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, 1999
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, 1999 was: Common Stock, $0.10 par value, 4,425,934
shares.
<PAGE>
PrimeEnergy Corporation
Index to Form 10-QSB
June 30, 1999
Part I - Financial Information
Consolidated Balance Sheets - June 30, 1999 and
December 31, 1998 3-4
Consolidated Statements of Operations for the six months
ended June 30, 1999 and 1998 5
Consolidated Statements of Operations for the three months
ended June 30, 1999 and 1998 6
Consolidated Statement of Stockholders' Equity for the
six months ended June 30, 1999 7
Consolidated Statements of Cash Flows for the six months
ended June 30, 1999 and 1998 8
Notes to Consolidated Financial Statements 9-16
Management's Discussion and Analysis of Financial Condition
and Results of Operations 17-21
Part II - Other Matters 22
Signatures 23
<PAGE>
PrimeEnergy Corporation
Consolidated Balance Sheets
June 30, 1999 and December 31, 1998
June 30, December 31,
1998 1999
(Unaudited) (Audited)
ASSETS:
Current assets:
Cash and cash equivalents $ 1,060,000 $ 1,167,000
Restricted cash and cash
equivalents (Note 2) 1,228,000 1,080,000
Accounts receivable (Note 3) 3,929,000 2,890,000
Due from related parties (Note 8) 3,949,000 2,952,000
Other current assets 389,000 79,000
Prepaid expenses 116,000 351,000
Deferred income taxes 18,000 18,000
---------- ----------
Total current assets 10,689,000 8,537,000
---------- ----------
Property and equipment, at cost (Notes 1 and 4):
Oil and gas properties (successful
efforts method):
Developed 44,531,000 40,582,000
Undeveloped 633,000 1,284,000
Furniture, fixtures and equipment
including leasehold improvements 6,667,000 6,571,000
---------- ----------
51,831,000 48,437,000
Accumulated depreciation and depletion (31,873,000) (29,310,000)
---------- ----------
Net property and equipment 19,958,000 19,127,000
---------- ----------
Other assets 622,000 622,000
Due from affiliates 325,000 325,000
---------- ----------
Total assets $ 31,594,000 $28,611,000
========== ==========
See accompanying notes to the consolidated financial statements.
<PAGE>
PrimeEnergy Corporation
Consolidated Balance Sheets
June 30, 1999 and December 31, 1998
June 30, December 31,
1998 1999
(Unaudited) (Audited)
LIABILITIES and STOCKHOLDERS' EQUITY:
Current liabilities:
Accounts payable $ 6,833,000 $ 6,315,000
Accrued liabilities:
Payroll, benefits and related items 611,000 552,000
Interest and other 755,000 832,000
Due to related parties (Note 8) 1,802,000 731,000
---------- ----------
Total current liabilities 10,001,000 8,430,000
---------- ----------
Long-term bank debt (Note 5) 18,500,000 16,505,000
Deferred income taxes (Note 1) 18,000 57,000
Stockholders' equity:
Preferred stock, $.10 par, authorized
10,000,000 shares; none issued -- --
Common stock, $.10 par value, authorized
15,000,000 shares; issued 7,607,970
in 1999 and 1998 761,000 761,000
Paid in capital 10,902,000 10,902,000
Accumulated deficit (1,169,000) (721,000)
---------- ----------
10,494,000 10,942,000
Treasury stock, at cost, 3,176,036
common shares in 1999 and 3,158,376
common shares in 1998 (7,419,000) (7,323,000)
---------- ----------
Total stockholders' equity 3,075,000 3,619,000
---------- ----------
Total liabilities and equity $ 31,594,000 $28,611,000
========== ==========
See accompanying notes to the consolidated financial statements.
<PAGE>
PrimeEnergy Corporation
Consolidated Statements of Operations
Six Months Ended June 30, 1999 and 1998
(Unaudited)
1999 1998
Revenue:
Oil and gas sales $ 4,471,000 $ 5,993,000
District operating income 5,862,000 5,545,000
Administrative revenue (Note 8) 845,000 850,000
Reporting and management fees (Note 8) 156,000 146,000
Interest and other income 102,000 216,000
---------- ----------
Total revenue 11,436,000 12,750,000
---------- ----------
Costs and expenses:
Lease operating expense 2,727,000 3,226,000
District operating expense 4,237,000 4,305,000
Depreciation and depletion of
oil and gas properties 2,237,000 2,429,000
General and administrative expense 1,251,000 1,646,000
Exploration costs 821,000 95,000
Interest expense (Note 5) 656,000 713,000
---------- ----------
Total costs and expenses 11,929,000 12,414,000
---------- ----------
Income (loss) from operations (493,000) 336,000
Gain on sale and exchange of assets 14,000 35,000
---------- ----------
Net income (loss) before income taxes (479,000) 371,000
(Benefit) provision for income taxes (31,000) 37,000
---------- ----------
Net income (loss) $ (448,000) $ 334,000
========== ==========
Basic income (loss) per common
share (Notes 1 and 9) $(0.10) $0.07
==== ====
Diluted income (loss) per common
share (Notes 1 and 9) $(0.10) $0.06
==== ====
See accompanying notes to the consolidated financial statements.
