<PAGE>
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-QSB
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
- ------
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1999
OR
- ------ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission file number 0-22695
SHERIDAN ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware 76-0507664
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1000 Louisiana, Suite 800
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713) 651-7899
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for 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
----- -----
As of August 16, 1999, there were 6,731,276 outstanding shares of Sheridan
Energy, Inc. Common Stock, $.01 par value.
<PAGE>
SHERIDAN ENERGY, INC.
Report on Form 10-QSB For The Quarter Ended June 30, 1999
Index
<TABLE>
<CAPTION>
Page
<S> <C>
Part I. Financial Information ................................................ 2
Item 1. Financial Statements (Unaudited) ............................ 2
Consolidated Balance Sheets -
June 30, 1999 and December 31, 1998 ......................... 3
Consolidated Statements of Operations -
Three and Six Month Periods Ended June 30, 1999 and 1998 ..... 4
Consolidated Statements of Cash Flows -
Six Month Periods Ended June 30, 1999 and 1998 ............... 5
Notes to Consolidated Financial Statements ................... 6
Item 2. Management's Discussion and Analysis or
Plan of Operation .......................................... 11
Part II. Other Information .................................................... 20
</TABLE>
Forward-Looking Statements
Stockholders are cautioned that all forward-looking statements involve
risks and uncertainties, including without limitation, statements about the
costs of exploring and developing new oil and natural gas reserves, the price
for which such reserves can be sold, the Company's attempts to reduce overhead
and eliminate non-core assets, environmental concerns affecting the drilling of
oil and natural gas wells, the effect of the Merger, pending litigation, the
attempts to acquire producing and non-producing oil and gas properties, the
ability of the Company to make projected capital expenditures and secure
required capital and to achieve projected quarterly results and compliance with
Year 2000 issues, and general market conditions, competition and pricing.
Although the Company believes that the assumptions underlying the forward-
looking statements contained herein are reasonable, any of the assumptions could
be inaccurate, and there can therefore be no assurance that the forward-looking
statements included in this Form 10-QSB will prove accurate. Because of the
significant uncertainties inherent in the forward-looking statements contained
in this Form 10-QSB, the inclusion of such information should not be regarded as
a representation by the Company or any other person that the objectives and
plans of the Company will be achieved.
<PAGE>
SHERIDAN ENERGY, INC.
Report on Form 10-QSB For the Quarter Ended June 30, 1999
Part 1. Financial Information
Item 1. Financial Statements (Unaudited)
The accompanying unaudited consolidated financial statements of Sheridan
Energy, Inc. and its subsidiary, Sheridan California Energy, Inc. (SCEI),
(collectively the "Company") have been prepared in accordance with Rule 310 of
Regulation S-B, "Interim Financial Statements," and accordingly do not include
all information and notes required under generally accepted accounting
principles for complete financial statements. The financial statements have been
prepared in conformity with the accounting principles and practices as disclosed
in the Company's Annual Report on Form 10-KSB for the year ended December 31,
1998. These interim financial statements reflect all adjustments (which were
limited to normal recurring adjustments) which are, in the opinion of
management, necessary for a fair presentation, in all material respects, of the
Company's financial position as of June 30, 1999. Results of operations for the
three and six-month periods ended June 30, 1999 are not necessarily indicative
of the results that may be expected for the year ending December 31, 1999. It is
recommended that these unaudited consolidated financial statements be read in
conjunction with the consolidated financial statements and notes thereto
included in the Company's Annual Report on Form 10-KSB for the year ended
December 31, 1998.
2
<PAGE>
SHERIDAN ENERGY, INC. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
June 30, December 31,
1999 1998
------------------ -------------------
(unaudited)
ASSETS (in thousands, except for share data)
-------
<S> <C> <C>
Current Assets:
Cash and cash equivalents..................................................... $ 714 $ 639
Accounts receivable, net of allowance for doubtful accounts for 1999
and 1998 of $120............................................................ 5,414 4,097
Acquisition deposit........................................................... -- 5,800
Other current assets.......................................................... 664 563
------------- -------------
Total current assets........................................................ 6,792 11,099
------------- -------------
Property and equipment:
Oil and natural gas properties................................................ 130,856 75,331
Other property and equipment.................................................. 1,410 1,025
Accumulated depletion, depreciation and amortization.......................... (25,664) (20,398)
------------- -------------
Property and equipment, net................................................. 106,602 55,958
------------- -------------
Investment in natural gas treating plant....................................... 283 336
Deferred tax asset............................................................. 930 930
Other assets, net.............................................................. 824 554
------------- -------------
Total other assets.......................................................... 2,037 1,820
------------- -------------
TOTAL ASSETS................................................................... $ 115,431 $ 68,877
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable and accrued liabilities...................................... $ 7,813 $ 10,318
Current portion of long-term debt............................................. 3,650 5,550
------------- -------------
Total current liabilities................................................... 11,463 15,868
------------- -------------
Long-term liabilities:
Long-term debt................................................................ 67,850 31,950
Other long-term liabilities................................................... 1,520 --
------------- -------------
Total long-term liabilities................................................. 69,370 31,950
------------- -------------
Total liabilities........................................................... 80,833 47,818
------------- -------------
Commitments and contingencies (Note 3)......................................... -- --
Redeemable Preferred Stock:
Series A Preferred Stock, shares outstanding 1,139,556 and 1,067,500,
respectively; redemption value $11,396 and $10,675, respectively............ 11,396 10,675
Series N-A Preferred Stock, 1,378,900 shares
outstanding, redemption value $13,789....................................... 13,789 --
------------- -------------
Total redeemable preferred stock............................................ 25,185 10,675
------------- -------------
Minority interest.............................................................. 1,789 --
Stockholders' equity:
Common Stock, 6,731,276 shares outstanding.................................... 67 67
Additional paid-in capital.................................................... 29,005 29,005
Accumulated deficit........................................................... (21,448) (18,688)
------------- -------------
Total stockholders' equity.................................................. 7,624 10,384
------------- -------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY..................................... $ 115,431 $ 68,877
============= =============
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
3
<PAGE>
SHERIDAN ENERGY, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
<TABLE>
<CAPTION>
Three Months Ended June 30, Six Months Ended June 30,
------------------------------- ---------------------------
1999 1998 1999 1998
--------------- ------------ ------------ ------------
(in thousands, except for per share data)
<S> <C> <C> <C> <C>
REVENUES:
Oil and natural gas sales................................. $ 7,028 $ 4,612 $ 13,261 $ 9,064
Natural gas gathering..................................... 68 63 119 119
Net gain (loss) on property sales......................... (138) 8 (138) 186
--------- ---------- ---------- ----------
6,958 4,683 13,242 9,369
--------- ---------- ---------- ----------
COST AND EXPENSES:
Operating expenses........................................ 1,653 1,489 3,224 2,976
Treating and transportation expenses...................... 202 221 401 413
Depletion, depreciation and amortization.................. 2,793 2,427 5,266 4,931
General and administrative expenses....................... 1,201 1,003 2,276 2,147
