since
last report)
Check whether the issuer (1) filed all reports required to be filed by
Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the
past 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 shares outstanding of each class of the Registrant's Common
Stock as of August 12, 1998 was: Common Stock, $0.10 par value,
4,459,194 shares.
PrimeEnergy Corporation
Index to Form 10-QSB
June 30, 1998
Part I - Financial Information
Consolidated Balance Sheets - June 30, 1998 and
December 31, 1997 3-4
Consolidated Statements of Operations for the six months
ended June 30, 1998 and 1997 5
Consolidated Statements of Operations for the three months
ended June 30, 1998 and 1997 6
Consolidated Statement of Stockholders' Equity for the
six months ended June 30, 1998 7
Consolidated Statements of Cash Flows for the six months
ended June 30, 1998 and 1997 8
Notes to Consolidated Financial Statements 9-17
Management's Discussion and Analysis of Financial Condition
and Results of Operations 18-22
Part II - Other Matters 23
Signatures 24
PrimeEnergy Corporation
Consolidated Balance Sheets
June 30, 1998 and December 31, 1997
June 30, December 31,
1998 1997
(Unaudited) (Audited)
Current assets:
Cash and cash equivalents $ 2,390,000 $ 2,987,000
Restricted cash and cash
equivalents (Note 2) 917,000 885,000
Accounts receivable (Note 3) 3,850,000 4,480,000
Due from related parties (Note 8) 1,529,000 2,454,000
Other current assets 100,000 175,000
Prepaid expenses 107,000 107,000
Deferred income taxes 121,000 121,000
---------- ----------
Total current assets 9,014,000 11,209,000
---------- ----------
Property and equipment, at cost (Notes 1 and 4):
Oil and gas properties (successful
efforts method):
Developed 42,577,000 41,427,000
Undeveloped 457,000 231,000
Furniture, fixtures and equipment
including leasehold improvements 6,106,000 5,757,000
---------- ----------
49,140,000 47,415,000
Accumulated depreciation and depletion (27,193,000) (24,885,000)
---------- ----------
Net property and equipment 21,947,000 22,530,000
---------- ----------
Other assets 628,000 604,000
Due from affiliates 325,000 325,000
---------- ----------
Total assets $ 31,914,000 $34,668,000
========== ==========
See accompanying notes to the consolidated financial statements.
PrimeEnergy Corporation
Consolidated Balance Sheets
June 30, 1998 and December 31, 1997
June 30, December 31,
1998 1997
(Unaudited) (Audited)
Current liabilities:
Accounts payable $ 4,886,000 $ 6,333,000
Accrued liabilities:
Payroll, benefits and related items 954,000 530,000
Taxes (Note 1) 7,000 27,000
Interest and other 741,000 646,000
Due to related parties (Note 8) 667,000 1,389,000
---------- ----------
Total current liabilities 7,255,000 8,925,000
---------- ----------
Long-term bank debt (Note 5) 18,650,000 18,865,000
Deferred income taxes (Note 1) 262,000 262,000
Stockholders' equity:
Preferred stock, $.10 par, authorized
10,000 shares; none issued -- --
Common stock, $.10 par value, authorized
15,000,000 shares; issued 7,607,970
in 1998 and 7,597,970 in 1997 761,000 760,000
Paid in capital 10,902,000 10,888,000
Retained earnings 1,305,000 971,000
---------- ----------
12,968,000 12,619,000
Treasury stock, at cost, 3,143,776
common shares in 1998 and 2,989,161
common shares in 1997 (7,221,000) (6,003,000)
---------- ----------
Total stockholders' equity 5,747,000 6,616,000
---------- ----------
Total liabilities and equity $ 31,914,000 $34,668,000
========== ==========
See accompanying notes to the consolidated financial statements.
PrimeEnergy Corporation
Consolidated Statements of Operations
Six Months Ended June 30, 1998 and 1997
(Unaudited)
1998 1997
Revenue:
Oil and gas sales $ 5,993,000 $ 7,680,000
District operating income 5,545,000 5,447,000
Administrative revenue (Note 8) 850,000 852,000
Reporting and management fees (Note 8) 146,000 160,000
Interest and other income 216,000 106,000
---------- ----------
Total revenue 12,750,000 14,245,000
---------- ----------
Costs and expenses:
Lease operating expense 3,258,000 3,380,000
District operating expense 4,305,000 4,101,000
Depreciation and depletion of
oil and gas properties 2,429,000 2,583,000
General and administrative expense 1,646,000 1,617,000
Exploration costs 95,000 1,351,000
Interest expense (Note 5) 713,000 566,000
---------- ----------
Total costs and expenses 12,446,000 13,598,000
---------- ----------
Income from operations 304,000 647,000
Gain on sale and exchange of assets 67,000 146,000
---------- ----------
Net income before income taxes 371,000 793,000
Provision for income taxes 37,000 79,000
---------- ----------
Net income $ 334,000 $ 714,000
========== ==========
Basic income per common share (Note 9) $0.07 $0.15
==== ====
Diluted income per common share (Note 9) $0.06 $0.13
==== ====
See accompanying notes to the consolidated financial statements.