<PAGE>
PrimeEnergy Corporation
Consolidated Statements of Operations
Three Months Ended June 30, 1999 and 1998
(Unaudited)
1999 1998
Revenue:
Oil and gas sales $ 2,542,000 $ 3,086,000
District operating income 3,004,000 2,865,000
Administrative revenue (Note 8) 446,000 417,000
Reporting and management fees (Note 8) 71,000 69,000
Interest and other income 57,000 136,000
---------- ----------
Total revenue 6,120,000 6,573,000
---------- ----------
Costs and expenses:
Lease operating expense 1,362,000 1,766,000
District operating expense 2,217,000 2,080,000
Depreciation and depletion of
oil and gas properties 1,432,000 1,306,000
General and administrative expense 629,000 819,000
Exploration costs 134,000 32,000
Interest expense (Note 5) 349,000 349,000
---------- ----------
Total costs and expenses 6,123,000 6,352,000
---------- ----------
Income (loss) from operations (3,000) 221,000
Gain on sale and exchange of assets 11,000 5,000
---------- ----------
Net income before income taxes 8,000 226,000
Provision for income taxes 7,000 19,000
---------- ----------
Net income $ 1,000 $ 207,000
========== ==========
Basic income per common
share (Notes 1 and 9) $0.00 $0.05
==== ====
Diluted income per common
share (Notes 1 and 9) $0.00 $0.04
==== ====
See accompanying notes to the consolidated financial statements.
<PAGE>
PrimeEnergy Corporation
Consolidated Statement of Stockholders' Equity
Six Months Ended June 30, 1999
<TABLE>
<CAPTION>
Additional
Commom Stock Paid In Retained Treasury
Shares Amount Capital Earnings Stock Total
<S> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1998 7,607,970 $761,000 $10,902,000 ($721,000) ($7,323,000) $3,619,000
Purchased 17,660 shares of
common stock (96,000) (96,000)
Net loss (448,000) (448,000)
--------- -------- ----------- ---------- ----------- ----------
Balance at June 30, 1999 7,607,970 $761,000 $10,902,000 ($1,169,000) ($7,419,000) $3,075,000
========= ======== =========== =========== =========== ==========
</TABLE>
See accompanying notes to the consolidated financial statements.
<PAGE>
PrimeEnergy Corporation
Consolidated Statements of Cash Flows
Six Months Ended June 30, 1999 and 1998
(Unaudited)
1999 1998
Net cash provided by operating
activities $ 2,637,000 $ 3,134,000
---------- ----------
Cash flows from investing activities:
Capital Expenditures,
including dry hole costs (4,690,000) (2,608,000)
Proceeds from sale of property
and equipment 37,000 295,000
Proceeds from payments on note receivable 10,000 --
---------- ----------
Net cash (used in) investing
activities (4,643,000) (2,313,000)
---------- ----------
Cash flows from financing activities:
Purchase of treasury stock (96,000) (1,218,000)
Increase in long-term bank debt and
other long-term obligations 12,255,000 16,415,000
Repayment of long-term bank debt and
other long-term obligations (10,260,000) (16,630,000)
Proceeds from exercised stock options -- 15,000
---------- ----------
Net cash provided by (used in)
financing activities 1,899,000 (1,418,000)
---------- ----------
Net decrease in cash and cash
equivalents (107,000) (597,000)
Cash and cash equivalents at the
beginning of the period 1,167,000 2,987,000
---------- ----------
Cash and cash equivalents at the
end of the period $ 1,060,000 $ 2,390,000
========== ==========
See accompanying notes to the consolidated financial statements.
<PAGE>
PrimeEnergy Corporation
Notes to Consolidated Financial Statements
June 30, 1999
(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 Company,
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 1,564
wells and owns non-operating interests in 494 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 and cash flow 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
<PAGE>
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.
