SWIFT ENERGY COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED September 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 September 30,			Nine months ended September 30,
	1999	1998		1999	1998
	----------------	----------------		----------------	----------------
Revenues:
Oil and gas sales	$      30,737,150	$      23,859,065		$     75,405,571	$     55,341,980
Fees from limited partnerships and joint ventures	92,737	93,062		192,386	297,941
Interest income	243,998	32,636		267,280	95,511
Other, net	205,410	572,790		830,879	1,638,080
	----------------	----------------		----------------	----------------
	31,279,295	24,557,553		76,696,116	57,373,512
	----------------	----------------		----------------	----------------
Costs and Expenses:
General and administrative, net	1,053,655	1,058,652		3,347,941	2,939,076
Depreciation, depletion, and amortization	10,403,262	13,347,786		31,630,013	27,333,026
Oil and gas production	5,138,138	4,045,160		13,689,086	8,920,157
Interest expense, net	3,749,414	2,385,626		10,402,426	5,355,269
Write-down of oil and gas properties	---	90,772,628		---	90,772,628
	----------------	----------------		----------------	----------------
	20,344,469	111,609,852		59,069,466	135,320,156
	----------------	----------------		----------------	----------------
Income (Loss) before Income Taxes	10,934,826	(87,052,299)		17,626,650	(77,946,644)
Provision (Benefit) for Income Taxes	3,827,189	(29,621,284)		6,085,231	(26,641,714)
	----------------	----------------		----------------	----------------
Net Income (Loss)	$      7,107,637	$     (57,431,015)		$     11,541,419	$     (51,304,930)
	===========	===========		===========	===========
Per share amounts-
Basic:	$               0.37	$               (3.50)		$               0.67	$                (3.11)
	===========	===========		===========	===========
Diluted:	$               0.36	$                 (3.50)		$               0.67	$                (3.11)
	===========	===========		===========	===========
Weighted Average Shares Outstanding	19,069,848	16,419,022		17,125,937	16,481,382
	===========	===========		===========	===========

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 September 30,
	1999	1998
	-----------------	-----------------
Cash Flows from Operating Activities:
Net income (loss)	$ 11,541,419	$ (51,304,930)
Adjustments to reconcile net income to net cash provided
by operating activities -
Depreciation, depletion, and amortization	31,630,013	27,333,026
Write-down of oil and gas properties	---	90,772,628
Deferred income taxes	5,787,938	(26,991,760)
Deferred revenue amortization related to production
payment	(806,950)	(948,040)
Other	422,196	355,942
Change in assets and liabilities -
Increase in accounts receivable	(3,245,871)	(4,170,800)
Increase in accounts payable and accrued
liabilities, excluding income taxes payable	2,930,390	2,713,583
Increase in income taxes payable	304,628	313,860
	-----------------	-----------------
Net Cash Provided by Operating Activities	48,563,763	38,073,509
	-----------------	-----------------
Cash Flows From Investing Activities:
Additions to property and equipment	(34,907,498)	(170,942,213)
Proceeds from the sale of property and equipment	3,914,578	1,294,383
Net cash received (distributed) as operator
of oil and gas properties	4,177,050	(11,210,890)
Net cash received (distributed) as operator
of partnerships and joint ventures	4,261,642	1,706,423
Limited partnership formation and marketing costs	(855,632)	(407,957)
Other	(326,799)	(95,752)
	-----------------	-----------------
Net Cash Used in Investing Activities	(23,736,659)	(179,656,006)
	-----------------	-----------------
Cash Flows From Financing Activities:
Proceeds from senior subordinated notes	124,054,369	---
Net proceeds from (payments of) bank borrowings	(146,200,000)	143,585,000
Net proceeds from issuances of common stock	42,794,224	1,192,811
Purchase of treasury stock	(1,462,740)	(3,050,459)
Payments of debt issuance costs	(3,501,441)	(540,671)
	-----------------	-----------------
Net Cash Provided by Financing Activities	15,684,412	141,186,681
	-----------------	-----------------
Net Increase (Decrease) in Cash and Cash Equivalents	40,511,516	(395,816)
Cash and Cash Equivalents at Beginning of Period	1,630,649	2,047,332
	-----------------	-----------------
Cash and Cash Equivalents at End of Period	$42,142,165	$1,651,516
	==========	==========
Supplemental disclosures of cash flow information:
Cash paid during period for interest, net of amounts capitalized	$6,180,930	$3,292,789
Cash paid during period for income taxes	$     ---	$     36,186

See accompanying notes to condensed consolidated financial statements.

