<PAGE> 1
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended SEPTEMBER 30, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 0-23166
[HUGOTON LOGO] HUGOTON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
KANSAS 48-1036256
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
301 N. MAIN, SUITE 1900, WICHITA, KANSAS 67202
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (316) 262-1522
NONE
(Former name or former address, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No [ ]
Indicate the number of shares of each of the issuer's classes of common stock,
as of the latest practicable date:
CLASS OUTSTANDING AS OF OCTOBER 31, 1997
Common stock, no par value 19,838,574
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<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<Caption.
PAGE
<S> <C> <C>
PART I FINANCIAL INFORMATION (UNAUDITED)
Item 1. Consolidated Financial Statements
Consolidated Statements of Operations for the three months and
nine months ended September 30, 1997 and 1996 3
Consolidated Balance Sheets at September 30, 1997
and December 31, 1996 4
Consolidated Statements of Cash Flows for the nine months
ended September 30, 1997 and 1996 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 7
PART II OTHER INFORMATION 11
SIGNATURE 12
</TABLE>
2
<PAGE> 3
Part I. FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
HUGOTON ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ---------------------
1997 1996 1997 1996
------- ------- ------- -------
<S> <C> <C> <C> <C>
Revenues:
Oil and Gas $16,970 $14,738 $57,618 $46,211
Gas Plant 256 465 923 1,384
Loss on sales of properties (121) - (103) -
Gain on certain gas swap contracts - - 10
------- ------- ------- -------
Total revenues 17,105 15,203 58,438 47,605
------- ------- ------- -------
Expenses:
Production
Lease operations 5,303 4,358 14,904 12,722
Production and severance tax 724 878 2,688 2,459
Gathering, transportation and other 529 448 1,224 1,296
Gas plant 229 353 775 1,046
Exploration 756 527 3,304 1,034
General and administrative 2,289 1,520 7,361 4,876
Depreciation, depletion, amortization 8,839 5,936 24,590 18,207
------- ------- ------- -------
Total expenses 18,669 14,020 54,846 41,640
------- ------- ------- -------
Operating income (loss) (1,564) 1,183 3,592 5,965
Other income (expenses):
Interest (1,753) (1,561) (4,884) (4,542)
Other 67 4 151 94
------- ------- ------- -------
Total other income (expenses) (1,686) (1,557) (4,733) (4,448)
------- ------- ------- -------
Income (loss) before income taxes (3,250) (374) (1,141) 1,517
(Provision) benefit for income taxes 1,065 142 200 (576)
------- ------- ------- -------
Net income (loss) $(2,185) $ (232) $ (941) $ 941
======= ======= ======= =======
Net income (loss) per common shares $ (0.11) $ (0.01) $ (0.05) $ 0.05
======= ======= ======= =======
Weighted average number of common
shares outstanding 19,838 19,697 19,795 19,697
======= ======= ======= =======
</TABLE>
See accompanying notes.
3
<PAGE> 4
HUGOTON ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data)
(unaudited)
<TABLE>
<CAPTION>
September 30, December 31,
1997 1996
------------- ------------
<S> <C> <C>
Assets
Current assets:
Cash $ 486 $ 3,732
Accounts receivable, less allowance for doubtful accounts
of $274 ($146 in 1996) 9,931 12,985
Other 845 568
---------- ---------
Total current assets 11,262 17,285
---------- ---------
Properties and equipment, at cost (successful efforts method)
Proved properties 291,249 253,419
Unproved properties 26,512 24,696
Gas plant 1,523 1,478
Other 6,709 6,303
---------- ---------
325,993 285,896
Less accumulated depreciation, depletion and amortization (77,140) (53,118)
---------- ---------
248,853 232,778
---------- ---------
Other assets, net 1,675 1,866
---------- ---------
Total Assets $ 261,790 $ 251,929
========== =========
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable $ 5,367 $ 6,534
Other accrued liabilities 937 1,104
Accrued property taxes payable 1,320 505
Accrued interest payable 1,090 597
---------- ---------
Total current liabilities 8,714 8,740
---------- ---------
Long-term debt 105,000 95,000
Deferred income taxes 15,941 16,142
Other deferred liabilities 475 520
Commitments and contingencies - -
Shareholders' equity:
Preferred stock, no par value, 10,000,000 shares authorized,
none issued and outstanding - -
Common Stock, no par value, 100,000,000 shares authorized,
19,838,574 shares issued and outstanding (19,702,036 in 1996) 198 197
Paid-in capital 135,615 134,541
Retained (deficit) (4,153) (3,211)
---------- ---------
Total shareholders' equity 131,660 131,527
---------- ---------
Total Liabilities and Shareholders' Equity $ 261,790 $ 251,929
========== =========
</TABLE>
See accompanying notes.