<PAGE>
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".
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. Costs relating to the drilling of wells that
ultimately result in dry holes, and are therefore written off to
expense, are treated as investing activities.
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.
<PAGE>
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 1999, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 137 ("SFAS No.
137"), "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB Statement No.
133." SFAS No. 133 establishes accounting and reporting standards
requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded
in the balance sheet as either an asset or liability measured at
its fair value. It also requires that changes in the derivative's
fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for
qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income
statement, and requires that a company must formally document,
designate, and assess the effectiveness of transactions that
receive hedge accounting. In accordance with the issuance of SFAS
No.137, the Company will be required to adopt the provisions of
SFAS No. 133 no later than the beginning of fiscal year 2001. The
Company has not yet quantified the impacts of adopting SFAS No.
133 on its financial statements and has not determined the timing
of or method of adoption of SFAS No. 133. However, SFAS No. 133
could increase volatility in earnings and other comprehensive
income.
(2) Restricted Cash and Cash Equivalents:
Restricted cash and cash equivalents includes $1,228,000 and
$1,080,000 at June 30, 1999 and December 31, 1998, respectively,
of cash primarily pertaining to unclaimed royalty payments. There
were corresponding accounts payable recorded at June 30, 1999 and
December 31, 1998 for these liabilities.
(3) Accounts Receivable
Accounts receivable at June 30, 1999 and December 31, 1998
consisted of the following:
<PAGE>
June 30, December 31,
1999 1998
Joint Interest Billing $ 1,733,000 $ 1,395,000
Trade Receivables 466,000 264,000
Oil and Gas Sales 1,826,000 1,287,000
Other 31,000 71,000
--------- ---------
4,056,000 3,017,000
Less, Allowance for doubtful
accounts (127,000) (127,000)
--------- ---------
$ 3,929,000 $ 2,890,000
========= =========
(4) Property and equipment
Property and equipment at June 30, 1999 and December 31, 1998
consisted of the following:
June 30, December 31,
1999 1998
Developed oil and gas
properties at cost $44,531,000 $40,582,000
Undeveloped oil and gas
properties at cost 633,000 1,284,000
Less, accumulated depletion
and depreciation (27,313,000) (25,077,000)
------------ ------------
17,851,000 16,789,000
------------ ------------
Furniture, fixtures and
equipment 6,667,000 6,571,000
Less, accumulated depreciation (4,560,000) (4,233,000)
---------- ----------
2,107,000 2,338,000
---------- ----------
Total net property and
equipment $19,958,000 $19,127,000
========== ==========
(5) Long-Term Bank Debt
During 1998 and 1999, the Company was party to a line of credit
agreement with a bank with a non-reducing borrowing base of $20
million. In February 1999, the credit agreement was revised to
require that the $20 million borrowing base, reestablished on
October 14, 1998, would begin reducing monthly by $300,000
beginning February 1, 1999. As of June 30, 1999, the outstanding
borrowings of $18,500,000 agreed to the amount of the borrowing
base.
<PAGE>
The credit agreement provides for interest on outstanding
borrowings at the bank's base rate, as defined, payable monthly,
or at rates ranging from 1.5% to 2% over the London Inter-Bank
Offered Rate (LIBO rate) depending upon the Company's utilization
of the available line of credit, payable at the end of the
applicable interest period.
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 are
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 Company 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, 1999 and 1998, options on 802,500 shares were
<PAGE>
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, 1999 and 1998, options
on 111,000 and 112,000 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 Company 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 provided 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
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, 1999 and December 31, 1998
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
<PAGE>
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:
<TABLE>
<CAPTION>
Six Months Ended Six Months Ended
June 30, 1999 June 30, 1998
Net Number of Per Share Net Number of Per Share
Loss Shares Amount Income Shares Amount
<S> <C> <C> <C> <C> <C> <C>
Net income (loss) per
common share $(448,000) 4,443,368 $(0.10) $334,000 4,486,215 $0.07
Effect of dilutive
securities: Options* -- -- -- -- 780,092 (0.01)
_________ __________ ______ ________ _________ _____
Diluted net income
(loss) per common share $(448,000) 4,438,368 $(0.10) $334,000 5,266,307 $0.06
======== ========== ===== ======== ========= =====
</TABLE>
* For the six months ended June 30,1999, the number of options
excluded from diluted loss per common share calculations were
715,323 as the conversion of these would have an anti-dilutive
effect on net loss per share.