PrimeEnergy Corporation
Consolidated Statements of Operations
Three Months Ended June 30, 1998 and 1997
(Unaudited)
1998 1997
Revenue:
Oil and gas sales $ 3,086,000 $ 3,421,000
District operating income 2,865,000 2,794,000
Administrative revenue (Note 8) 417,000 488,000
Reporting and management fees (Note 8) 69,000 79,000
Interest and other income 136,000 55,000
---------- ----------
Total revenue 6,573,000 6,837,000
---------- ----------
Costs and expenses:
Lease operating expense 1,768,000 1,730,000
District operating expense 2,080,000 1,986,000
Depreciation and depletion of
oil and gas properties 1,306,000 1,293,000
General and administrative expense 819,000 809,000
Exploration costs 32,000 708,000
Interest expense (Note 5) 349,000 291,000
---------- ----------
Total costs and expenses 6,354,000 6,817,000
---------- ----------
Income from operations 219,000 20,000
Gain on sale and exchange of assets 7,000 124,000
---------- ----------
Net income before income taxes 226,000 144,000
Provision for income taxes 19,000 14,000
---------- ----------
Net income $ 207,000 $ 130,000
========== ==========
Basic income per common share (Note 9) $0.05 $0.03
==== ====
Diluted income per common share (Note 9) $0.04 $0.02
==== ====
See accompanying notes to the consolidated financial statements.
PrimeEnergy Corporation
Consolidated Statement of Stockholders' Equity
Six Months Ended June 30, 1998
<TABLE>
<C>
Additional
Common Stock Paid In Retained Treasury
Shares Amount Capital Earnings Stock Total
<S>
Balance at December 31, 1997 7,597,970 $760,000 $10,888,000 $971,000 ($6,003,000) $6,616,000
Purchased 154,615 shares of
common stock (1,218,000) (1,218,000)
Stock options exercised 10,000 1,000 14,000 15,000
Net income 334,000 334,000
--------- -------- ----------- ---------- ------------ ----------
Balance at June 30, 1998 7,607,970 $761,000 $10,902,000 $1,305,000 ($7,221,000) $5,747,000
========= ======== =========== ========== =========== ==========
</TABLE>
See accompanying notes to the consolidated financial statements.
Consolidated Statements of Cash Flows
Six Months Ended June 30, 1998 and 1997
(Unaudited)
1998 1997
Net cash provided by operating activities $ 3,077,000 $ 4,373,000
---------- ----------
Cash flows from investing activities:
Additions to property and equipment (2,583,000) (2,794,000)
Proceeds from sale of property
and equipment 327,000 828,000
Proceeds from payments on note receivable -- 40,000
---------- ----------
Net cash (used in) investing
activities (2,256,000) (1,926,000)
---------- ----------
Cash flows from financing activities:
Purchase of treasury stock (1,218,000) (777,000)
Increase in long-term bank debt and
other long-term obligations 16,415,000 14,690,000
Repayment of long-term bank debt and
other long-term obligations (16,630,000) (17,300,000)
Proceeds from exercised stock options 15,000 --
---------- ----------
Net cash (used in) financing
activities (1,418,000) (3,387,000)
---------- ----------
Net decrease in cash and cash
equivalents (597,000) (940,000)
Cash and cash equivalents at the
beginning of the period 2,987,000 3,316,000
---------- ----------
Cash and cash equivalents at the
end of the period $ 2,390,000 $ 2,376,000
========== ==========
See accompanying notes to the consolidated financial statements.
PrimeEnergy Corporation
Notes to Consolidated Financial Statements
June 30, 1998
1) Description of Operations and Significant Accounting Policies:
Nature of Operations-
PrimeEnergy Corporation ("PEC"), a Delaware corporation, was
organized in March 1973. PrimeEnergy Management Corporation
("PEMC"), a wholly-owned subsidiary, acts as the managing general
partner, providing administration, accounting and tax preparation
services for 53 private and publicly-held limited partnerships and
trusts (the "Partnerships"). PEC owns Eastern Oil Well Service
Company ("EOWSC") and Southwest Oilfield Construction Company
("SOCC"), both of which perform oil and gas field servicing. PEC
also owns Prime Operating Company ("POC") which serves as operator
for most of the producing oil and gas properties owned by the
Company and affiliated entities. PrimeEnergy Corporation and its
wholly-owned subsidiaries are herein referred to as the "Company."