Exploration costs......................................... 750 1 1,048 30
--------- ---------- ---------- ----------
6,599 5,141 12,215 10,497
--------- ---------- ---------- ----------
OPERATING INCOME (LOSS)................................... 359 (458) 1,027 (1,128)
Other income (expenses):
Equity earnings in natural gas treating plant............. 172 157 324 313
Interest expense.......................................... (1,500) (807) (2,697) (1,481)
--------- ---------- ---------- ----------
(1,328) (650) (2,373) (1,168)
--------- ---------- ---------- ----------
LOSS BEFORE INCOME TAXES.................................. (969) (1,108) (1,346) (2,296)
Income tax expense (benefit).............................. -- -- -- --
--------- ---------- ---------- ----------
NET LOSS.................................................. (969) (1,108) (1,346) (2,296)
Preferred stock dividends................................. (830) (274) (1,525) (633)
Minority interest......................................... (92) -- (111) --
--------- ---------- ---------- ----------
NET LOSS APPLICABLE TO COMMON STOCK....................... $ (1,891) $ (1,382) $ (2,982) $ (2,929)
========= ========== ========== ==========
LOSS PER SHARE:
Basic and diluted......................................... $ (0.28) $ (0.21) $ (0.44) $ (0.44)
========= ========== ========== ==========
WEIGHTED AVERAGE SHARES:
Basic and diluted......................................... 6,731 6,731 6,731 6,731
========= ========== ========== ==========
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
4
<PAGE>
SHERIDAN ENERGY, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOW
(UNAUDITED)
<TABLE>
<CAPTION>
Six Months Ended June 30,
--------------------------
1999 1998
------------ -----------
(in thousands)
<S> <C> <C>
Cash flow from operating activities:
Net loss......................................................................... $ (1,346) $ (2,296)
Adjustments to reconcile net loss to cash provided by operating activities:
Depletion, depreciation and amortization........................................ 5,266 4,931
Cash paid to settle litigation matters.......................................... (488) --
Amortization of debt transaction costs.......................................... 156 114
Net gain (loss) on property sales............................................... 138 (186)
Distribution in excess of equity earnings....................................... 53 113
Changes in current operating assets and liabilities:
Increase in accounts receivable................................................ (1,317) (1,677)
Decrease in acquisition deposit................................................ 5,800 --
Increase in other current assets............................................... (101) (347)
Increase (decrease) in accounts payable and accrued liabilities................ (1,997) 3,233
------------ -----------
Net cash provided by operating activities....................................... 6,164 3,885
------------ -----------
Cash flow from investing activities:
Capital expenditures............................................................. (57,120) (8,713)
Proceeds from property sales..................................................... 2,592 186
------------ -----------
Net cash used in investing activities............................................ (54,528) (8,527)
------------ -----------
Cash flow from financing activities:
Payments on revolving credit facility............................................ (16,050) (8,000)
Borrowings under revolving credit facility....................................... 50,050 12,375
Proceeds from issuance of subsidiary Series N-A preferred stock.................. 13,000 --
Proceeds from issuance of subsidiary common shares............................... 1,900 --
Debt transaction costs and other................................................. (461) (7)
------------ -----------
Net cash provided by financing activities........................................ 48,439 4,368
------------ -----------
Net increase (decrease) in cash and cash equivalents.............................. 75 (274)
Cash and cash equivalents at beginning of period.................................. 639 274
------------ -----------
Cash and cash equivalents at end of period........................................ $ 714 $ --
------------ -----------
Supplemental Disclosure of Non-Cash Investing and Financing Activities:
Accrued capital expenditures to be refinanced with long-term debt................ $ 1,520 $ --
Preferred dividends paid through the issuance of additional shares............... $ 1,510 $ --
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
5
<PAGE>
SHERIDAN ENERGY, INC. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BUSINESS AND ACQUISITION AND EQUITY ISSUANCE AND ACCOUNTING POLICIES
Business
Sheridan Energy, Inc. ("Sheridan") including its subsidiary, Sheridan
California Energy, Inc. ("SCEI") (collectively the "Company") is a domestic
independent energy company engaged in the production of oil and natural gas and
in intrastate natural gas gathering and treating. Sheridan is the surviving
entity resulting from the merger, effective June 12, 1997, (the "Merger") with
its former parent company, TGX Corporation ("TGX").
Acquisition and Equity Issuance
On January 25, 1999, but effective as of November 1, 1998, the Company,
through SCEI, acquired approximately $58.0 million of oil and gas producing and
non-producing properties in the Sacramento Basin, California ("California
Properties") from Amerada Hess Corporation (the "Amerada Transaction"). In order
to finance a portion of the Amerada Transaction, SCEI received a borrowing base
facility from Bank One, Texas, N.A. in the amount of approximately $43.0
million. See "Note 2--Long-Term Debt and Notes Payable" and "Note 6--Other Long-
Term Liabilities." In addition, the Company entered into an agreement with
Calpine Corporation and CPN Production Company ("CPN"), each unaffiliated
parties, pursuant to which SCEI was created to acquire and own the California
Properties. CPN contributed $14.9 million in cash in exchange for $13.0 million
in seven-year redeemable non-voting Series N-A Preferred Stock of SCEI (the
"SCEI Preferred Stock") and 20% of the outstanding common stock of SCEI valued
at $1.9 million. In certain circumstances, Sheridan may be entitled to acquire
the common stock of SCEI held by CPN. In other instances, including a change of
control of the Company, CPN may have the option to require SCEI to redeem the
SCEI Preferred Stock. Sheridan contributed $3.0 million in cash and $4.6 million
of seismic and oil and gas producing and non-producing assets in California and
received 80% of the outstanding common stock of SCEI. For further information
about the SCEI Preferred Stock, see "Note 7--Redeemable Preferred Stock."
Accounting for Derivative Instruments and Hedging Activities
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," which requires
that companies recognize all derivatives as either assets or liabilities in the
balance sheet and measure those instruments at fair value. SFAS No. 133
provides, if certain conditions are met, that a derivative may be specifically
designated as (1) a hedge of the exposure to changes in the fair value of a
recognized asset or liability or an unrecognized firm commitment (fair value
hedge) or (2) a hedge of the exposure to variable cash flows of a forecasted
transaction (cash flow hedge). Under SFAS No. 133, the accounting for changes in
fair value of a derivative depends on its intended use and designation. For a
fair value hedge, the gain or loss is recognized in earnings in the period of
change together with the offsetting loss or gain on the hedged item. For a cash
flow hedge, the effective portion of the derivative's gain or loss is initially
reported as a component of other comprehensive income and subsequently
reclassified into earnings when the forecasted transaction affects earnings. For
all other items not designated as hedging instruments, the gain or loss is
recognized in earnings in the period of change. The Company is required to adopt
this Statement by the first quarter of 2001 and is currently assessing its
effect on the consolidated financial statements.
Reclassifications
Certain amounts from the prior year have been reclassified to conform to
the current year presentation.
6
<PAGE>
2. LONG-TERM DEBT AND NOTES PAYABLE
As of June 30, 1999 and December 31, 1998 the components of long-term debt
were as follows:
<TABLE>
<CAPTION>
June 30, December 31,
1999 1998
---- ----
(in thousands)
<S> <C> <C>
Secured bank debt under revolving credit facilities.. $ 71,500 $ $37,500
Less current maturities.............................. (3,650) (5,550)
------------ ------------
Long-term debt....................................... $ 67,850 $ 31,950
============ ============
</TABLE>
Prior to 1997, Sheridan entered into a borrowing base facility ("Facility")
with Bank One, Texas, N.A. ("Bank One"). The Bank One Facility, as of June 30,
1999, had total borrowings outstanding of $33.5 million and a borrowing base of
$36.5 million and is scheduled to mature on June 30, 2001. As of June 30, 1999,
Sheridan had letters of credit outstanding of $104,000 under the Bank One
Facility, which further reduced Sheridan's availability under the Facility.
