SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED June 30, 1999
INDEX

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

Liabilities and Stockholders' Equity

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three months ended June 30,			Six months ended June 30,
	1999	1998		1999	1998
	----------------	----------------		----------------	----------------
Revenues:
Oil and gas sales	$      23,572,785	$      15,681,004		$     44,668,421	$     31,482,915
Fees from limited partnerships and joint ventures	57,272	124,948		99,649	204,879
Interest income	9,538	44,376		23,282	62,875
Other, net	289,139	490,402		625,469	1,065,290
	----------------	----------------		----------------	----------------
	23,928,734	16,340,730		45,416,821	32,815,959
	----------------	----------------		----------------	----------------
Costs and Expenses:
General and administrative, net of reimbursement	1,184,612	879,945		2,294,286	1,880,424
Depreciation, depletion, and amortization	10,478,278	7,250,518		21,226,751	13,985,240
Oil and gas production	4,130,804	2,355,237		8,550,948	4,874,997
Interest expense, net	3,348,635	1,584,877		6,653,012	2,969,643
	----------------	----------------		----------------	----------------
	19,142,329	12,070,577		38,724,997	23,710,304
	----------------	----------------		----------------	----------------
Income Before Income Taxes	4,786,405	4,270,153		6,691,824	9,105,655
Provision for Income Taxes	1,634,378	1,373,683		2,258,042	2,979,570
	----------------	----------------		----------------	----------------
Net Income	$      3,152,027	$      2,896,470		$     4,433,782	$     6,126,805
	===========	===========		===========	===========
Per share amounts-
Basic:	$               0.20	$               0.18		$               0.27	$               0.37
	===========	===========		===========	===========
Diluted:	$               0.20	$               0.18		$               0.27	$               0.37
	===========	===========		===========	===========
Weighted Average Shares Outstanding	16,151,514	16,524,739		16,153,982	16,512,562
	===========	===========		===========	===========

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(1) $.01 Par Value
(2) Unaudited


See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Period Ended June 30,
	1999	1998
	-----------------	-----------------
Cash Flows from Operating Activities:
Net income	$ 4,433,782	$ 6,126,085
Adjustments to reconcile net income to net cash provided
by operating activities -
Depreciation, depletion, and amortization	21,226,751	13,985,240
Deferred income taxes	2,157,818	2,728,421
Deferred revenue amortization related to production
payment	(557,616)	(647,279)
Other	257,572	233,297
Change in assets and liabilities -
Decrease in accounts receivable	1,373,493	2,864,171
Decrease in accounts payable and accrued
liabilities, excluding income taxes payable	(702,149)	(20,211)
Increase in income taxes payable	113,569	221,223
	-----------------	-----------------
Net Cash Provided by Operating Activities	28,303,220	25,490,947
	-----------------	-----------------
Cash Flows From Investing Activities:
Additions to property and equipment	(23,190,252)	(66,968,334)
Proceeds from the sale of property and equipment	1,746,559	1,199,061
Net cash received (distributed) as operator
of oil and gas properties	(1,354,867)	(6,749,156)
Net cash received (distributed) as operator
of partnerships and joint ventures	3,243,695	575,843
Limited partnership formation and marketing costs	(648,637)	(478,048)
Other	(183,267)	(48,745)
	-----------------	-----------------
Net Cash Used in Investing Activities	(20,386,769)	(72,469,379)
	-----------------	-----------------
Cash Flows From Financing Activities:
Net proceeds from (payments of) bank borrowings	(6,200,000)	56,085,000
Net proceeds from issuances of common stock	476,971	1,178,846
Purchase of treasury stock	(1,462,740)	(826,846)
	-----------------	-----------------
Net Cash Provided by (Used in) Financing Activities	(7,185,769)	56,437,000
	-----------------	-----------------
Net Increase in Cash and Cash Equivalents	730,682	9,458,568
Cash and Cash Equivalents at Beginning of Period	1,630,649	2,047,332
	-----------------	-----------------
Cash and Cash Equivalents at End of Period	$2,361,331	$11,505,900
	==========	==========
Supplemental disclosures of cash flow information:
Cash paid during period for interest, net of amounts capitalized	$6,395,440	$2,794,055
Cash paid during period for income taxes	$     ---	$     29,926

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1999 (UNAUDITED) AND DECEMBER 31, 1998

(1) GENERAL INFORMATION

 