The Company is engaged in oil and gas exploration and drilling,
and the development, acquisition and production of oil and natural
gas properties. The Company owns leasehold, mineral and royalty
interests in producing and non-producing oil and gas properties
across the continental United States, primarily in Texas, Oklahoma
and West Virginia. The Company operates approximately 1,650 wells
and owns non-operating interests in approximately 900 additional
wells. Additionally, the Company provides well-servicing support
operations, site preparation and construction services for oil and
gas drilling and rework operations, both in connection with the
Company's activities and in providing contract services for third
parties. The Company is publicly traded on NASDAQ under the
symbol "PNRG".
The markets for the Company's products are highly competitive, as
oil and gas are commodity products and prices depend upon numerous
factors beyond the control of the Company, such as economic,
political and regulatory developments and competition from
alternative energy sources.
Certain items on the prior year income statements have been
reclassified to conform with current year classification.
Principles of Consolidation-
The consolidated financial statements include the accounts of
PrimeEnergy Corporation and its wholly-owned subsidiaries. All
material inter-company accounts and transactions between these
entities have been eliminated. Oil and gas properties include
ownership interests in affiliated partnerships. The statement of
operations includes the Company's proportionate share of revenue
and expenses related to oil and gas interests owned by the
partnerships.
Use of Estimates-
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Estimates of oil and gas reserves, as determined by independent
petroleum engineers, are continually subject to revision based on
price, production history and other factors. Depletion expense,
which is computed based on the units of production method, could
be significantly impacted by changes in such estimates.
Additionally, SFAS No. 121 requires that, if the expected future
cash flow from an asset is less than its carrying cost, that asset
must be written down to its fair market value. As the fair market
value of a property is generally substantially less than the total
future cash flow expected from the asset, small changes in the
estimated future net revenue from an asset could lead to the
necessity of recording a significant impairment.
The Company has significant deferred tax assets which have been
fully reserved against based upon the assumption that at current
and expected future levels of taxable income, and considering the
Section 29 credits the Company expects to generate, the
availability of these carryforwards will not lead to significant
reductions in the Company's tax liability as compared to what it
would pay if such carryforwards did not exist. Increases in
estimates of future taxable income could lead to significant
reductions in the amount of this reserve, which could have a
material effect on the net income of the Company.
Property and Equipment-
The Company follows the "successful efforts" method of accounting
for its oil and gas properties. Under the successful efforts
method, costs of acquiring undeveloped oil and gas leasehold
acreage, including lease bonuses, brokers' fees and other related
costs are capitalized. Provisions for impairment of undeveloped
oil and gas leases are based on periodic evaluations. Annual lease
rentals and exploration expenses, including geological and
geophysical expenses and exploratory dry hole costs, are charged
against income as incurred.
All other property and equipment are carried at cost.
Depreciation and depletion of oil and gas production equipment and
properties are determined under the unit-of-production method
based on estimated proved recoverable oil and gas reserves.
Depreciation of all other equipment is determined under the
straight-line method using various rates based on useful lives.
The cost of assets and related accumulated depreciation is removed
from the accounts when such assets are disposed of, and any
related gains or losses are reflected in current earnings.
Income Taxes-
The Company records income taxes in accordance with Statement of
Financial Accounting Standards ("SFAS") No. 109, "Accounting for
Income Taxes". SFAS No. 109 is an asset and liability approach to
accounting for income taxes, which requires the recognition of
deferred tax assets and liabilities for the expected future
consequences of events that have been recognized in the Company's
financial statements or tax returns.
Deferred tax liabilities or assets are established for temporary
differences between financial and tax reporting bases and are
subsequently adjusted to reflect changes in the rates expected to
be in effect when the temporary differences reverse. A valuation
allowance is established for any deferred tax asset for which
realization is not likely.
General and Administrative Expenses-
General and administrative expenses represent costs and expenses
associated with the operation of the Company. Certain
partnerships, trusts and joint ventures sponsored by the Company
reimburse general and administrative expenses incurred on their
behalf.
Income per share-
Income per share of common stock has been computed based on the
weighted average number of common shares and common stock
equivalents outstanding during the respective periods in
accordance with SFAS No. 128, "Earnings per Share," described
below in Recently Issued Accounting Standards.