Sheridan may elect to borrow at Bank One's stated rate (the "Bank One Stated
Rate") (7.75% at June 30, 1999) or LIBOR (5.21% at June 30, 1999) plus 2.5% (the
"LIBOR Rate") or a combination thereof. As of June 30, 1999, Sheridan had $33.3
million of borrowings at the LIBOR Rate with the remainder of the borrowings
outstanding at the Bank One Stated Rate. The Bank One Facility is secured by
substantially all of Sheridan's oil and gas properties and is repayable through
monthly borrowing base reductions of $550,000. The borrowing base is
redetermined every six months or at Bank One's discretion. After consideration
of the current borrowing base and monthly facility reduction rate, current
maturities of $3.7 million were reflected in the consolidated balance sheet at
June 30, 1999.
The Bank One Facility requires the maintenance of certain ratios relating
to working capital, as adjusted pursuant to the Bank One Facility, tangible net
worth, cash flow to debt service of at least 1.1 to 1.0 and annual limitations
on general and administrative expenses and non-oil and gas capital expenditures.
In addition, the payment of dividends on Sheridan common stock and Sheridan
Series A Preferred Stock ("Sheridan Preferred Stock") is restricted except that
cash dividends may be paid on the Sheridan Preferred Stock if Sheridan has a
cash flow to debt service of at least 1.2 to 1. Sheridan was in default on
certain of these financial covenant ratios at June 30, 1999 but has received
waivers from Bank One regarding these covenants.
In January 1999, in conjunction with the Amerada Transaction, Bank One
extended a borrowing base facility (the "SCEI Facility") to SCEI, with an
initial borrowing base of $43.0 million. Under the SCEI Facility, SCEI may elect
to borrow at the Bank One Stated Rate or the LIBOR Rate or a combination
thereof. As of June 30, 1999, SCEI had $37.0 million of borrowings at the LIBOR
Rate with the remainder of the borrowings outstanding at the Bank One Stated
Rate. The SCEI Facility is secured by substantially all of SCEI's oil and gas
properties and is repayable through monthly borrowing base reductions of
$450,000. The borrowing base is redetermined every six months or at Bank One's
discretion with the next redetermination scheduled for August 1999. At June 30,
1999, SCEI had borrowings outstanding of $38.0 million and a borrowing base of
$40.8 million, and the SCEI Facility is scheduled to mature on December 31,
2001. In addition, SCEI had letters of credit outstanding of $1.5 million under
the Bank One Facility, which reduced SCEI's availability under the Facility.
Based on Bank One's review, SCEI's borrowing base shall increase to a minimum of
$45.0 million, effective July 1, 1999, and thus no current maturities are
reflected. The SCEI Facility is repayable only by SCEI and is not an obligation
of Sheridan.
The SCEI Facility requires the maintenance of certain financial ratios
including ratios relating to working capital, tangible net worth, cash flow to
debt service of at least 1.1 to 1.0 and annual limitations on general and
administrative expense and non-oil and gas capital expenditures of SCEI. In
addition, the payment of dividends on SCEI common stock and preferred stock is
restricted except that cash dividends may be paid on the SCEI Series N-A
Preferred Stock if SCEI has a cash flow to debt service ratio of at least 1.2 to
1.0. SCEI was in compliance with all financial covenant ratios at June 30, 1999.
7
<PAGE>
Cash paid by the Company for interest for the six months ended June 30,
1999 and 1998 totaled approximately $2.4 million and $1.5 million, respectively.
Costs incurred regarding the establishment of the Bank One Facility and
SCEI Facility are included in other assets and are being amortized over the term
of the facility. As of June 30, 1999 and December 31, 1998, the remaining
unamortized costs totaled $570,000 and $264,000, respectively.
3. COMMITMENTS AND CONTINGENCIES
Litigation
(a) In July 1992, certain unleased mineral interest owners commenced a
legal action in the 19th Judicial District for East Baton Rouge, Parish,
Louisiana Case No. 383844, Division "A," against TGX, as operator of three
wells. The petition alleged that the unleased owners were entitled to a refund
of revenues paid to TGX and other working interest owners, since first
production, which were attributable to the unleased owners' proportionate unit
interests and were utilized to offset the plaintiffs' proportionate share of
cost associated with drilling the wells. Sheridan argued that any claim which
arose prior to the date of the entry of the order confirming the Reorganization
Plan had been discharged through bankruptcy. Sheridan filed a lawsuit in the
U.S. Bankruptcy Court for the Western District of Louisiana (Case No. 96AP-1047)
claiming such a defense. However, the Bankruptcy Court rejected that defense.
Further, Sheridan argued that its payout notice to the unleased owners complied
with statutes requirements. The Louisiana District Court, in August 1998,
entered a judgment against the Company for $2.4 million, plus interest and
plaintiff's court cost. In December 1998, Sheridan settled with approximately
85% of the plaintiffs for a cash payment of $1.3 million. Sheridan was required
by statute to issue a letter of credit in the amount of $476,000 to pursue its
appeal for the remaining unsettled judgment. In April 1999, the remaining
claimants settled this matter for $230,000. Upon settlement, the letter of
credit was canceled.
(b) In July 1995, certain royalty owners in the same wells commenced a
separate legal action alleging that TGX and other working interest owners
improperly profited under the terms of a Gas Gathering and Transportation
Agreement. In 1996, the court entered an order granting a motion on behalf of
TGX for a partial summary judgment, holding that all of the royalty owner's
claims preceding the filing of the suit by more than three years were time-
barred. Sheridan has asked the court to dismiss the remaining claims asserted by
the royalty owners. If not dismissed, Sheridan will vigorously defend against
this lawsuit.
(c) In May 1982, Samson Resources Company ("Samson") brought suit against
TGX in the United States District Court for the Western District of Oklahoma
alleging that Sheridan owed Samson for its under-production on a well in
Oklahoma. Sheridan argued that the claim which arose prior to the date of the
entry of the order confirming the Reorganization Plan had been discharged
through bankruptcy. The Oklahoma District Court, in August 1998, entered a
judgment against the Company for $205,000, plus interest and plaintiff court
costs. In February 1999, Sheridan agreed to settle this lawsuit by paying
$258,000 and receiving a full release regarding this matter.
As a result of management's assessment of the likelihood of losses from the
various litigation matters against the Company, based on advice of legal counsel
and review of the facts, circumstances, and developments surrounding these
litigation matters, the Company recorded provisions in late 1998 and 1997 of
$2.4 million and $1.0 million, respectively, representing its estimate of losses
and/or related costs and expenses associated with such litigation matters,
including actual litigation settlements completed through April 30, 1999. As of
June 30, 1999, the Company had $160,000 of accrued liability related to the
various outstanding litigation matters and related costs.