<TABLE>
<CAPTION>
Three Months Ended Three Months Ended
June 30, 1999 June 30, 1998
Net Number of Per Share Net Number of Per Share
Income Shares Amount Income Shares Amount
<S> <C> <C> <C> <C> <C> <C>
Net income per
common share $ 1,000 4,443,241 $ 0.00 $207,000 4,470,434 $0.05
Effect of dilutive
securities: Options** -- 702,877 0.00 -- 774,134 (0.01)
_________ __________ ______ ________ _________ _____
Diluted net income
per common share $ 1,000 5,136,118 $ 0.00 $207,000 5,244,568 $0.04
======== ========== ===== ======== ========= =====
</TABLE>
<PAGE>
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 Company 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, exploration
and development. By increasing its reserve base, the Company's
borrowing ability is increased due to additional properties available
as collateral. Capital expenditures during 1999 were financed by
borrowings and internally generated funds coupled with cash balances
available at the prior year-end.
During 1998 and 1999, the Company was party to a line of credit
agreement with a bank with a non-reducing borrowing base of $20
million. In February 1999, the credit agreement was revised to require
that the $20 million borrowing base, reestablished on October 14,
1998, would begin reducing monthly by $300,000 beginning February 1,
1999. The credit agreement provides for interest on outstanding
borrowings at the bank's base rate, as defined, payable monthly, or at
rates ranging from 1.5% to 2% over the London Inter-Bank Offered Rate
(LIBO rate) depending upon the Company's utilization of the available
line of credit, payable at the end of the applicable interest period.
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 are pledged as
security under this agreement. Under the Company's credit agreement,
the Company is required to maintain, as defined, minimum current,
tangible net worth, debt coverage and interest coverage ratios.
As of June 30, 1999, the Company had fully utilized its credit line of
$18,500,000.
The Company spent approximately $4,118,000 on the acquisition,
exploration and development of oil and gas properties in the first half
of 1999, including $413,000 spent to repurchase limited partner
interests from investors in the oil and gas partnerships.
The Company also spent approximately $196,000 on field service
equipment and $66,000 on computer hardware and software in the first
half of 1999.
The Company spent $96,000 in the first half of 1999 to acquire treasury
stock in open market transactions.
<PAGE>
During 1998, the Company organized a 1998 Drilling Program which
included participation by several joint venture partners. Six wells
have been drilled as part of this program. As of the date of this
report, two of the wells are producing, one well is currently awaiting
hookup, and three wells have been determined to be dry holes.
Substantially all of the costs associated with the three dry holes have
been written off to expense as of June 30, 1999.
The Company is currently participating in the development of the Ramrod
field in southeast Texas. The Company was carried for its share of
drilling costs on the Saint Andrew #1 well, but will be responsible for
a portion of the completion costs, as well as its share of the cost of
frac jobs to be performed. The Company also participated in the
drilling of the Saint George #2 well. It is not known at this time
whether these wells will produce in commercial quantities. The Company
has spent $1,210,000 on the development of this field in the first six
months of 1999 and expects to spend another $1,306,000 in the third
quarter of 1999.
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 availability of capital,
the number of oil and gas prospects, and oil and gas business
opportunities in general.
RESULTS OF OPERATIONS
The Company had a loss of $448,000 for the six months ended June 30,
1999 as compared to income of $334,000 in the first six months of 1998.
The Company had income of $1,000 in the second quarter of 1999 as
compared to income of $207,000 in the second quarter of 1998. The 1999
loss is primarily attributable to extremely low oil and gas prices in
the first half of 1999 and $821,000 in exploration costs incurred.
Oil and gas sales of $4,471,000 for the first half of 1999 represented
a 25% decrease over sales in the first half of 1998. In the first half
of 1999 average oil and gas prices were $13.07 per barrel and $2.02 per
Mcf as compared to $13.20 per barrel and $2.28 per Mcf in the first
half of 1998. Production for the first six months of 1999 totaled
118,113 barrels of oil and 1,448,452 Mcf of gas as compared to 140,392
barrels of oil and 1,813,424 Mcf of gas during the comparable period in
1998.
Second quarter oil and gas sales of $2,542,000 represented a 18%
decrease over sales in the second quarter of 1998. Second quarter 1999
average oil and gas prices were $15.20 per barrel and $2.14 per Mcf as
compared to $12.47 per barrel and $2.34 per Mcf in the second quarter
of 1998. Production for the second quarter of 1999 totaled 60,020
barrels of oil and 762,174 Mcf of gas as compared to 70,908 barrels of
oil and 939,349 Mcf of gas during the comparable period in 1998.