Statements of cash flows-
For purposes of the consolidated statements of cash flows, the
Company considers short-term, highly liquid investments with
original maturities of less than ninety days to be cash
equivalents.
Concentration of Credit Risk-
The Company maintains significant banking relationships with
financial institutions in the State of Texas. The Company limits
its risk by periodically evaluating the relative credit standing
of these financial institutions. The Company's oil and gas
production purchasers consist primarily of independent marketers
and major gas pipeline companies.
Hedging-
From time to time, the Company may enter into futures contracts in
order to reduce its exposure related to changes in oil and gas
prices. In accordance with Statement of Financial Accounting
Standards No. 80, any gain or loss on such contracts is treated as
an adjustment to oil and gas revenue. Cash activity related to
hedging transactions is treated as operating activity on the
Statements of Cash Flows.
Recently Issued Accounting Standards-
In June 1997, the Financial Accounting Standards Board released
Statement No. 130, "Reporting Comprehensive Income" and Statement
No. 131, "Disclosures about Segments of an Enterprise and Related
Information." These statements require disclosure of certain
components of changes in equity and certain information about
operating segments and geographic areas of operation. Both of
these statements were adopted by the Company as of January, 1998.
These statements had no effect on the results of operations or
financial position.
In February 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards ("SFAS") No. 128,
"Earnings per Share" (EPS). SFAS No. 128 replaces the standards
for computing earnings per share previously established by APB No.
15, "Earnings per Share" by replacing the primary EPS with a
presentation of "basic EPS" and requiring dual presentation of
basic and diluted EPS on the face of the income statement. SFAS
No. 128 requires companies to adopt its provisions for fiscal
years ending after December 15, 1997 and requires restatement of
all prior period EPS data, if necessary. Earnings per share
information has been presented on the financial statements and its
computations disclosed in footnote 9 in accordance with SFAS No.
128.
(2) Restricted Cash and Cash Equivalents:
Restricted cash and cash equivalents includes $917,000 and
$885,000 at June 30, 1998 and December 31, 1997, respectively, of
cash primarily pertaining to unclaimed royalty payments. There
were corresponding accounts payable recorded at June 30, 1998 and
December 31, 1997 for these liabilities.
(3) Accounts Receivable
Accounts receivable at June 30, 1998 and December 31, 1997
consisted of the following:
June 30, December 31,
1998 1997
Joint Interest Billing $ 1,719,000 $ 1,601,000
Trade Receivables 241,000 213,000
Oil and Gas Sales 1,761,000 2,630,000
Other 155,000 62,000
--------- ---------
3,876,000 4,506,000
Less, Allowance for doubtful
accounts (26,000) (26,000)
--------- ---------
$ 3,850,000 $ 4,480,000
========= =========
(4) Property and equipment
Property and equipment at June 30, 1998 and December 31, 1997
consisted of the following:
June 30, December 31,
1998 1997
Developed oil and gas
properties at cost $42,577,000 $41,427,000
Undeveloped oil and gas
properties at cost 457,000 231,000
Less, accumulated depletion
and depreciation (23,358,000) (21,397,000)
------------ ------------
19,676,000 20,261,000
------------ ------------
Furniture, fixtures and
and equipment 6,106,000 5,757,000
Less, accumulated depreciation (3,835,000) (3,488,000)
---------- ----------
2,271,000 2,269,000
---------- ----------
Total net property and
equipment $21,947,000 $22,530,000
========== ==========
5) Long-Term Bank Debt
At December 31, 1996, the Company was party to a line of credit
agreement with a bank with a non-reducing borrowing base of $19
million. Twenty-five percent of the borrowing is syndicated to a
second bank. At the beginning of 1997, the agreement provided for
interest at 1/2% over the bank's base rate as defined, or 2 3/4% over
the London Inter-Bank Offered Rate (LIBOR) for the interest period
in question, payable at the end of the interest period.
On February 6, 1997, the bank extended the borrowing base to $21
million. The credit agreement was also amended to provide for
interest on outstanding borrowings at the bank's base rate, as
defined, or 2 1/4% over the LIBO rate. Effective in May, 1997, the
bank revised the borrowing base to $20.5 million due to the sale
of properties by the Company. In September, 1997, the borrowing
base was again revised to $20 million.
Effective January 2, 1998, the credit agreement was amended to
implement an interest rate schedule that is based upon the
aggregate principal amount of loans outstanding as a percentage of
the borrowing base. The amendment provides for interest on
outstanding borrowings at the bank's base rate, as defined, or
from 1 1/2% to 2% over the LIBOR rate depending upon the Company's
utilization of the available line of credit. During the first half
of 1998, the Company's level of borrowings has resulted in
interest charged at 2% over the LIBOR rate.