4
<PAGE> 5
HUGOTON ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
--------------------------
1997 1996
-------- --------
<S> <C> <C>
Cash flows from operating activities:
Net income (loss) $ (941) $ 941
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depreciation, depletion, and amortization 24,590 18,207
Loss on sale of properties and other assets 67 (76)
Leasehold abandonments 383 -
Deferred income taxes (201) 576
Stock option compensation 77 -
Other non-cash charges 225 166
Changes in operating assets and liabilities:
Accounts receivable 3,054 (2,159)
Other current assets (277) (126)
Other (6) 784
Accounts payable (1,167) 487
Accrued liabilities 1,141 1,297
Accrued swap contract liability - (1,646)
Deferred liabilities (45) (15)
-------- --------
Net cash provided by operating activities 26,900 18,436
-------- --------
Cash flows from investing activities:
Additions to properties and equipment (42,036) (33,512)
Proceeds from sale of proved properties and other assets 891 7,265
-------- --------
Net cash used in investing activities (41,145) (26,247)
-------- --------
Cash flows from financing activities:
Proceeds from long term debt 15,000 22,000
Repayment of long term debt (5,000) (15,000)
Proceeds from exercised stock options 999 -
-------- --------
Net cash provided by financing activities 10,999 7,000
-------- --------
Net decrease in cash (3,246) (811)
Cash at beginning of period 3,732 3,914
-------- --------
Cash at end of period $ 486 $ 3,103
======== ========
Supplemental disclosure of cash flow information:
Interest paid $ 4,565 $ 4,408
</TABLE>
See accompanying notes.
5
<PAGE> 6
HUGOTON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1. INTERIM FINANCIAL STATEMENTS
The consolidated financial statements at September 30, 1997, and for
the nine month and three month periods then ended are unaudited and reflect all
adjustments (consisting of only normal recurring adjustments) which are, in the
opinion of management, necessary for a fair presentation of the financial
position and operating results for the interim period. The consolidated
financial statements should be read in conjunction with the consolidated
financial statements and notes thereto, together with management's discussion
and analysis of financial condition and results of operations, contained in the
Company's Annual Report on Form 10-K for the fiscal year ended December 31,
1996. The results of operations for the nine months ended September 30, 1997,
are not necessarily indicative of the results which may be expected for any
other interim period or for the entire fiscal year ending December 31, 1997.
NOTE 2. EARNINGS PER COMMON SHARE AND RECENTLY ISSUED ACCOUNTING STANDARDS
The Company's earnings per common share has been computed based on the
weighted average number of shares outstanding during the period.
In February 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 128, "Earnings per Share" ("FAS
128"), that specifies the computation, presentation, and disclosure
requirements for earnings per share with the objective to simplify the
computation of earnings per share. FAS 128 is effective for financial
statements for periods ending after December 15, 1997, and earlier application
is not permitted. After the effective date, all prior periods earnings per
share data shall be restated to conform with the provision of FAS 128. The
adoption of FAS 128 is not expected to have a material impact on the Company's
earnings per share data.
6
<PAGE> 7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW
Hugoton Energy Corporation (the "Company") is an independent oil and
natural gas company engaged in the exploration for and the development,
exploitation, production and acquisition of oil and natural gas reserves and
properties. The Company has historically been one of the most active
independent operators in the Hugoton Field and has expanded its operations
throughout the Mid-Continent area in Kansas, Oklahoma and Texas, and into the
Permian Basin in West Texas and New Mexico, the Austin Chalk Trend of Texas and
Louisiana and the Williston Basin in Montana and North Dakota. The Company
intends to expand its reserve base by continuing its drilling and acquisition
activities primarily in its four core areas. The Company focuses on exploring
and developing properties that it believes possess significant upside
potential, which can be realized through the application of 3-D seismic
technology and traditional geologic studies, as well as advanced drilling and
completion techniques.