In November 1998, the Company sold one-half of its interest in the
Ramrod property, and turned over operations of the property to the
purchaser. In December, the most significant well on this property, the
<PAGE>
Saint George #1, had to be shut in for remedial work. The Saint George
#1 has since come back on line, but is producing at a lesser rate than
before the remedial work was performed. Total production from the
Ramrod property was 48,000 Mcf of gas and 300 barrels of oil in the
first half of 1999 as compared to 329,000 Mcf of gas and 4,700 barrels
of oil in 1998.
The Company's South Powderhorn property produced 149,000 Mcf of gas in
the first half of 1999 as compared to 348,000 Mcf in 1998, due to a
sharp natural decline curve on this property.
The Francis Martin #1 well, which was drilled as part of the Company's
1998 drilling program, had first production on January 28th 1999, and
contributed 264,000 Mcf to the Company's production in the first half
of 1999. The Company owns a 13.44% revenue interest in this well, which
is currently producing at a rate of over 14,000 Mcf per day. The
Company's participation in this well was subject to a provision wherein
its ownership interest is reduced at such time as it has received cash
flow equal to its capital costs expended on the well. Its interest is
further reduced when additional levels of cash flow are met.
The Company has entered into commodity swap contracts with the First
National Bank of Chicago. Pursuant to these contracts, the Company
will add approximately $11,000 of gas revenue received in the field in
the third quarter. The Company used similar swap contracts to sell its
oil production for the third quarter at $19.00 per barrel.
District operating income increased by $317,000 or 6%, between the
first half of 1999 and the first half of 1998, and by $139,000, or 5%
in the second quarter of 1999 as compared to the comparable period in
1988. Both increases were primarily due to an increase in work
performed for third parties.
Administrative revenue for the first half of 1999 declined by 1% as
compared to 1998. 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.
Lease operating expense for the first half of 1999 declined by 15% or
$499,000 compared to the first half of 1998. In terms of Mcf
equivalents, with one barrel of oil considered to be equal to six Mcf
of gas, per unit costs increased from $1.22 per Mcf equivalent to $1.26
per Mcf equivalent. This is largely because as production from certain
fields declines, the costs associated with operating those fields do
not decline proportionately.
<PAGE>
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 $800,000 in the first half of
1999 as compared to $675,000 for the same period in 1998.
District operating expense decreased 2%, or $68,000 in the first half
of 1999 as compared to the same period in 1998.
General and administrative expenses decreased by nearly 24% in both the
six months of 1999 and the second quarter of 1999, as compared to the
comparable periods in 1998.
The lower district operating and general and administrative expenses
are due to efforts by the Company to reduce costs in response to
extremely low oil and gas prices.
Depreciation and depletion of oil and gas properties decreased
$192,000, or 8%, in the first half of 1999 as compared to the half of
1998, but increased by $126,000 or 10% in the second quarter of 1999 as
compared to the second quarter of 1998. Per unit costs were higher for
both the six month and quarterly periods in 1999 as compared to the
same periods in 1998, but for the six month period this was more than
offset by the lower volumes produced.
Exploration costs were $821,000 during the first half of 1999 as
compared to $95,000 during the same period in 1998. The 1999 costs
consist primarily of the cost of two dry holes drilled as part of the
Company's 1998 Drilling Program.
Interest expense during the first half of 1999 decreased approximately
8% to $656,000 as average debt levels decreased.
The Year 2000 (Y2K) issue is the definition and resolution of
potential problems resulting from computer application programs or
imbedded chip instruction sets utilizing two-digits, as opposed to
four digits, to define a specific year. Such date sensitive
systems may be unable to properly interpret dates, which could
cause a system failure or other computer errors, leading to
disruptions in operations. The Company relies on the Company for
all management and administrative functions. Consequently, the
Company's exposure to the Y2K problems is determined by what Year
2000 efforts have been undertaken by the Company.
In 1997, the Company developed a three-phase program for the Y2K
information systems compliance. Phase I is to identify those
systems with which the Company has exposure to Y2K issues. Phase
II is to remediate systems and replace equipment where required.
Phase III is the final testing of each major area of exposure to
ensure compliance. The Company has identified four major areas
determined to be critical for successful Y2K compliance: (1)
financial and informational system applications,
(2) communications applications, (3) oil and gas producing
operations, and (4) third-party relationships.