Advances pursuant to the agreement are limited to the borrowing
base as defined in the agreement. Most of the Company's oil and
gas properties as well as certain receivables and equipment were
pledged as security under this agreement. Under the Company's
credit agreement, the Company is required to maintain, as defined,
a minimum current ratio, tangible net worth, debt coverage ratio
and interest coverage ratio.
(6) Contingent Liabilities:
PEMC, as managing general partner of the affiliated partnerships
and trusts (the "Partnerships"), is responsible for all
Partnership activities, including the review and analysis of oil
and gas properties for acquisition, the drilling of development
wells and the production and sale of oil and gas from productive
wells. PEMC also provides the administration, accounting and tax
preparation work for the Partnerships. PEMC is liable for all
debts and liabilities of the affiliated Partnerships, to the
extent that the assets of a given limited Partnership are not
sufficient to satisfy its obligations.
As a general partner, PEMC is committed to offer to purchase the
limited partners' interests in certain of its managed Partnerships
at various annual intervals. Under the terms of a partnership
agreement, PEMC is not obligated to purchase an amount greater
than 10% of the total partnership interest outstanding. In
addition, PEMC will be obligated to purchase interests tendered by
the limited partners only to the extent of one-hundred fifty (150)
percent of the revenues received by it from such partnership in
the previous year. Purchase prices are based upon annual reserve
reports of independent petroleum engineering firms discounted by a
risk factor. Based upon historical production rates and prices,
management estimates that if all such offers were to be accepted,
the maximum annual future purchase commitment would be
approximately $500,000. In recent years, the Company has chosen
to repurchase limited partnership interests in excess of its
commitment.
(7) Stock Options and Other Compensation:
In May 1989, non-statutory stock options were granted by the
Company to four key executive officers for the purchase of shares
of common stock. Such options are exercisable, on a cumulative
basis, as to twenty percent of the shares subject to option in
each year, beginning one year after the granting of the option.
At June 30, 1998 and 1997, options on 802,500 shares were
outstanding and exercisable at prices ranging from $1.00 to $1.25.
On January 27, 1983, the Company adopted the 1983 Incentive Stock
Option Plan. At June 30, 1998 and 1997, options on 112,000 and
124,000 shares were exercisable at $1.50 per share, respectively,
and no additional shares were available for granting.
PEMC has a marketing agreement with its current President to
provide assistance and advice to PEMC in connection with the
organization and marketing of oil and gas partnerships and joint
ventures and other investment vehicles of which PEMC is to serve
as general or managing partner. The Company had a similar
agreement with its former Chairman. Although that agreement has
expired, the former Chairman is still entitled to receive certain
payments relating to partnerships formed during the time the
agreement was in effect. The President is entitled to a
percentage of the Company's carried interest depending on total
capital raised and annual performance of the Partnerships and
joint ventures.
(8) Related Party Transactions:
PEMC is a general partner in several oil and gas Partnerships in
which certain directors have limited and general partnership
interests. A substantial portion of the assets and revenues of
PEMC are derived from its interests in the oil and gas properties
owned by the Partnerships. As the managing general partner in each
of the Partnerships, PEMC receives approximately 5% to 12% of the
net revenues of each Partnership as a carried interest in the
Partnerships' properties.
The Partnership agreements allow PEMC to receive management fees
for various services to the Partnerships as well as reimbursement
for property acquisition and development costs incurred on behalf
of the Partnerships and general and administrative overhead, which
is reported in the statements of operations as administrative
revenue.
In 1991, the Company loaned approximately $325,000 at 12% interest
to a real estate limited partnership of which a Company Officer
and Director is a general partner. This loan is secured by a
mortgage on the underlying real estate in the partnership and the
Company received a 23% equity participation in the partnership.
The loan agreement provides for interest payments on a quarterly
basis provided the cash flow from operations of the limited
partnership are sufficient to pay interest for the quarter. If
cash flows are not sufficient, the accrued interest is added to
the principal. This loan is included in other non-current assets
on the balance sheet.
Due to related parties at June 30, 1998 and December 31, 1997
primarily represent receipts collected by the Company, as agent,
from oil and gas sales net of expenses. Receivables from
affiliates consist of reimbursable general and administrative
costs, lease operating expenses and reimbursements for property
acquisitions, development and related costs.