The condensed consolidated financial statements included herein have been prepared by Swift Energy Company and are unaudited, except for the balance sheet at December 31, 1998, which has been prepared from the audited financial statements at that date. The financial statements reflect necessary adjustments, all of which were of a recurring nature, and are in the opinion of our management, necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in the latest Form 10-K and Annual Report.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Oil and Gas Properties

 

We follow the "full-cost" method of accounting for oil and gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the acquisition, exploration, and development of oil and gas reserves are capitalized. Under the full-cost method of accounting, such costs may be incurred both prior to or after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, equipment, and certain general and administrative costs directly associated with acquisition, exploration, and development activities. Interest costs related to unproved properties are also capitalized to unproved oil and gas properties. General and administrative costs related to production and general overhead are expensed as incurred.

No gains or losses are recognized upon the sale or disposition of oil and gas properties, except in transactions that involve a significant amount of reserves. The proceeds from the sale of oil and gas properties are generally treated as a reduction of oil and gas property costs. Fees from associated oil and gas exploration and development limited partnerships are credited to oil and gas property costs to the extent they do not represent reimbursement of general and administrative expenses currently charged to expense.

Future development, site restoration, and dismantlement and abandonment costs, net of salvage values, are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as our capitalized oil and gas property costs are amortized. Our properties are all onshore and historically the salvage value of the tangible equipment offsets our site restoration and dismantlement and abandonment costs. We expect this relationship will continue in the future.

We compute our provision for depreciation, depletion, and amortization of oil and gas properties on the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties - including future development, site restoration, and dismantlement and abandonment costs, but excluding costs of unproved properties - by an overall rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves. This calculation is done on a country by country basis for those countries with oil and gas production. We currently have production in the United States only.

The cost of unproved properties not being amortized is assessed quarterly, on a country by country basis, to determine whether such properties have been impaired. Domestically, any impairment assessed is added to the cost of proved properties being amortized. To the extent costs accumulated in our international initiatives are determined by management to be costs that will not result in the addition of proved reserves, any impairment is charged to income. In determining whether such costs should be impaired, our management evaluates, among other factors, current oil and gas industry conditions, international economic conditions, capital availability, foreign currency exchange rates, the political stability in the countries in which we have an investment, and available geological and geophysical information.

The calculation of the Ceiling Test and provision for depreciation, depletion, and amortization is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered.

Hedging Activities

 

Our revenues are primarily the result of sales of our oil and natural gas production. Market prices of oil and natural gas may fluctuate and adversely affect operating results. To mitigate some of this risk, we do engage periodically in certain limited hedging activities, but only to the extent of buying protection price floors for portions of our and the limited partnerships’ oil and natural gas production. Costs and any benefits derived from these price floors are accordingly recorded as a reduction or increase, as applicable, in oil and gas sales revenue and were not significant for any period presented. The costs to purchase put options are amortized over the option period. The costs related to 1999 hedging activities through June 30, 1999 totaled approximately $591,600 with benefits of approximately $348,400 having been received, resulting in a net cash outflow of approximately $243,200. The costs related to open contracts as of June 30, 1999 totaled approximately $194,000 and had a fair market value of $10,000.

Earnings Per Share

 

Basic earnings per share ("Basic EPS") has been computed using the weighted average number of common shares outstanding during the respective periods. Basic EPS has been retroactively restated in all periods presented to give recognition to the 10% stock dividend declared in October 1997 that resulted in an additional 1,494,622 shares being issued.

The calculation of diluted earnings per share ("Diluted EPS") assumes conversion of our Convertible Notes as of the beginning of the respective periods and the elimination of the related after-tax interest expense and assumes, as of the beginning of the period, exercise of stock options and warrants (using the treasury stock method). Certain of our stock options that would potentially dilute Basic EPS in the future were not included in the computation of diluted EPS because to do so would have been antidilutive for the periods presented. Diluted EPS has also been retroactively restated for all periods presented to give effect to the 10% stock dividend. The original conversion price of the Convertible Notes of $34.6875 has been revised to $31.534 to reflect the October 1997 stock dividend declared.

New Accounting Pronouncement

 

In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Statement establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows the gains and losses on derivatives to offset related results on the hedged item in the income statements and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133, as amended by SFAS No. 137, is effective for fiscal years beginning after June 15, 2000. We are currently evaluating the new standard, but have not yet determined the impact it will have on our financial position and results of operations.