The Company has accumulated an acreage position of approximately
567,000 net acres, including 165,000 net acres that were added during 1996.
These acreage holdings are located in the Company's four core areas and have
exploration and development opportunities with multiple pay horizons. The
Company believes that it has sufficient drilling prospects in its acreage
inventory to allow it to continue its drilling program through 1999, and it
intends to continue to add acreage to its holdings. The Company's 1997 capital
budget is $75 million, an increase of 63% over 1996 capital expenditures, and
includes $50 million for drilling, $10 million for 3-D seismic and land costs
and $15 million for small strategic acquisitions.
CURRENT DEVELOPMENTS
The Company has drilled a total of 88 wells during the first nine
months of 1997 and completed 79 of them for a success rate of 90%. The Company
currently has eight drilling rigs running, including six rigs in the
Mid-Continent area and the Permian Basin, one rig in the Williston Basin and
one rig in the Austin Chalk Trend. This level of drilling represents an
increase of 150% in the number of wells drilled during the first nine months of
1996. The Company expects to drill a total of 120 wells during 1997. The
Company has experienced delays in its drilling program due to the high level of
demand in the industry for drilling equipment and crews. Additional delays
have been experienced due to the diversion of technical personnel to the effort
associated with the possible sale or merger of the Company.
The Company announced on Thursday, November 13th that it had signed a
definitive agreement to merge with Chesapeake Energy Corporation (NYSE:CHK) in a
stock-for-stock transaction. Hugoton shareholders will receive a fixed exchange
ratio of 1.3 shares of Chesapeake common stock for each share of Hugoton common
stock. The transaction will result in Hugoton's shareholders owning
approximately 26% of Chesapeake, pro forma for the transaction. Based on the
closing market price of Chesapeake's common stock on November 12, the
transaction has a total value of approximately $380 million.
Chesapeake will acquire Hugoton by merging it into a subsidiary of
Chesapeake. Although both Hugoton and Chesapeake's Boards of Directors have
approved the transaction, the merger is subject to approval by both companies'
shareholders. The transaction is expected to close in early-1998 and is
expected to be accounted for as a pooling of interests and qualify as a tax-free
reorganization.
7
<PAGE> 8
RESULTS OF OPERATIONS
The following table sets forth certain operating information of the
Company for the periods shown:
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
1997 1996 1997 1996
---- ---- ---- ----
<S> <C> <C> <C> <C>
Net production (1):
Natural gas (MMCF) 4,834 4,711 14,561 14,430
Oil (MBBLS) 407 411 1,284 1,268
Natural gas equivalents (MMCFE) 7,276 7,177 22,265 22,038
Average net daily production (1):
Natural gas (MCF) 52,543 51,208 53,338 52,665
Oil (BBLS) 4,429 4,453 4,702 4,628
Natural gas equivalents (MCFE) 79,117 78,046 81,550 80,433
Average sales price per unit (2):
Natural Gas ($/MCF) $1.95 $1.54 $2.21 $1.65
Oil ($/BBL) 18.49 18.16 19.77 17.66
Natural gas equivalents ($/MCFE) 2.33 2.05 2.59 2.10
</TABLE>
_________
(1) Net production and average net daily production excludes NGLs and
natural gas purchased by AmGas (100% owned subsidiary of the Company)
from and sold to unrelated third parties.
(1) Average prices received from sales of natural gas include revenues
attributable to NGLs as the Company has not historically accounted
separately for production or revenues attributable to NGLs.
Three Months Ended September 30, 1997 Compared to Three Months Ended
September 30, 1996
Net Income or Loss and Cash Flow from Operating Activities. The
Company reported a net loss of $2.2 million, or $.11 per share, on total
revenues of $17.1 million for the three months ended September 30, 1997. This
compares to a net loss of $0.2 million, or $.01 per share, on total revenues of
$15.2 million for the three months ended September 30, 1996. Cash flows from
operating activities for the three months ended September 30, 1997, decreased
to $6.0 million from $6.4 million for the same period in 1996. Total revenues
increased for 1997 due largely to a higher average sales price per MCFE ($2.33
in 1997 versus $2.05 in 1996). The net effect of the hedging transactions was
not significant to net income for the three months ended September 30, 1997.