From time to time, in the normal course of business, the Company is a party
to other litigation matters, the outcome of which, to the extent not otherwise
provided for, should not, in the opinion of management, have a material adverse
effect on the Company's financial position, cash flows or results of operations.
8
<PAGE>
4. ACCOUNTS RECEIVABLE
As of June 30, 1999 and December 31, 1998, the primary components of
accounts receivable were:
<TABLE>
<CAPTION>
June 30, December 31,
1999 1998
---- ----
(in thousands)
<S> <C> <C>
Accrued oil and gas sales......................... $ 4,215 $ 3,201
Joint interest billing and other.................. 1,319 1,016
Allowance for doubtful accounts................... (120) (120)
------------- ------------
$ 5,414 $ 4,097
============= ============
</TABLE>
5. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As of June 30, 1999 and December 31, 1998, the primary components of
accounts payable and accrued liabilities were:
<TABLE>
<CAPTION>
June 30, December 31,
1999 1998
---- ----
(in thousands)
<S> <C> <C>
Accounts payable.................................. $ 1,927 $ 2,934
Undistributed net oil and natural gas revenues.... 2,824 2,782
Accrued operating and tax expenses................ 1,590 1,172
Acquisition cost accruals......................... -- 1,881
Accrued preferred stock dividends payable......... 64 85
Accrued litigation expenses....................... 160 648
Interest payable.................................. 390 218
Accrued professional fees......................... 93 142
Notes payable..................................... 236 42
Miscellaneous accruals............................ 529 414
------------- ------------
$ 7,813 $ 10,318
============= ============
</TABLE>
6. OTHER LONG-TERM LIABILITIES
As of June 30, 1999, SCEI had accrued acquisition costs of $1.5 million
related to certain properties in California. Pursuant to an agreement, these
accrued costs will be financed through long-term debt borrowings.
7. REDEEMABLE PREFERRED STOCK
Series A Preferred Stock
In December 1997, Sheridan sold 1.0 million shares of Series A Preferred
Stock ("Sheridan Preferred Stock") to Enron Capital & Trade Resources, Inc. in
connection with the acquisition of certain oil and gas properties. The Sheridan
Preferred Stock provides for cash dividends in an amount equal to $0.60 per
share payable semi-annually (a 12% annual rate) or, at the discretion of the
Company, dividends may be paid by issuing additional fully paid shares of
Sheridan Preferred Stock in an amount equal to .0675 additional shares (a 13.5%
annual rate) for each share of Sheridan Preferred Stock then issued and
outstanding. The Sheridan Preferred Stock also provides for a liquidation
preference of $10 per share. The Sheridan Preferred Stock is redeemable from
time to time at the discretion of the Company at certain established redemption
prices, and must be redeemed on December 15, 2002, or upon the occurrence of
certain defined situations, including a change of control or a default as
defined in the Sheridan Preferred Stock designation.
9
<PAGE>
SERIES N-A PREFERRED STOCK
On January 25, 1999, SCEI issued 1.3 million shares of SCEI Preferred Stock
to CPN in connection with the Amerada Transaction. The SCEI Preferred Stock
provides for cash dividends in an amount equal to $0.625 per share payable semi-
annually (a 12.5% annual rate) or, at the discretion of SCEI, dividends may be
paid by issuing additional fully paid and non-assessable shares of SCEI
Preferred Stock in an amount equal to .07 additional shares (a 14% annual rate)
for each share of SCEI Preferred Stock then issued and outstanding. The SCEI
Preferred Stock also provides for a liquidation preference of $10 per share. The
SCEI Preferred Stock is redeemable from time to time at the discretion of SCEI,
and must be redeemed on January 25, 2006. In addition, upon the occurrence of
certain defined situations, including a change of control or a default as
defined in the SCEI Preferred Stock designation, the SCEI Preferred Stock grants
an option to the holder to require a redemption of the SCEI Preferred Stock.
10
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION
The following discussion is intended to assist in an understanding of the
Company's financial position and results of operations and those presently known
events, trends or uncertainties that are reasonably likely to have a material
impact on the Company's future results of operations and conditions or that are
reasonably likely to cause the historical financial statements not to be
necessarily indicative of future operating results or condition. It should be
read in conjunction with the unaudited consolidated financial statements and
related notes appearing elsewhere herein and the Company's Annual Report on Form
10-KSB for the year ended December 31, 1998.
Stockholders are cautioned that all forward-looking statements involve
risks and uncertainties, including without limitation, statements about the
costs of exploring and developing new oil and natural gas reserves, the price
for which such reserves can be sold, the Company's attempts to reduce overhead
and eliminate non-core assets, environmental concerns affecting the drilling of
oil and natural gas wells, the effect of the Merger, pending litigation, the
attempts to acquire producing and non-producing oil and gas properties, the
ability of the Company to make projected capital expenditures and secure
required capital and to achieve projected quarterly results and compliance with
Year 2000 issues, and general market conditions, competition and pricing.
Although the Company believes that the assumptions underlying the forward-
looking statements contained herein are reasonable, any of the assumptions could
be inaccurate, and there can therefore be no assurance that the forward-looking
statements included in this Form 10-QSB will prove accurate. Because of the
significant uncertainties inherent in the forward-looking statements contained
in this Form 10-QSB, the inclusion of such information should not be regarded as
a representation by the Company or any other person that the objectives and
plans of the Company will be achieved.
All statements, other than statements of historical facts, included or
incorporated by reference in this document that address activities, events or
developments that the Company expects or anticipates will or may incur in the
future, including such things as future capital expenditures and acquisitions,
business strategy and measures to implement such strategy, competitive
strengths, goals, expansion and growth of the Company's business and operations,
plans, references to future success as well as other statements which include
words such as "anticipate," "believe," "plan," "estimate," "expect," and
"intend," and other similar expressions constitute forward-looking statements.
Although the Company believes that the assumptions underlying the forward-
looking statements contained herein are reasonable, any of the assumptions could
be inaccurate, and therefore, there can be no assurance that the forward-looking
statements included in this document will prove to be accurate. In light of the
significant uncertainties inherent in the forward-looking statements included
herein, the inclusion of such information should not be regarded as a
representation by the Company or any other person that the objectives and plans
of the Company will be achieved.
RESULTS OF OPERATIONS
General
The following event affects the comparative results of operations and
financial condition for the three and six month periods ended June 30, 1999 and
1998 and will impact future operations and financial condition.
1999 Acquisition. On January 25, 1999, but effective as of November 1,
1998, the Company, through SCEI, acquired approximately $58.0 million of
California Properties through the Amerada Transaction. In order to finance a
portion of the Amerada Transaction, SCEI received a borrowing base facility from
Bank One, Texas, N.A. in the amount of approximately $43.0 million. See Notes 2
and 6 of "Notes to Consolidated Financial Statements (Unaudited)." In addition,
the Company entered into an agreement with Calpine Corporation and CPN, each
unaffiliated parties, pursuant to which SCEI was created to acquire and own the
California Properties. CPN contributed $14.9 million in cash and received $13.0
million in seven-year redeemable non-voting SCEI Preferred Stock and 20% of the
outstanding common stock of SCEI valued at $1.9 million. In certain
circumstances, Sheridan may be entitled to acquire the common stock of SCEI held
by CPN. Sheridan contributed $3.0 million in cash and $4.6 million of seismic
and oil and gas producing and non-producing assets in California and received
80% of the outstanding common stock of SCEI. For information about the SCEI
Preferred Stock, see Note 7 of "Notes to Consolidated Financial
11
<PAGE>
Statements (Unaudited)." As a result of the Amerada Transaction having been
completed in late January 1999, the statements of operations reflect only five
months of SCEI activity.