(9) Income per share:
Basic earnings per share are computed by dividing earnings
available to common stockholders by the weighted average number
of common shares outstanding during the period. Diluted earnings
per share reflect per share amounts that would have resulted if
dilutive potential common stock had been converted to common
stock. The following reconciles amounts reported in the
financial statements:
Six Months Ended Six Months Ended
June 30, 1998 June 30, 1997
Net Number of Per Share Net Number of Per Share
Income Shares Amount Income Shares Amount
Net income per
common share $334,000 4,486,215 $0.07 $714,000 4,689,230 $0.15
Effect of dilutive
securities:
Options -- 780,092 (0.01) -- 740,985 (0.02)
-------- --------- ------ -------- ---------- -------
Diluted net income
per common share $334,000 5,266,307 $0.06 $714,000 5,430,215 $0.13
======== ========== ====== ======== ========= ======
Three Months Ended Three Months Ended
June 30, 1998 June 30, 1997
Net Number of Per Share Net Number of Per Share
Income Shares Amount Income Shares Amount
Net income per
common share $207,000 4,470,434 $0.05 $130,000 4,676,806 $0.03
Effect of dilutive
securities:
Options -- 774,134 (0.01) -- 765,736 (0.01)
________ _________ _______ ________ _________ _____
Diluted net income
per common share $207,000 5,244,568 $0.04 $130,000 5,442,542 $0.02
======== ========= ======= ======== ========= ======
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
This discussion should be read in conjunction with the financial
statements of the Company and notes thereto. The Company's
subsidiaries are defined in Note 1 of the financial statements. PEMC
is the managing general partner or managing trustee in several Limited
Partnerships and Trusts (collectively, the "Partnerships").
LIQUIDITY AND CAPITAL RESOURCES
The Company feels that it has the ability to generate sufficient
amounts of cash to meet long-term liquidity needs, as well as debt
service. The Company's goal is to generate increased cash flows by
increasing its reserve base through continued acquisition and
development. By increasing its reserve base, the Company's borrowing
ability is increased due to additional properties available as
collateral. Capital expenditures during 1998 were financed by
borrowings and internally generated funds coupled with cash balances
available at the prior year-end.
On April 26, 1995, the Company entered into a revised credit agreement
with Bank One, Texas, NA providing for $12.5 million revolving line of
credit on a $50 million master promissory note. This new agreement
introduced Den Norske Bank, AS as a 25% syndication partner in the
line. The agreement also provides for a lower floating rate compared
to previous agreements as well as the ability to borrow based upon the
London Inter-Bank Offered Rate (LIBOR). The borrowing base is revised
every six months by the bank.
As of June 30, 1998, the borrowing base under the agreement was
$20,000,000 and the Company had $1,350,000 available under this line of
credit. During most of 1997, the interest rate on this line of credit
was the banks base rate, as defined, monthly, or 2 1/4 % over the
published LIBOR rate, payable at the end of the applicable interest
period. Effective February 2, 1998, this agreement was amended so that
the interest rate on the LIBOR Rate Loan will vary from 1 1/2% to 2%
above the published LIBOR rate depending on the portion of the
Company's credit line being utilized. Based on current and expected
levels of borrowing, it is anticipated that the rate charged to the
Company on these loans will be at 2% above the published LIBOR rate for
most or all of 1998.
Most of the Company's oil and gas properties as well as certain
receivables and equipment are pledged as security under the agreement.
The Company is required to maintain, as defined, a minimum tangible net
worth, and certain debt, interest coverage and current ratios, and
restrictions are placed on the Company's ability to pay dividends and
purchase treasury stock.
The Company spent approximately $2,165,000 on the acquisition,
exploration and development of oil and gas properties in the first half
of 1998, including $218,000 spent to repurchase limited partners
interests from investors in the oil and gas partnerships.
The Company also spent approximately $400,000 on field service
equipment and $113,000 on computer hardware and software in the first
half of 1998.
In January, 1998, the Company purchased 53,334 shares of its stock for
treasury from Stanford University and 53,334 shares from the University
of California. The total combined cost of these two purchases was
$853,000. The Company spent an additional $365,000 in the first
quarter of 1998 to acquire treasury stock in open market transactions.
During the first quarter of 1998, the Company sold its interests in a
group of wells located in Southeast New Mexico for $157,000, and its
interest in the Guerra Field located in Webb County Texas, for
$105,000.
Most of the Company's capital spending is discretionary and the
ultimate level of spending will be dependent on the Company's
assessment of the oil and gas business, the number of oil and gas
prospects, and oil and gas business opportunities in general.