(3) BANK BORROWINGS

 

Under our $250.0 million revolving credit facility with a syndicate of ten banks, at June 30, 1999, we had outstanding borrowings of $140.0 million. At December 31, 1998, we had outstanding borrowings of $146.2 million under our borrowing arrangements. At June 30, 1999, the credit facility consisted of a $250.0 million revolving line of credit with a $162.5 million borrowing base. The interest rate is either (a) the lead bank’s prime rate (8.00% at June 30, 1999) or (b) the adjusted London Interbank Offered Rate ("LIBOR") plus the applicable margin depending on the level of outstanding debt (a weighted average of 6.64% at June 30, 1999). The applicable margin is based on our ratio of outstanding balance on the credit facility to the last calculated borrowing base. All of the $140.0 million borrowed at June 30, 1999 was borrowed at the LIBOR rate.

The terms of the credit facility include, among other restrictions, a limitation on the level of cash dividends (not to exceed $2.0 million in any fiscal year), requirements as to maintenance of certain minimum financial ratios (principally pertaining to working capital, debt, and equity ratios), and limitations on incurring other debt. Since inception, no cash dividends have been declared on our common stock. We are currently in compliance with the provisions of this agreement. The borrowing base is redetermined at least every six months and the May 1, 1999 borrowing base determination was set at $164.0 million, declining by $1.5 million per month to $155.0 million at November 1, 1999, the next scheduled borrowing base determination date. By its terms, the credit facility extends until August 2002.

(4) ACQUISITION OF PROPERTIES

 

We purchased interests in the Brookeland and Masters Creek Fields from Sonat Exploration Company in the third quarter of 1998 for approximately $85.6 million in cash. Of this purchase price, $55.3 million was spent for producing properties, $15.0 million for 20% interests in two natural gas processing plants, and $15.3 million for leasehold properties.

As of December 31, 1998, estimated proved reserves for these acquired properties were 130.5 Bcfe, of which approximately 58% were natural gas, and 59% were proved undeveloped. At such date the properties included 162 producing wells in the Brookeland Field in Southeast Texas and the Masters Creek Field in Western Louisiana, 23 saltwater disposal wells, a 20% interest in two natural gas plants, associated production facilities, and working interests in approximately 444,000 net acres. Swift has become operator of 115 of the 162 wells. Our production on these properties amounted to approximately 11.6 Bcfe in 1998 and 12.0 Bcfe in the first six months of 1999, of which 56% was oil in each of these periods. The two gas plants are operated by a third party and have combined capacity of 250 MMcfe per day.

This acquisition was accounted for by the purchase method and was incorporated into our results of operations in the third quarter of 1998. The following unaudited pro forma supplemental information presents consolidated results of operations as if this acquisition had occurred on January 1, 1998:

		Six months ended June 30, 1998
(Thousands, except per share amounts)		(Unaudited)
Revenue		$65,741
Net Income Before Income Taxes		$20,337
Net Income		$13,539
Per Share Amounts--
Basic		$0.82
Diluted		$0.77

(5) FOREIGN ACTIVITIES

 

New Zealand. Since October 1995, the New Zealand Minister of Energy has issued Swift two petroleum exploration permits. The first permit covered approximately 65,000 acres in the Onshore Taranaki Basin of New Zealand’s North Island, and the second covered approximately 69,300 adjacent acres. A wholly-owned subsidiary, Swift Energy New Zealand Limited, formed in late 1997, conducts our New Zealand activities and owns the interest in the permits. In March 1998, we surrendered approximately 46,400 acres covered in the first permit, and the remaining acreage has been included as an extension of the area covered in the second permit leaving us with only one expanded permit. Under the terms of the expanded permit, we must drill one exploratory well prior to August 12, 1999, which we have commenced. We have fulfilled all other obligations under the permit.

On October 23, 1998, we entered into separate agreements with Marabella Enterprises Ltd., a subsidiary of Bligh Oil & Minerals N.L., an Australian company, to obtain from Marabella a 25% working interest in another New Zealand petroleum exploration permit and for Marabella to become a 5% participant in our permit. During the fourth quarter of 1998, Marabella drilled an unsuccessful exploration well on its permit. Accordingly, we charged $400,000 against earnings, representing our costs of such well. We also agreed in principle to participate with Marabella in an additional permit as a 25% working interest owner. Additionally, Swift obtained a 7.5% working interest in another New Zealand permit from Antrim Oil and Gas Limited, and Antrim became a 5% participant in our permit. On this permit, an exploratory well was drilled and temporarily abandoned during the second quarter of 1999, and we charged our $290,000 portion of the costs on this well against earnings. As of June 30, 1999, our investment in New Zealand totaled approximately $5.4 million. We included these costs in the unproved properties portion of oil and gas properties.