Oil and Gas Revenues. Revenues from oil and gas operations increased
by 16% to $17.0 million for the three months ended September 30, 1997, compared
to $14.7 million for the same period during 1996. The increase is attributed
to the higher oil and natural gas prices received by the Company during 1997.
Production Expense. Production expense for the three months ended
September 30, 1997, increased by 15 % to $6.6 million compared to $5.7 million
during the same period of 1996. Lease operating costs rose $0.9 million,
production and severance taxes decreased by $0.2 million and gathering,
transportation and other increased by $0.1 million. The rise in lease operating
costs comprised the majority of the overall increase in the category and is
primarily a result of continued increasing price pressures encountered in the
service and supply sector of the economy.
Exploration Expense. Exploration expense for the three months ended
September 30, 1997, increased to $0.8 million compared to $0.5 million during
the same period of 1996. The increase is largely due to $0.2 million in
abandoned undeveloped acreage cost.
General and Administrative Expense. General and administrative
expense increased to $2.3 million in the three month period ended September 30,
1997, compared to $1.5 million for the same period in 1996. The increase is
primarily attributable to costs associated with the Company's review of
strategic alternatives that is currently underway.
8
<PAGE> 9
Depreciation, Depletion and Amortization Expense. Depreciation,
depletion and amortization ("DD&A") for the three months ended September 30,
1997 was $8.8 million compared to $5.9 million for the same period of 1996.
The increased DD&A recorded is primarily attributed to higher DD&A rates
associated with the Company's Austin Chalk Properties.
Income Taxes. For the three months ended September 30, 1997, the
Company recorded a tax benefit of $1.1 million compared to a tax provision of
$0.1 million for the same period of 1996. The benefit recorded in 1997
represents the Company's net loss for the three months ended at its expected
effective tax rate for 1997. The effective tax rate used by the Company in
1997 differs from the 1996 rate due to the inclusion of certain non-deductible
amortization present in 1997.
Nine Months Ended September 30, 1997 Compared to Nine Months Ended
September 30, 1996
Net Income or Loss and Cash Flow from Operating Activities. The
Company reported a net loss of $0.9 million, or $.05 per share, on total
revenues of $58.4 million for the nine months ended September 30, 1997. This
compares to net income of $0.9 million, or $.05 per share, on total revenues of
$47.6 million for the nine months ended September 30, 1996. Cash flows from
operating activities for the nine months ended September 30, 1997, increased to
$26.9 million from $18.4 million for the same period in 1996. The increase in
total revenues and cash flows for 1997 is largely attributable to higher
average sales prices per MCFE ($2.59 in 1997 versus $2.10 in 1996). The
Company's realized prices for the first nine months of 1997 were positively
impacted by $.53/BBL and $.08/MCF due to hedging transactions. The net effect
of the hedging transactions was an increase of $1.3 million in net income for
the first nine months of 1997.
Oil and Gas Revenues. Revenues from oil and gas operations increased
by 25% to $57.6 million for the nine months ended September 30, 1997, compared
to $46.2 million for the same period during 1996. The increase is attributed
to the higher oil and natural gas prices received by the Company during 1997
and the positive impact of hedging transactions in place during 1997, as
previously mentioned above.
Production Expense. Production expense for the nine months ended
September 30, 1997, increased to $18.8 million compared to $16.5 million during
the same period of 1996. Lease operating costs rose $2.2 million, production
and severance taxes increased by $0.2 million while gathering, transportation
and other declined by $0.1 million. The rise in lease operating costs comprised
the majority of the overall increase in the category and is primarily a result
of continued increasing price pressures encountered in the service and supply
sector of the economy. A higher sales price per MCFE received by the Company
during 1997 ($2.59 vs. $2.10) is attributed to the increase in production and
severance taxes.
Exploration Expense. Exploration expense for the nine months ended
September 30, 1997, increased to $3.3 million compared to $1.0 million during
the same period of 1996. The increase is due to $0.3 million in seismic costs,
$1.6 million in delay rentals and $0.4 million in abandoned undeveloped acreage
costs.