RESULTS OF OPERATIONS
Net income decreased to $334,000 for the six months ended June 30, 1998
as compared to $714,000 for the first six months of 1997, and increased
to $207,000 for the quarter ended June 30, 1998 as compared to $130,000
for the comparable period in 1997. Sharply lower oil and gas prices in
1998 as compared to 1997 had a strong negative impact on both second
quarter 1998 and year to date earnings. This impact was partially
offset in both cases by much lower exploration costs, and in the second
quarter by significant revenue received from the Company's Saint George
# 1 well, which came on line in the middle of March 1998.
The Company has undertaken a 1998 Development Drilling Program, in
which the Company, with participation from several joint venture
partners, intends to drill five exploratory wells in the second half of
1998. The Company's share of the cost of this drilling is expected to
be approximately $2.5 million. To the extent this drilling results in
dry holes, the drilling costs will be expensed as exploration costs,
which would significantly impact earnings.
Oil and gas sales of $5,993,000 for the first half of 1998 represented
a 22% decrease over sales in the first half of 1997. Second quarter
1998 sales of $3,086,000 represent a 10% decrease over 1997 second
quarter sales. For the first six months of 1998 as compared to the
first six months of 1997, the average oil price received dropped from
$20.52 per barrel to $13.20, and average gas prices decreased from
$2.53 per MCF to $2.28. For the second quarter of 1998 as compared to
the second quarter of 1997, the average oil price received dropped from
$19.41 per barrel to $12.47, and average gas prices decreased from
$2.52 per MCF to $2.34.
The company's production totaled 71,000 barrels of oil and 939,000
MCF's of gas in the second quarter of 1998, as compared to 66,000
barrels of oil and 1,013,000 MCF's of gas during the comparable period
in 1997. The increase in oil production is attributable to workovers,
improvements and development drilling on several of the Company's
existing properties. The decline in gas production is due to the normal
production declines coupled with a reduced working interest in the
Company's South Powderhorn field, partially offset by production from
the Saint George # 1 well, which was completed this year.
The purchase of the Company's South Powderhorn property, located in
Calhoun County, Texas was subject to a provision wherein the seller
obtains a 25% working interest in the property at such time as the
Company and its joint venture partners have received net cash flow from
the property equal to 200% of their costs (Payout). This Payout
occurred in January of 1998, and production attributable to the
Company's interest which reverted to the seller was approximately
116,000 MCF's in the first six months of 1998.
First sales from the St. George #1 well occurred on March 12, 1998. The
Company's share of production from this well was approximately 268,000
MCF's through June 30, 1998.
District operating income increased by $98,000, or 2%, between the
first half of 1998 and the first half of 1997, primarily due to an
increase in third party work performed.
Administrative revenue for the first half of 1998 was consistent with
the first half of 1997. Amounts received in both years from certain
Partnerships are substantially less than the amounts allocable to those
Partnerships under the Partnership agreements. The lower amounts
reflect PEMC's efforts to limit costs incurred and the amounts
allocated to the Partnerships.
Other income for the second quarter of 1998 includes a $65,000 contract
settlement with a gas purchaser relating to production cost deductions
and tax reimbursements prior to 1989.
Lease operating expense for the first half of 1998 declined by 4% or
$122,000 compared to the first half of 1997. Second quarter 1998 lease
operating expense of $1,768,000 represented an increase of $38,000, or
2%, over the second quarter 1997 amount.
The Company receives reimbursement for costs incurred related to the
evaluation, acquisition and development of properties in which
interests are owned by its joint venture partners, related
partnerships, and trusts. To the extent that these costs are expended
at the district level, the reimbursements reduce total district
operating expenses. To the extent such expenses are incurred by PEMC,
such reimbursements reduce total general and administrative expenses.
Such reimbursement totaled approximately $675,000 in the first half of
1998 as compared to $750,000 for the same period in 1997.
District operating expense as a percentage of district operating income
remained fairly constant in the first half of 1998 as compared to the
same period in 1997.
General and administrative expenses remained fairly constant in 1998 as
compared to 1997.
Depreciation and depletion of oil and gas properties decreased
$154,000, or 6% in the first half of 1998 as compared to the first half
of 1997, primarily due to lower production, but increased $13,000 or 1%
in the second quarter of 1998 as compared to the second quarter of 1997
due to depletion expense relating to a full quarter's depletion on the
Saint George # 1 well.