Three Months Ended June 30, 1999 ("1999") Compared to Three Months Ended June
30, 1998 ("1998")
Oil and Gas Operations. The following table sets forth certain information
with respect to the oil and gas operations of the Company. Oil and condensate
and natural gas prices are shown on a per barrel and per Mcf basis,
respectively. Oil and condensate and natural gas volumes are shown in barrels
and million of cubic feet (MMcf), respectively. Total production is shown on an
equivalent Mcf basis ("Mcfe"), where one barrel of oil or condensate is equal to
six Mcf of natural gas.
<TABLE>
<CAPTION>
THREE MONTHS ENDED JUNE 30,
----------------------------------------------
1999 1998 Change
--------------- -------------- -------------
<S> <C> <C> <C>
Production:
Oil and condensate (Bbl).................................................. 43,761 49,878 (12)%
Natural gas (MMcf) (includes liquids)..................................... 3,266 1,946 68%
Total production (MMcfe).................................................. 3,529 2,245 57%
Natural gas production as a percentage of total production................ 93% 87% 7%
Oil, condensate and natural gas sales (in thousands, except
percentages):
Oil and condensate sales.................................................. $ 650 $ 713 (9)%
Natural gas sales......................................................... $ 6,378 $ 3,899 64%
Total oil, condensate and natural gas sales............................... $ 7,028 $ 4,612 52%
Natural gas revenues as a percentage of oil and gas revenues.............. 91% 85% 7%
Average realized price (includes price hedges):
Oil and condensate (per Bbl).............................................. $ 14.85 $ 14.29 4%
Natural gas (per Mcf)..................................................... $ 1.95 $ 2.00 (3)%
Average cost (per Mcfe):
Operating expenses (excludes production taxes)............................ $ 0.41 $ 0.54 (24)%
Depreciation, depletion and amortization.................................. $ 0.79 $ 1.08 (27)%
General and administrative expenses....................................... $ 0.34 $ 0.45 (24)%
</TABLE>
Production
The MMcfe production increase for 1999 was primarily due to three months of
production from the California Properties of approximately 1,851 MMcfe.
Excluding California Properties production, total MMcfe 1999 production would
have declined 567 MMcfe or 25% from 1998 primarily due to property sales.
Revenues
Revenues from the sale of oil, condensate and natural gas for 1999 were
approximately $7.0 million, an increase of $2.4 million over 1998 revenues of
approximately $4.6 million. Of this increase, net sales volume increases
contributed $2.6 million of additional revenues which was partially offset by a
gas price decline. The average realized price per Mcf of natural gas for 1999,
after product price hedging, was $1.95, a decrease of $0.05 per Mcf or 3% from
$2.00 in 1998. Natural gas product price hedging during the second quarter of
1999 increased the average realized price per Mcf by $0.04 and natural gas
revenues by approximately $131,000, while 1998 gas price hedging decreased the
average realized price per Mcf by $0.03 and natural gas revenues by
approximately $58,000. Currently, the Company has 2,400 MMcf of its gas
production, or approximately 78% of third quarter 1999 proved developed
producing
12
<PAGE>
reserves, as estimated by the Company's independent petroleum engineers, hedged
at a weighted average price per Mcf of $2.35. In addition, the Company has
15,000 barrels of oil or approximately 43% of third quarter 1999 proved
developed producing reserves, as estimated by the Company's independent
petroleum engineers, hedged at a weighted average price per barrel of $17.10.
Costs and Expenses
Operating expenses. For 1999, total operating expenses, which includes
through-wellhead production costs (lifting costs), severance taxes and workover
costs, increased approximately $164,000 or 11%. Production taxes for 1999 and
1998 totaled $219,000 and $259,000, respectively. Operating expense, excluding
production taxes, per Mcfe decreased 24%, from $0.54 in 1998 to $0.41 in 1999
primarily due to lower operating expenses related to the California Properties
and lower workover costs. Workover costs for 1999 and 1998 totaled $25,000 and
$156,000, respectively, and primarily represent discretionary remedial well
activities that were implemented to enhance or increase production from existing
producing zones.
Treating and transportation expenses. Treating and transportation expense
in 1999 decreased to $202,000, as compared to $221,000 in 1998 primarily due to
production declines. These costs represent post-wellhead expenses incurred
primarily to treat the Company's Comite Field gas to comply with pipeline
specifications or to transport the gas to market.
Depletion, depreciation and amortization. Depletion, depreciation, and
amortization ("DD&A") expense for 1999 and 1998 was approximately $2.8 million
and $2.4 million, respectively. DD&A per Mcfe for 1999 was $0.79, as compared to
$1.08 for 1998. The decrease in the per Mcfe rate reflects the lower cost basis
as a result of the impairment provision of $3.2 million taken in the fourth
quarter of 1998 and the lower per Mcfe DD&A rate related to the California
Properties.
General and administrative expenses. General and administrative expenses
for 1999 and 1998 were approximately $1.2 million and $1.0 million,
respectively. For 1999, the increase in general and administrative expenses is
primarily the result of higher personnel costs partially offset by lower legal
expenses.
Exploration Costs. Exploration cost in 1999 of approximately $750,000 was
the result of the Company's participation in four gross (1.7 net) unsuccessful
wells and higher delay rental expenses related to the California Properties.
Interest expense. Interest expense for 1999 increased to $1.5 million from
$807,000 in 1998, primarily due to an increase in long-term debt resulting from
the 1999 California Properties acquisition. Interest expense is anticipated to
increase in the third quarter of 1999 as a result of the completion and funding
of the majority of the California Properties acquisition in June 1999 and
increasing interest rates.
Preferred Dividends
The 1999 preferred dividend increase is primarily the result of issuance of
the SCEI Preferred Stock. The dividend expense is based on the anticipated
payment-in-kind of the Sheridan Preferred Stock and SCEI Preferred Stock through
the issuance of additional fully paid and non-assessable shares of each.
Six Months Ended June 30, 1999 ("1999") Compared to Six Months Ended June 30,
1998 ("1998")
Oil and Gas Operations. The following table sets forth certain information
with respect to the oil and gas operations of the Company. Oil and condensate
and natural gas prices are shown on a per barrel and per Mcf basis,
respectively. Oil and condensate and natural gas volumes are shown in barrels
and million of cubic feet (MMcf), respectively. Total production is shown on an
equivalent Mcf basis ("Mcfe"), where one barrel of oil or condensate is equal to
six Mcf of natural gas.