General and Administrative Expense. General and administrative
expense increased to $7.4 million in the nine month period ended September 30,
1997, compared to $4.9 million for the same period in 1996. The increase is
primarily attributable to costs associated with the Company's review of
strategic alternatives that is currently underway.
Depreciation, Depletion and Amortization Expense. Depreciation,
depletion and amortization ("DD&A") for the nine months ended September 30,
1997, was $24.6 million compared to $18.2 million for the same period of 1996.
The additional DD&A recorded is primarily attributed to higher DD&A rates
associated with the Company's Austin Chalk Properties.
Income Taxes. For the nine months ended September 30, 1997, the
Company recorded a tax benefit of $0.2 million compared to a tax provision of
$0.6 million for the same period of 1996. The provision recorded in 1997
represents the Company's net income for the nine months ended at its expected
effective tax rate. The effective tax rate used by the Company in 1997 differs
from the 1996 rate due to the inclusion of certain non-deductible amortization
present in 1997.
9
<PAGE> 10
LIQUIDITY AND CAPITAL RESOURCES
The Company's working capital position decreased by $6.0 million from
year-end 1996 to $2.5 million at September 30, 1997. Cash and accounts
receivable decreased by $3.2 million and $3.1 million, respectively. The
Company's current ratio of current assets to current liabilities was 1.3 to 1.0
at September 30, 1997 and 2.0 to 1.0 at December 31, 1996.
Capital Expenditures. The Company's primary needs for cash are for
exploration, development and acquisitions of oil and gas properties, payment of
interest on outstanding indebtedness and working capital obligations. The
Company's 1997 capital expenditure budget has been set at $75 million of which
approximately $50 million is committed to drilling, $10 million for 3-D seismic
and land costs and $15 million for small strategic acquisitions. Through
September 30, 1997, the Company has expended approximately $40 million of its
capital budget. Funding for the Company's exploration and development
activities and its working capital obligations are provided primarily by
internally-generated cash flow. The Company budgets its capital expenditures
based on projected cash flows and routinely adjusts the level of its capital
expenditures in response to anticipated changes in cash flows.
During the first nine months of 1997, the Company's net borrowings
increased by $10.0 million. Proceeds from the borrowings were used to fund
acquisitions and the Company's drilling activities.
Capital Resources. The Company's capital resources consist of cash
flow from operating activities and funds available under its bank credit
facility (the "Credit Facility"). The Company's Credit Facility is an
unsecured $250 million revolving credit agreement that is due September 7,
1999. The new facility is provided by a group of seven commercial banks led by
Bank One, Texas, N.A. as agent (the "Agent Bank"). The Borrowing Base, as
defined in the loan agreement, is currently set at $135 million, and is subject
to semi-annual redetermination. Outstanding borrowings were $105 million at
September 30, 1997.
The Credit Facility provides the option of borrowing at floating
interest rates based on the Agent Bank's base rate or at a Eurodollar option
based on the London Interbank Offered Rates ("LIBOR") plus 3/4 of 1% to 1.25%,
depending on the outstanding loan balance. Interest is paid quarterly or at
the end of each interest period. The current weighted average interest rate is
6.79%. The Company also incurs a commitment fee of 1/4 of 1% on the unused
portion of the Borrowing Base. The Credit Facility contains customary
restrictive covenants, including restrictions on the payment of dividends and
requires the Company to maintain certain financial ratios.
The Company has historically funded its operations and capital
spending programs with cash flow from operations and borrowings under bank
credit facilities. The Company believes that cash flow from operations and the
borrowing availability under the Credit Facility will be sufficient to meet its
anticipated capital requirements for 1997. However, because future cash flows
and the availability of financing are subject to a number of variables, such as
the level of production and the prices received for natural gas and oil, there
can be no assurance that the Company's capital resources will be sufficient to
maintain currently planned levels of capital expenditures.
In general, because the Company's principal natural gas and oil
reserves are depleted by production, its success is dependent upon the results
of its development, acquisition and exploration activities.
Hedging Transactions. With the objective of achieving more
predictable revenues and cash flows and reducing the exposure to fluctuations
in oil and natural gas prices, the Company periodically enters into hedging
transactions of various kinds with respect to both oil and natural gas. While
the use of these hedging arrangements limits the downside risk of adverse price
movements, it may also limit future revenues from favorable price movements.