Exploration costs were $95,000 in the first half of 1998 as compared to
$1,351,000 during the same period in 1997. The 1997 costs consisted
primarily of a 3D seismic shoot and related costs. The Company has
plans to drill several exploratory wells during the remainder of 1998,
which would be charged to exploration expense if they were dry holes,
and is also considering participating in 3D seismic shoots in an
attempt to identify additional locations for exploratory drilling. It
is therefore possible that exploration costs during the remainder of
1998 will be significantly in excess of the first half of 1998.
Gain on sale of assets of $67,000 in the first six months of 1998
consists of net gains of $28,000 on the sale of producing properties
and $39,000 in receipts from the sale of equipment on fully depleted
wells in excess of the plugging costs of those wells.
Interest expense during the first half of 1998 increased approximately
26% to $713,000 as average debt levels increased, primarily due to the
amounts borrowed to fund drilling and exploration activities in the
latter part of 1997 and the beginning of 1998.
Many existing computer applications use two digits rather than four to
define the applicable year, raising the possibility that software may
erroneously assume that a date using "00" as the year refers to the
year 1900 rather than the year 2000.
The Company's existing software will properly handle all dates
including dates beyond December 31, 1999 and the Company does not
expect any significant operational difficulties or unusual costs to
result from the year 2000 issue. While it is not possible at this time
to determine what effect the year 2000 issue might have on the
Company's customers, suppliers, or joint venture partners, the Company
does not believe the potential problems associated with the year 2000
issue will have a material effect on it financial position.
This Report contains forward-looking statements that are based on
management's current expectations, estimates and projections. Words
such as "expects," "anticipates," "intends," "plans," "believes,"
"projects" and "estimates," and variations of such words and similar
expressions are intended to identify such forward-looking statements.
These statements constitute "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933, and are subject
to the safe harbors created thereby. These statements are not
guarantees of future performance and involve risks and uncertainties
and are based on a number of assumptions that could ultimately prove
inaccurate and, therefore, there can be no assurance that they will
prove to be accurate. Actual results and outcomes may vary materially
from what is expressed or forecast in such statements due to various
risks and uncertainties. These risks and uncertainties include, among
other things, the possibility of drilling cost overruns and technical
difficulties, volatility of oil and gas prices, competition, risks
inherent in the Company's oil and gas operations, the inexact nature of
interpretation of seismic and other geological and geophysical data,
imprecision of reserve estimates, and the Company's ability to replace
and expand oil and gas reserves. Accordingly, stockholders and
potential investors are cautioned that certain events or circumstances
could cause actual results to differ materially from those projected.
PART II - OTHER MATTERS
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Annual Meeting of Stockholders of the Company was held on June
4, 1998. The only matter submitted to the stockholders was the
election of fifteen Directors (named below), nominated by
management, all of whom were currently serving as Directors.
Proxies were solicited pursuant to Regulation 14A under the
Securities Act of 1934, definitive copies of which were filed with
the Commission. There was no solicitation in opposition to
management's nominees, and all of the Directors nominated for the
re-election were elected. The number of shares of the Company's
common stock outstanding and entitled to vote at the Annual
Meeting was 4,476,500. Those persons nominated and elected as
Directors and the number of shares voting for or withheld for
each, is shown below. There were no abstentions or broker non-
votes.
For Withheld
Samuel R. Campbell 3,928,375 2,539
James E. Clark 3,928,365 2,549
Beverly A. Cummings 3,928,075 2,839
Charles E. Drimal, Jr. 3,928,062 2,852
Charles E. Drimal, Sr. 3,928,375 2,539
Matthias Eckenstein 3,928,375 2,539
H. Gifford Fong 3,928,262 2,652
Thomas S. T. Gimbel 3,928,375 2,539
Clint Hurt 3,928,375 2,539
Robert de Rothschild 3,928,375 2,539
Jarvis J. Slade 3,928,375 2,539
Jan K. Smeets 3,928,375 2,539
Bennie H. Wallace, Jr. 3,928,375 2,539
Gaines Wehrle 3,928,252 2,662
Michael H. Wehrle 3,928,375 2,539
Item 5. OTHER INFORMATION
Exhibit 27 - Financial Data Schedule is attached to the electronic
filing of this report only.
Item 6. EXHIBITS AND REPORTS ON FORM 8K
No reports on form 8K were filed by the Company during the six
months ended June 30, 1998.
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of
1934, Registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
PrimeEnergy Corporation
(Registrant)
August 14, 1998 /s/ Charles E. Drimal,Jr.
(Date) --------------------------
Charles E. Drimal, Jr.
President
Principal Executive
Officer
August 14, 1998 /s/ Beverly A. Cummings
(Date) --------------------------
Beverly A. Cummings
Executive Vice President
Principal Financial and
Accounting Officer
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