13
<PAGE>
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
-------------------------------------------------
1999 1998 Change
------------- ------------- ---------------
<S> <C> <C> <C>
Production:
Oil and condensate (Bbl)......................................... 88,093 105,486 (16)%
Natural gas (MMcf) (includes liquids)............................ 5,873 3,632 62%
Total production (MMcfe)......................................... 6,402 4,265 50%
Natural gas production as a percentage of total production....... 92% 85% 8%
Oil, condensate and natural gas sales (in thousands, except
percentages):
Oil and condensate sales......................................... $ 1,091 $ 1,463 (25)%
Natural gas sales................................................ $ 12,170 $ 7,601 60%
Total oil, condensate and natural gas sales...................... $ 13,261 $ 9,064 46%
Natural gas revenues as a percentage of oil and gas revenues..... 92% 84% 10%
Average realized price (includes price hedges):
Oil and condensate (per Bbl)..................................... $ 12.38 $ 13.87 (11)%
Natural gas (per Mcf)............................................ $ 2.07 $ 2.09 (1)%
Average cost (per Mcfe):
Operating expenses (excludes production taxes)................... $ 0.44 $ 0.56 (21)%
Depreciation, depletion and amortization......................... $ 0.82 $ 1.07 (23)%
General and administrative expenses.............................. $ 0.36 $ 0.50 (28)%
</TABLE>
Production
The MMcfc production increase for 1999 was primarily due to five months of
production from the California Properties of approximately 3, 012 MMcfe.
Excluding California Properties production, total MMcfe 1999 production would
have declined by 875 MMcfe or 21% from 1998 primarily due to property sales.
Revenues
Revenues from the sale of oil, condensate and natural gas for 1999 were
approximately $13.3 million, an increase of $4.2 million, over 1998 revenues of
approximately $9.1 million. Of this increase, net sales volume increases
contributed $4.4 million of additional revenues which was partially offset by
oil and gas price declines. The average oil price per barrel for 1999 was
$12.38, a decrease of $1.49 per barrel or 11% as compared to the 1998 price of
$13.87. The oil price decline reduced first half revenues by approximately
$131,000. The average realized price per Mcf of natural gas for 1999, after
product price hedging, was $2.07, a decrease of $0.02 per Mcf or 1% from $2.09
in 1998. Natural gas product price hedging during the first half of 1999
increased the average realized price per Mcf by $0.20 and natural gas revenues
by approximately $1.2 million while 1998 gas price hedging activity decreased
the average realized price by $0.05 per Mcf and natural gas revenues by
approximately $158,000. Currently, for the remainder of 1999, the Company has
4,800 MMcf of its gas production, or approximately 78% of remaining 1999 proved
developed producing reserves, as estimated by the Company's independent
petroleum engineers, hedged at a weighted average price per Mcf of approximately
$2.35 and 30,000 barrels of projected oil production hedged at a weighted
average price of approximately $17.10 per barrel or 43% of estimated production.
In addition, for the year 2000, the Company has 5,760 MMcf of gas production
hedged or approximately 56% of proved developed producing reserves, as estimated
by the Company's independent petroleum engineers, at a weighted average price
per Mcf of approximately $2.47 and no oil hedge.
For the first half of 1999, the Company recorded a loss on proved property
sales of $138,000 as compared to a gain on undeveloped acreage sales of $186,000
in 1998.
14
<PAGE>
Costs and Expenses
Operating expenses. For 1999, total operating expenses, which includes
through-wellhead production costs (lifting costs), severance taxes and workover
costs, increased approximately $248,000. Production taxes for 1999 and 1998
totaled $406,000 and $550,000, respectively. Operating expense, excluding
production taxes, per Mcfe decreased 21%, from $0.56 in 1998 to $0.44 in 1999
primarily due to lower operating expenses on the California Properties and lower
workover costs. Workover costs for 1999 and 1998 totaled $240,000 and $275,000,
respectively, and primarily represent discretionary remedial well activities
that are implemented to enhance or increase production from existing producing
zones.
Treating and transportation expenses. Treating and transportation expense
in 1999 decreased to $401,000, as compared to $413,000 in 1998 primarily due to
production declines. These costs represent post-wellhead expenses incurred
primarily to treat the Company's Comite Field gas to comply with pipeline
specifications or to transport the gas to market.
Depletion, depreciation and amortization. Depletion, depreciation, and
amortization ("DD&A") expense for 1999 and 1998 was approximately $5.3 million
and $4.9 million, respectively. DD&A per Mcfe for 1999 was $0.82, as compared
to $1.07 for 1998. The decrease in the per Mcfe rate reflects the lower cost
basis as a result of the impairment provision of $3.2 million taken in the
fourth quarter of 1998 and the lower per Mcfe DD&A rate related to the
California Properties. Also included in 1998 DD&A is a provision for impairment
loss on oil and gas properties of $300,000. This impairment provision was due
to mechanical problems on a well in Louisiana.
General and administrative expenses. General and administrative expenses
for 1999 and 1998 were approximately $2.3 million and $2.1 million,
respectively. The increase in general and administrative expenses is primarily
the result of higher personnel costs offset by lower legal expenses.
Exploration costs. Exploration costs for 1999 and 1998 were $1.1 million
and $30,000, respectively. The 1999 exploration costs reflects the Company's
participation to date in four gross (1.7 net) unsuccessful wells and higher
delay rental expenses.
Interest expense. Interest expense for 1999 increased to $2.7 million from
$1.5 million in 1998, primarily due to an increase in long-term debt resulting
from the 1999 California Properties acquisition. Interest expense is
anticipated to increase throughout the remainder of 1999 due to the completion
and funding of the California Properties acquisition in June 1999 and increasing
interest rates.
Preferred Dividends
The 1999 preferred dividend increase is primarily the result of issuance of
the SCEI Preferred Stock. The dividend is based on the anticipated payment-in-
kind of the Sheridan Preferred Stock and SCEI Preferred Stock through the
issuance of additional fully paid and non-assessable shares of each.
FINANCIAL CONDITION
At June 30, 1999, the Company had a working capital deficit of
approximately $4.7 million which includes current maturities of long term debt
of $3.7 million. The working capital deficit was relatively unchanged compared
to December 31, 1998 deficit of approximately $4.8 million.
As of June 30, 1999, the Sheridan Bank One Facility had total borrowings
outstanding of $33.5 million and a borrowing base of $36.5 million and such
facility is scheduled to mature on June 30, 2001. In addition, Sheridan had
letters of credit outstanding of $104,000, which further reduced Sheridan's
availability under the Bank One Facility. The Bank One Facility is secured by
substantially all of Sheridan's oil and gas properties and is repayable through
monthly borrowing base reductions of $550,000. The borrowing base is
redetermined every six months or at Bank One's
15
<PAGE>
discretion. After consideration of the current borrowing base and monthly
facility reduction rate, current maturities of $3.7 million were reflected in
the consolidated balance sheet at June 30, 1999.
The Bank One Facility requires the maintenance of certain ratios relating
to working capital, as adjusted pursuant to the Facility, tangible net worth,
cash flow to debt service of at least 1.1 to 1.0 and annual limitations on
general and administrative expenses and non-oil and gas capital expenditures.
In addition, the payment of dividends on Sheridan Common Stock and Sheridan
Preferred Stock is restricted except that cash dividends may be paid on the
Sheridan Preferred Stock if the Company has a cash flow to debt service of at
least 1.2 to 1. Sheridan was in default on certain of these financial covenant
ratios at June 30, 1999 but received waivers from Bank One regarding these
covenants.