Our portion of the currently budgeted drilling costs of the above mentioned well in our expanded permit are approximately $4.3 million. We expect to conclude the drilling of this well during the third quarter of 1999. Should this exploratory well fail to discover economic reserves, we would be required to charge against earnings the drilling costs, plus a large portion of the capitalized costs in the unproved properties portion of oil and gas properties, with the estimated potential aggregate impairment of costs currently estimated to total up to $6.0 million in the second half of 1999.

SWIFT ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

GENERAL

 

Over the last several years, we have emphasized adding reserves through drilling activity. We also add reserves through strategic purchases of producing properties when oil and gas prices are lower and other market conditions are appropriate, as we did in the third quarter of 1998 with the purchase of the Masters Creek and Brookeland Fields from Sonat Exploration Company. In 1996, 1997, 1998 and in the first six months of 1999, we used this flexible strategy of employing both drilling and acquisitions to add more reserves than we depleted through production. Our revenues are primarily from oil and gas sales attributable to properties in which we own a direct or indirect interest.

LIQUIDITY AND CAPITAL RESOURCES

 

During the first six months of 1999, we relied upon our internally generated cash flows of $28.3 million to fund capital expenditures of $23.2 million. We expect internally generated cash flows, together with limited borrowings under our credit facility, to provide cash and working capital for the remainder of 1999. During 1998, we used $138.3 million borrowed under our credit facilities, along with our internal cash flows of $54.2 million, to fund capital expenditures of $183.8 million.

Net Cash Provided by Operating Activities. For the first half of 1999, net cash provided by our operating activities increased by 11% to $28.3 million, as compared to $25.5 million during the first six months a year earlier. The 1999 increase of $2.8 million was primarily due to $13.2 million of additional oil and gas sales. However, this increase was substantially offset by the $7.4 million increases in both oil and gas production costs and in interest expense.

Credit Facility. At June 30, 1999, we had outstanding borrowings of $140.0 million under our credit facility syndicated in August 1998. At December 31, 1998, we had outstanding borrowings of $146.2 million under the credit facility. At June 30, 1999, our credit facility consists of a $250.0 million revolving line of credit with a $162.5 borrowing base. Our $250.0 million revolving credit facility includes, among other restrictions, requirements as to maintenance of certain minimum financial ratios (principally pertaining to working capital, debt, and equity ratios), and limitations on incurring other debt. We are currently in compliance with the provisions of this agreement.

Debt Maturities. The new credit facility extends until August 18, 2002. Our $115.0 million convertible notes mature November 15, 2006.

Working Capital. Our working capital increased from $3.8 million at December 31, 1998, to $5.2 million at June 30, 1999, as our internally generated funds exceeded our capital expenditures.

Due to the nature of our business, the individual components of our working capital fluctuate considerably from period to period. We incur significant working capital requirements in our role as operator of approximately 836 wells and in our drilling and acquisition activities. In this capacity, we are responsible for certain day-to-day cash management, including the collection and disbursement of oil and gas revenues and related expenses.

Common Stock Repurchase Program. In March 1997, we commenced a common stock repurchase program which terminated pursuant to its terms as of June 30, 1999. We have spent $13.3 million through June 30, 1999 to acquire 927,774 shares at an average cost of $14.34 per share. In March 1999, we used 68,318 shares of treasury stock to fund our employer liability in the 401(k) program for our employees.

Capital Expenditures. During the first six months of 1999, we used $23.2 million to fund capital expenditures for property, plant, and equipment. These capital expenditures included:

• $15.7 million for drilling costs, both development and exploratory;

• $6.7 million of domestic prospect costs, principally prospect leasehold, seismic and geological costs of unproved prospects for our account;

• $0.4 million invested in New Zealand; and

• $0.4 million spent primarily for computer equipment, software and furniture and fixtures.

In the remaining six months of 1999, we expect to spend approximately $31.0 million on capital expenditures, including investments in all areas in which investments were made during the first six months of the year as described above. Ten wells were drilled in the first half of 1999, and seven were completed as successful development wells. For the second half of 1999, we anticipate drilling an additional 10 wells, made up of eight development wells and two exploratory wells. We estimate capital expenditures for 1999 to be approximately $54.2 million, which is substantially lower than prior years. Approximately $36.0 million of the 1999 budget is allocated to drilling, primarily in our core fields. The remaining $18.2 million is targeted principally for leasehold, seismic and geological costs of unproved properties. We believe that 1999’s anticipated internally generated cash flows, together with limited borrowings under our credit facility, will be sufficient to finance the costs associated with our currently budgeted remaining 1999 capital expenditures.