The Company, in accordance with Phase I of the program, conducted
an internal review of all systems and contacted all software
suppliers to determine major areas of exposure to Y2K issues. The
<PAGE>
Company has completed the modifications to its core financial and
reporting systems and is continuing to test compliance in this
area. These modifications were made in conjunction with an upgrade
of the financial reporting applications provided by the Company's
software vendor. Conversion to the new system was completed during
1998. Due to the technology advances in the communications area
the Company has upgraded such equipment regularly over the past
three years. Y2K compliance was a specification requirement of
each installation. Consequently, the Company expects exposure in
this area to be limited to third party readiness. The Company is
in the process of identifying areas of exposure resulting from
equipment used in its oil and gas producing operations. The
Company intends to continue identification, remediation and
testing throughout 1999. In the third-party area, the Company has
received assurance from its significant service suppliers that
they intend to be Y2K compliant by 2000. The Company has
implemented a program to request Year 2000 certification or other
assurance from other third parties during 1999.
The Company recognizes that, notwithstanding the efforts described
above, the Company could experience disruptions to its operations
or administrative functions, including those resulting from non-
compliant systems utilized by unrelated third party governmental
and business entities. The Company is in the process of developing
a contingency plan in order to mitigate potential disruption to
business operations. The Company expects to complete and to
refine this plan throughout 1999.
The Company has handled identifying, remediating and testing
systems for Year 2000 compliance within the scope of routine
upgrades and systems evaluations. The Company expects to complete
the review of oil and gas operations exposure in the same manner,
without incurring substantial additional costs. However,
information resulting from the oil and gas operations review may
indicate required expenditures not currently contemplated by the
Company.
<PAGE>
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
3, 1999. One matter submitted to the stockholders was the
election of fourteen 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 4,439,124. 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 3,741,326 5,146
James E. Clark 3,741,166 5,306
Beverly A. Cummings 3,741,676 4,796
Charles E. Drimal, Jr. 3,741,676 4,796
Matthias Eckenstein 3,741,826 4,646
H. Gifford Fong 3,741,726 4,746
Thomas S. T. Gimbel 3,741,726 4,746
Clint Hurt 3,741,826 4,646
Robert de Rothschild 3,741,626 4,846
Jarvis J. Slade 3,741,226 5,246
Jan K. Smeets 3,741,826 4,646
Bennie H. Wallace, Jr. 3,741,726 4,746
Gaines Wehrle 3,741,576 4,896
Michael H. Wehrle 3,741,526 4,946
Additionally, the shareholders by a vote of 3,332,419 shares for
and 4,840 against, with 2,226 abstaining and 406,987 broker no
votes, voted to reduce the number of authorized preferred shares
from from 10,000,000 to 5,000,000, and the number of authorized
common shares from 15,000,000 to 10,000,000.
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 three
months ended March 31, 1999.
<PAGE>
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 16, 1999 /s/ Charles E. Drimal,Jr.
(Date) --------------------------
Charles E. Drimal, Jr.
President
Principal Executive
Officer
August 16, 1999 /s/ Beverly A. Cummings
(Date) --------------------------
Beverly A. Cummings
Executive Vice President
Principal Financial and
Accounting Officer
<TABLE> <S> <C>
<S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extract from the
PrimeEnergy Corporation second quarter 1999 Form 10QSB, and is qualified in its
entirety by reference to that document.
</LEGEND>
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<CASH> 2288
<SECURITIES> 0
<RECEIVABLES> 4056
<ALLOWANCES> 127
<INVENTORY> 0
<CURRENT-ASSETS> 10689
<PP&E> 51831
<DEPRECIATION> 31873
<TOTAL-ASSETS> 31594
<CURRENT-LIABILITIES> 10001
<BONDS> 18500
0
0
<COMMON> 761
<OTHER-SE> 2314<F1>
<TOTAL-LIABILITY-AND-EQUITY> 31594
<SALES> 4471
<TOTAL-REVENUES> 11436
<CGS> 0
<TOTAL-COSTS> 11273
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 656
<INCOME-PRETAX> (479)
<INCOME-TAX> (31)
<INCOME-CONTINUING> (448)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (448)
<EPS-BASIC> (0.10)
<EPS-DILUTED> (0.10)<FN>
<F1>Retained Earnings (1169)
<F1>Treasury Stock (7419)
<F1>Paid In Capital 10902
</FN>
</TABLE>