At June 30, 1999, the SCEI Facility had borrowings outstanding of $38.0
million and a borrowing base of $40.8 million and a maturity of December 31,
2001. In addition, SCEI had letters of credit outstanding of $1.5 million. The
SCEI Facility is secured by substantially all of SCEI's oil and gas properties
and is repayable through monthly borrowing base reductions of $450,000. The
borrowing base is redetermined every six months or at Bank One's discretion with
the next scheduled redetermination for August, 1999. Based on Bank One's
review, SCEI's borrowing base shall increase to a minimum of $45.0 million,
effective July 1, 1999. The SCEI Facility is repayable only by SCEI and is not
an obligation of Sheridan.
The SCEI Facility requires the maintenance of certain financial ratios
including ratios relating to working capital, tangible net worth, cash flow to
debt service of at least 1.1 to 1.0 and annual limitations on general and
administrative expense and non-oil and gas capital expenditures of SCEI. In
addition, the payment of dividends on SCEI common stock and preferred stock is
restricted except that cash dividends may be paid on the SCEI Preferred Stock if
SCEI has a cash flow to debt service ratio of at least 1.2 to 1.0. SCEI was in
compliance with all financial covenant ratios at June 30, 1999.
There are certain dividend and redemption obligations related to the
Sheridan Preferred Stock and SCEI Preferred Stock. For financial reporting
purposes, the preferred stocks have both debt and equity characteristics and,
accordingly, are not classified as a component of stockholders' equity. At June
30, 1999, the Sheridan and SCEI Preferred Stock redemption values were $11.4
million and $13.8 million, respectively. There are no mandatory redemption
obligations on the Sheridan and SCEI Preferred Stock until December 15, 2002 and
January 15, 2006, respectively. At the respective redemption dates, the
Sheridan or SCEI Preferred Stock then outstanding must be redeemed. However, in
certain circumstances, including a change of control as defined in their
respective Preferred Stock designations, the holders of the respective shares of
Preferred Stock have an option to require Sheridan or SCEI to redeem their
respective shares of Preferred Stock. Based on Sheridan's and SCEI's current
financial condition, neither company currently has the financial resources to
redeem their respective Preferred Stock if mandatory redemption was required.
LIQUIDITY AND CAPITAL RESOURCES
For 1999, cash provided by operating activities was approximately $6.2
million. Excluding working capital changes, cash provided by direct operating
activities was approximately $3.8 million.
As required by the Bank One credit agreements and the ECT Agreement, the
Company entered into swap agreements to reduce its exposure to price
fluctuations on a portion of its natural gas and oil sales and to achieve a more
predictable cash flow. As of June 30, 1999, the Company had hedged
approximately 2.4 Bcf and 5.8 Bcf of 1999 and 2000 natural gas production,
respectively, at a weighted average sales price per Mcf of approximately $2.35
and $2.47, respectively, and 30,000 barrels of 1999 oil production at a weighted
average price of $17.10 per barrel. Based on proved developed producing
reserves as estimated by the Company's independent petroleum engineers, the
Company has hedged approximately 78% and 56% of its 1999 and 2000 projected gas
production volumes, respectively and 43% of its 1999 oil production.
16
<PAGE>
The Sheridan Bank One Facility had a borrowing base of $36.5 million with
approximately $33.5 million of borrowings outstanding at June 30, 1999. The
Company also had letter of credit commitments totaling $104,000 outstanding
under the Bank One Facility, resulting in a quarter end Bank One Facility
availability of $996,000. The borrowing base is reduced monthly by $550,000,
and all amounts are due June 30, 2001. Considering the Company's expected
operating results and anticipated increase in availability under the credit
facility, capital resources are deemed sufficient for current operating
activities. The Company, however, will be required to seek additional financing
sources to effect any sizeable acquisition or expand its capital drilling
program.
The SCEI Facility had a borrowing base of approximately $40.8 million with
approximately $38.0 million of borrowings outstanding at June 30, 1999. The
borrowing base is reduced monthly by $450,000. Based on Bank One preliminary
indications, the SCEI borrowing base is anticipated to be increased to
approximately $46.0 million effective July 1, 1999.
At June 30, 1999 there were outstanding 1.1 and 1.4 million shares of
Sheridan and SCEI Preferred Stock, respectively, with redemption values of $10
per share. At the option of the Company, dividends on the Sheridan Preferred
Stock may be paid-in-kind, semi-annually, in an amount equal to 0.0675 shares
for each share then issued and outstanding (a 13.5% annual rate). The SCEI
Preferred Stock provides that, at the discretion of SCEI, dividends may be paid
by issuing additional fully paid and non-assessable shares of SCEI Preferred
Stock in an amount equal to .07 additional shares (a 14% annual rate) for each
share then issued and outstanding. The Company anticipates that all Sheridan
and SCEI preferred dividends for 1999 will be paid-in-kind.
The Company anticipates that continued development drilling and workovers
will maintain or increase current production volumes. The current projected
cash flows from existing properties and borrowing available and anticipated
increases under the Company's lines of credit are considered adequate to fund
current operating activities. In addition, the Company is continually
evaluating opportunities for acquisition of producing properties and currently
intends to pursue future production volume and reserve base growth through
acquisitions. Any sizeable acquisitions will have to be financed through a
combination of bank borrowings, mezzanine financing, production payments and
additional equity issuance. Effective implementation of the Company's
development and acquisition plans is expected to meet the Company's long-term
operating and liquidity requirements. However, should either the Sheridan or
SCEI Preferred Stock currently require mandatory redemption pursuant to their
respective Preferred Stock designations, neither Sheridan nor SCEI has the
financial resources to meet such redemption requirements.
Inflation and Changes in Prices
The Company's revenues have been and will continue to be affected by
changes in oil and natural gas prices, which have been unstable. Although the
futures markets provide some indication of crude oil and natural gas prices for
the subsequent 12 to 18 months, prices in the future markets are subject to
substantial changes in relatively short periods of time. For management
purposes, the Company assumes that oil and natural gas prices will continue to
fluctuate but ultimately trend upward and that operating costs and expenses will
escalate at or above the current inflation per annum rate. The principal
effects of inflation on the Company relate to the costs required to drill,
complete and operate oil and natural gas properties. Drilling costs, which
until 1998 had been on a general upward trend, have recently been decreasing due
to an industry-wide decline in drilling activity. This decrease in drilling
costs is not anticipated to significantly impact the Company's current
operations.
Accounting for Derivative Instruments and Hedging Activities
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," which requires
that companies recognize all derivatives as either assets or liabilities in the
balance sheet and measure those instruments at fair value. SFAS No. 133
provides, if certain conditions are met, that a derivative may be specifically
designated as (1) a hedge of the exposure to changes in the fair value of a
recognized asset or liability or an unrecognized firm commitment (fair value
hedge) or (2) a hedge of the exposure to variable cash flows of a forecasted
transaction (cash flow hedge). Under SFAS No. 133, the accounting for changes
in fair value of a derivative depends on its intended use and designation. For
a fair value hedge, the gain or loss is
17
<PAGE>
recognized in earnings in the period of change together with the offsetting loss
or gain on the hedged item. For a cash flow hedge, the effective portion of the
derivative's gain or loss is initially reported as a component of other
comprehensive income and subsequently reclassified into earnings when the
forecasted transaction affects earnings. For all other items not designated as
hedging instruments, the gain or loss is recognized in earnings in the period of
change. The Company is required to adopt this Statement by the first quarter of
2001 and is currently assessing its effect on the consolidated financial
statements.