At September 30, 1997, the Company had active swap agreements fixing
the price of 20,000 MMBTU of natural gas per day through October 1997 at an
average net price to the Company of $2.11 per MMBTU and 60,000 BBLS of oil per
month through October 1997 at a net price to the Company of $21.19 per BBL.
The Company continues to evaluate whether to enter into additional
hedging transactions for 1997 and future years. In addition, the Company may
determine from time to time to terminate its then existing hedging positions.
This report contains certain forward-looking statements within the
meaning of Section 27A of the Securities Act of
10
<PAGE> 11
1933, as amended, and Section 21E of the Securities Exchange Act of 1934,
amended. Although the Company believes 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 contained in the report will prove to be accurate.
PART II. OTHER INFORMATION
ITEMS 1, 2, 3, 5 & 6 ARE NOT APPLICABLE AND HAVE BEEN OMITTED.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the Company's Annual Meeting of Stockholders, held May 15, 1997, the
following individuals were elected to the Board of Directors:
Jonathan S. Linker - Class II director, term expires at annual meeting
of stockholders in 2000
William E. Macaulay - Class II director, term expires at annual
meeting of stockholders in 2000
The following members of the Board of Directors had terms that continued after
the meeting:
David S. Elkouri - Class I director, term expires at annual meeting of
stockholders in 1998
John T McNabb, II - Class I director, term expires at annual meeting
of stockholders in 1998
Alan J. Andreini - Class I director, term expires at annual meeting
of stockholders in 1998
Floyd C. Wilson - Class III director, term expires at annual meeting
of stockholders in 1999
W. Mark Womble - Class III director, term expires at annual meeting of
stockholders in 1999
J. W. Decker - Class III director, term expires at annual meeting of
stockholders in 1999
The following proposals were approved at the Company's Annual meeting:
<TABLE>
<CAPTION>
Affirmative Negative Votes
Votes Votes Withheld
----- ----- --------
<S> <C> <C> <C>
1. Election of two Class II directors to the 16,277,219 235 -
Board of Directors
2. Consider and approve the Hugoton Energy 16,229,619 44,800 3,035
Corporation Amended and Restated 1995
Stock Option Plan
3. Consider and approve a Nonstatutory Stock 16,132,369 136,450 8,635
Option Agreement between the Company
and Jay W. Decker dated September 8, 1996
4. Consider and ratify the appointment of 16,274,154 1,300 2,000
Ernst & Young LLP as the independent
accountants of the Company for the fiscal
year ending December 31, 1997
</TABLE>
11
<PAGE> 12
SIGNATURE
Pursuant to the requirements Section 13 or 15 (d) of the Securities Exchange
Act 1934, the Registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized, on the 14th day of November
1997.
HUGOTON ENERGY CORPORATION
(Registrant)
Date: November 14, 1997 /s/ W. Mark Womble
----------------------------- -----------------------------------
W. Mark Womble, Executive
Vice President, Chief
Financial Officer and Director
(Chief Financial Officer and
Duly Authorized Officer)
12
<PAGE> 13
INDEX TO EXHIBITS
Exhibit
No. Description
------- -----------
27 Financial Data Schedule
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 0000914144
<NAME> HUGOTON ENERGY CORP
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> SEP-30-1997
<CASH> 486
<SECURITIES> 0
<RECEIVABLES> 9,931
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 11,262
<PP&E> 325,993
<DEPRECIATION> 77,140
<TOTAL-ASSETS> 261,790
<CURRENT-LIABILITIES> 8,714
<BONDS> 0
0
0
<COMMON> 198
<OTHER-SE> 131,462
<TOTAL-LIABILITY-AND-EQUITY> 261,790
<SALES> 58,438
<TOTAL-REVENUES> 58,438
<CGS> 19,591
<TOTAL-COSTS> 19,591
<OTHER-EXPENSES> 35,255
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 4,884
<INCOME-PRETAX> 1,141
<INCOME-TAX> 200
<INCOME-CONTINUING> 941
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 941
<EPS-PRIMARY> 0.05
<EPS-DILUTED> 0.05
</TABLE>