Proposed Offerings. On July 13, 1999, we announced our intention to offer for sale 4,000,000 shares of common stock in a public offering concurrently with a separate proposed public offering of $125.0 million of senior subordinated notes. Neither proposed offering is conditioned upon the other. Swift intends to use the net proceeds from both offerings, if consummated, to repay our outstanding debt under our credit facility. The amount which could be borrowed under the credit facility is then anticipated to be approximately $150.0 million, which then could be used, along with any excess net proceeds of the offerings and our internal cash flow, to fund our future capital expenditures.

RESULTS OF OPERATIONS – Six Months Ended June 30, 1999 and 1998
     

Revenues. Our revenues increased 38% during the first six months of 1999 as compared to the same period in 1998. This increase was caused by growth in our oil and gas sales, which resulted from the increase in production volumes and which was offset by lower gas prices.

Oil and Gas Sales. Our oil and gas sales increased 42% to $44.7 million in the first six months of 1999, compared to $31.5 million for the comparable period in 1998. Our gas production increased 16% and oil production increased 256% primarily due to production from the Brookeland and Masters Creek Fields, which were acquired in the third quarter of 1998. Our net sales volume in the first six months of 1999 increased by 55%, or 7.8 Bcfe, over volumes in the same period in 1998. A 14% decrease in gas prices between the two periods significantly offset the increase in volume and 9% increase in oil prices.

Our $13.2 million increase in oil and gas sales during the first six months of 1999 resulted from:

• Volume increases which added $16.0 million of sales, with $4.2 million of the increase coming from the 1.9 Bcf increase in gas sales volumes and $11.8 million of the increase coming from the 987,000 barrel increase in oil sales volumes; and

• Price variances which had a $2.8 million unfavorable impact on sales due to the decrease in average gas prices received of $4.2 million offset by an increase of $1.4 million in average oil prices received.

The following table provides additional information regarding the changes in the sources of our oil and gas sales and volumes for the first six month periods of 1999 and 1998.

Field		Revenues (In Millions)					Net Sales Volumes (Bcfe)
		1999		1998		1999			1998
AWP Olmos		$13.8		$17.2		6.9			7.8
Brookeland		$ 5.8		--		2.9			--
Giddings		$ 3.6		$ 8.9		1.9			3.9
Masters Creek		$19.3		--		9.1			--

 

Revenues from oil and gas sales comprised 98% of our total revenues for the first six months of 1999 as compared to 96% for the first half of 1998. Our acquisition of interests in the Masters Creek and Brookeland Fields, which have a higher percentage of production from oil, has decreased the predominance of gas in our production mix from 84% in the first six months of 1998 to 63% in the first six months of 1999. Even though we scaled back our 1999 capital expenditures budget, we expect oil and gas sales volumes to increase in 1999 when compared to 1998, primarily due to the full year of production from the Masters Creek and Brookeland Fields. However, due to the decrease in the 1999 capital expenditures budget, and the resulting curtailment of new drilling in the Giddings Field, the natural production decline in this field was not offset by newly developed production.

The following table provides additional information regarding our oil and gas sales:

 

Costs and Expenses. Our general and administrative expenses for the first six months of 1999 increased approximately $0.4 million, when compared to the same period in 1998. However, our general and administrative expenses per Mcfe produced decreased by 21% from $0.13 per Mcfe for the first six months of 1998 to $0.10 per Mcfe for the comparable period in 1999. Supervision fees netted from general and administrative expenses for the first six months of 1999 were $1.5 million and for the same period of 1998 were $1.4 million.

Depreciation, depletion and amortization of our assets, or DD&A, increased 52% or approximately $7.2 million for the first six months of 1999. This was primarily due to additions to our reserves and associated costs and to the related 55% increase in production volumes from the added reserves primarily resulting from the Sonat acquisition as compared to the same period in 1998. Our DD&A rate per Mcfe of production has decreased from $0.98 per Mcfe in the first six months of 1998 to $0.96 per Mcfe in the same 1999 period.