Year 2000
Historically, certain computer systems, as well as certain hardware
containing embedded chip technology, such as micro controllers and
microprocessors, were designed to utilize a two-digit date field and
consequently, they may not be able to properly recognize dates in the Year 2000.
This could result in significant system failures. The Company relies on its
computer-based management information systems, as well as embedded technology to
operate instruments and equipment in conducting its normal business activities.
Certain of these computer-based programs and embedded technology may not have
been designed to function properly with respect to the application of dating
systems relating to the Year 2000.
In response, the Company has developed a "Year 2000 Plan" and has
established an internal group to identify and assess potential areas of risk and
to make any required modifications to its computer systems and equipment used in
oil and gas exploration, production, gathering and gas processing activities.
The Year 2000 Plan is comprised of various phases, including assessment,
remediation, testing and contingency plan development. After the assessment
phase has been completed and evaluated, the remediation, testing and
certification phases will be implemented to ensure that the material facilities
and business activities will continue to operate safely and reliably, and
without interruption after 1999. Based upon the results of these activities,
contingency plans will be developed to the extent deemed necessary.
The Company's inventory of computer hardware and primary business software
is substantially Year 2000 compliant. The Company is currently assessing its
engineering software systems for compliance. It is anticipated that these
software systems will be Year 2000 compliant. If any programming modifications
are required, such should be completed and tested by the third quarter of 1999
with implementation and conversion scheduled for the fourth quarter of 1999.
The Company has monitor and control equipment with embedded chip technology
which are utilized in production and gas processing operations. These various
systems are currently being reviewed in conjunction with the overall Year 2000
Plan and to date no major compliance issues have been discovered. Other systems
with embedded chip technology are relatively new and should be Year 2000
compliant according to the manufacturers.
The Company has also undertaken to monitor the compliance efforts of
suppliers, contractors and other third parties with whom it does business and
whose computer-based systems and/or embedded technology equipment interface with
those of the Company to ensure that operations will not be adversely affected by
the Year 2000 compliance problems of others. There can be no assurance that
there will not be an adverse effect on the Company if vendors, suppliers,
customers, state and federal governmental authorities and other third parties do
not convert their respective systems in a timely manner and in a way that is
compatible with the Company's information systems and embedded technology
equipment. However, management believes that ongoing communication with and
assessment of the compliance efforts and status of these third parties will
minimize these risks.
The Company believes that it can provide the resources necessary to ensure
Year 2000 compliance and expects to complete its Year 2000 Plan within a time
frame that will enable its computer-based programs and embedded technology
equipment to function without significant disruption in the Year 2000. Through
1998, the Company had incurred less than $10,000 in third party costs for
software and equipment costs related to Year 2000 compliance matters.
Management estimates that the total future third party software costs related to
Year 2000 compliance activities, based upon information developed to date, will
be less than $50,000 and such costs will be expensed as incurred. These costs
have been and will continue to be funded through operating cash flows and are
not deemed to
18
<PAGE>
be material to the operations of the Company. The cost of the remediation
activities and the completion dates are based on management's best estimates and
may be updated as additional information becomes available. The costs incurred
to date and those estimated to be incurred in the future with respect to Year
2000 issues do not include internal costs. The Company does not separately track
the internal costs incurred with respect to implementation of the Year 2000
Plan. Such costs are principally internal payroll costs, including senior
management, and field operations personnel, involved in the compliance program
and related travel and other out-of-pocket expenses.
Although the Company anticipates minimal business disruption will occur as
a result of Year 2000 issues, in the event the computer-based programs and
embedded technology equipment of the Company, or that owned and operated by
third parties, should fail to function properly, possible consequences include
but are not limited to, loss of communications links, inability to produce and
process natural gas, loss of electric power, and inability to automatically
process commercial transactions, or engage in similar normal automated or
computerized business activities.
To date, the Company has not finalized its contingency plans for possible
Year 2000 issues. As noted above, in the event the Company, after completion of
the assessment, remediation and testing phases of the Year 2000 Plan and review
of the results of monitoring the compliance efforts and status of third parties,
determines that contingency plans are necessary, the Company will finalize such
contingency plans based on its assessment of outside risks. The Company
anticipates that final contingency plans, as necessary, will be in place by the
fourth quarter of 1999.
The discussion of the Company's efforts and management's expectations
relating to Year 2000 compliance contains forward-looking statements. Presently
the Company does not anticipate that the Year 2000 issues will have a material
adverse effect on the operations or financial performance of the Company.
However, there can be no assurance that the Year 2000 will not adversely affect
the Company and its business.
19
<PAGE>
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Except as set forth in Note 3 of the "Notes to Consolidated Financial
Statements (Unaudited)" included in Part I hereof, since the filing date of the
Annual Report on Form 10-KSB, there have been no substantial developments
related to the legal proceedings described therein.
ITEM 2. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 3. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On May 25, 1999, the Company held its 1999 Annual Meeting of Shareholders.
At such time the following item was submitted to a vote of security holders.
Such matter was submitted to the security holders through the solicitation of
proxies.
1. Election of Directors.
The following persons were elected to serve on the Board of Directors
until the 2000 Annual Meeting of Stockholders or until their successors have
been duly elected and qualified. The Directors received the votes set forth
opposite their respective names:
<TABLE>
<CAPTION>
Name For Against Abstain
<S> <C> <C> <C>
B. A. Berilgen 5,003,001 0 357
Jonathan P. Carroll 5,003,001 0 357
Craig W. Childers 5,003,001 0 357
D. Bradley Dunn 5,003,001 0 357
Michael A Gerlich 5,002,966 0 392
David H. Scheiber 5,002,992 0 366
Jeffrey E. Susskind 5,003,001 0 357
</TABLE>
ITEM 4. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits:
Exhibit 27 - Financial Data Schedule
b. Reports on Form 8-K:
None.
20
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SHERIDAN ENERGY, INC.
(Registrant)
Date: August 16, 1999 By: /s/ Michael A. Gerlich
--------------------------------------
Michael A. Gerlich
Vice President and Chief Financial
Officer
21
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1999
<PERIOD-END> JAN-30-1999
<CASH> 714
<SECURITIES> 0
<RECEIVABLES> 5,414
<ALLOWANCES> 120
<INVENTORY> 0
<CURRENT-ASSETS> 6,792
<PP&E> 132,266
<DEPRECIATION> 25,664
<TOTAL-ASSETS> 115,431
<CURRENT-LIABILITIES> 11,463
<BONDS> 67,850
25,105
0
<COMMON> 67
<OTHER-SE> 7,557
<TOTAL-LIABILITY-AND-EQUITY> 115,431
<SALES> 13,261
<TOTAL-REVENUES> 13,242
<CGS> 3,625
<TOTAL-COSTS> 3,625
<OTHER-EXPENSES> 8,590
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 2,697
<INCOME-PRETAX> (1,346)
<INCOME-TAX> 0
<INCOME-CONTINUING> (1,346)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (2,982)
<EPS-BASIC> (0.44)
<EPS-DILUTED> (0.44)
</TABLE>