Our production costs per Mcfe increased to $0.39 per Mcfe in the first half of 1999 from $0.34 per Mcfe in the same 1998 period. In the Brookeland and Masters Creek Fields, a higher percentage of our production is from oil. Production costs for oil typically are higher than those for gas, resulting in a higher production cost per Mcfe. Primarily due to the 55% increase in our production volumes, oil and gas production costs increased by 75%, or approximately $3.7 million, in the first six months of 1999 when compared to the first six months of 1998. Supervision fees netted from production costs for the first six months of 1999 were $1.5 million and for the first six months of 1998 were $1.4 million.

Interest expense on our convertible notes due 2006, including amortization of debt issuance costs, was the same in the first six months of 1999 and in 1998, totaling $3.8 million. Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $4.9 million in the first six months of 1999, compared to $1.1 million for our credit facilities in the same 1998 period. Thus, 1999 total interest charges were $8.7 million, of which $2.0 million was capitalized. In the first six months of 1998, these charges totaled $4.8 million, of which $1.8 million was capitalized. We capitalized that portion of interest related to our exploration, partnership and foreign business development activities. The increase in interest expense in 1999 is attributable to the increase in amounts outstanding under our credit facility.

Net Income. Our net income for the first six months of 1999 of $4.4 million and basic earnings per share, or EPS, of $0.27 were both 27% lower than net income of $6.1 million and basic EPS of $0.37 for the same period in 1998. This decrease primarily reflected the effect of lower gas prices, while our costs and expenses increased 63% in relation to the 55% increase in production volumes discussed above.

RESULTS OF OPERATIONS – Three Months Ended June 30, 1999 and June 30, 1998

 

Revenues. Our revenues increased 46% during the second quarter of 1999 as compared to the same period in 1998. This increase was caused by growth in our oil and gas sales, which resulted from the increase in production volumes.

Oil and Gas Sales. Our oil and gas sales increased 50% to $23.6 million in the second quarter of 1999, compared to $15.7 million for the comparable period in 1998. Our natural gas production increased 9% and oil production increased 239% primarily due to production from the Brookeland and Masters Creek Fields, which were acquired in the third quarter of 1998. Our net sales volume in the second quarter of 1999 increased by 45%, or 3.3 Bcfe, over volumes in the same period in 1998. A 7% decrease in gas prices between the two periods slighty offset the increase in volume and 36% increase in oil prices.

Our $7.9 million increase in oil and gas sales during the second quarter of 1999 resulted from:

• Volume increases which added $6.3 million of sales, with $1.2 million of the increase coming from the 0.5 Bcf increase in gas sales volumes and $5.1 million of the increase coming from the 454,000 barrel increase in oil sales volumes; and

• Price variances which had a $1.6 million favorable impact on sales, due to the decrease in average gas prices received of $1.0 million, offset by an increase of $2.6 million in average oil prices received.

The following table provides additional information regarding the changes in the sources of our oil and gas sales and volumes for the second quarter periods of 1999 and 1998.

Field		Revenues (In Millions)						Net Sales Volumes (Bcfe)
		1999		1998			1999			1998
AWP Olmos		$ 7.0		$ 8.9			3.2			3.9
Brookeland		$ 2.9		--			1.3			--
Giddings		$ 2.2		$ 4.7			1.0			2.1
Masters Creek		$10.0		--			4.3			--

 

Revenues from oil and gas sales comprised 99% of our total revenues for the second quarter of 1999 as compared to 96% for the second quarter of 1998. Our acquisition of interests in the Masters Creek and Brookeland Fields, which have a higher percentage of production from oil, has decreased the predominance of gas in our production mix from 84% in the second quarter of 1998 to 63% in the second quarter of 1999. Due to the decrease in the 1999 capital expenditures budget, and the resulting curtailment of new drilling in the Giddings Field, the natural production decline in this field was not offset by newly developed production.

 The following table provides additional information regarding our oil and gas sales:

	Net Sales Volume		Average Sales Price
	Oil (Bbl)	Gas (Mcf)	Oil (Bbl)	Gas (Mcf)
	-----------	-----------	-----------	-----------
1998:
3 MONTHS ENDED 6/30/98	190,225	6,159,255	$11.20	$2.20
1999:
3 MONTHS ENDED 6/30/99	644,323	6,688,316	$15.25	$2.05

 

Costs and Expenses. Our general and administrative expenses for the second quarter of 1999 increased approximately $0.3 million, when compared to the same period in 1998. However, our general and administrative expenses per Mcfe produced decreased by 7% from $0.12 per Mcfe for the second quarter of 1998 to $0.11 per Mcfe for the comparable period