SWIFT ENERGY COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 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.

 

At the end of each quarterly reporting period, the unamortized cost of oil and gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using current period-end prices, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“Ceiling Test”). This calculation is done on a country-by-country basis for those countries with proved reserves. Currently, the Company has proved reserves in the United States only.

 

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. Any impairment assessed is added to the cost of proved properties being amortized and is therefore subject to the Ceiling Test. Because our international initiatives have not yet resulted in the discovery of any proved reserves, 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 determined by management will be charged to income. In determining whether such costs should be impaired, our management evaluates, among other factors, the results of drilling, 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 September 30, 1999 totaled approximately $803,200 with benefits of approximately $348,400 having been received, resulting in a net cash outflow of approximately $454,800, or $0.011 per Mcfe. The costs related to open contracts as of September 30, 1999 totaled approximately $106,500, which is our maximum exposure under these contracts. These open contracts had a fair market value of $9,000 at September 30, 1999.

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.

 

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 except for the three month period ended September 30, 1999. The following is a reconciliation of the calculation of Basic and Diluted EPS for the three-month and nine-month periods ended September 30, 1999:

	Three Months Ended September 30, 1999
	Net Income		Shares		Per Share Amount
	---------		---------		--------
Basic EPS:
Net Income and Share Amounts	$7,107,637		19,069,848		$.37
Dilutive Securities:
Convertible Notes	1,230,527		3,646,847
Stock Options	---		222,286
	---------------		----------		---------
Diluted EPS:
Net Income and Assumed Share   Conversions	$8,338,164		22,938,981		$.36
	======		======		======

 

	Nine Months Ended September 30, 1999
	Net Income		Shares		Per Share Amount
	---------		---------		--------
Basic EPS:
Net Income and Share Amounts	$11,541,419		17,125,937		$.67
Dilutive Securities:
Convertible Notes(1)	3,715,567		3,646,847
Stock Options(1)	---		222,286
	---------------		----------		---------
Diluted EPS:
Net Income and Assumed Share   Conversions	$15,256,986		20,995,070		$.67
	======		======		======

(1) The convertible notes and the stock options are antidilutive in this period.

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) LONG-TERM DEBT

 

Under our $250.0 million revolving credit facility with a syndicate of ten banks, at September 30, 1999, we had no outstanding borrowings, as previous borrowings had been paid in full during August with proceeds from our third quarter concurrent public offerings of senior subordinated notes and common stock. At December 31, 1998, we had outstanding borrowings of $146.2 million under our borrowing arrangements. At September 30, 1999, the credit facility consisted of a $250.0 million revolving line of credit with a $140 million borrowing base. The interest rate is either (a) the lead bank’s prime rate (8.25% at September 30, 1999) or (b) the adjusted London Interbank Offered Rate ("LIBOR") plus the applicable margin depending on the level of outstanding debt. The applicable margin is based on our ratio of outstanding balance on the credit facility to the last calculated borrowing base.

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 is currently under its November review which had not been completed as of the date of this report. We have requested that the credit facility be reduced from $250.0 million to $225.0 million and for the $140.0 million borrowing base to be reduced to $100.0 million. The reduction in the borrowing base was requested in order to reduce the amount of commitment fees paid on this facility. By its terms, the credit facility extends until August 2002.

The Company’s convertible notes at September 30, 1999 consist of $115,000,000 of 6.25% Convertible Subordinated Notes due 2006. The notes were issued on November 25, 1996, and will mature on November 15, 2006. The notes are unsecured and convertible into common stock of the Company at the option of the holders at any time prior to maturity at an adjusted conversion price of $31.534 per share, subject to adjustment upon the occurrence of certain events. The original conversion price of $34.6875 was adjusted downward to reflect the October 1997 10% stock dividend. Interest on the notes is payable semiannually on May 15 and November 15, and commenced with the first payment on May 15, 1997. On or after November 15, 1999, the notes are redeemable for cash at the option of the Company, with certain restrictions, at 104.375% of principal, declining to 100.625% in 2005. Upon certain changes in control of the Company, if the price of the Company’s common stock is not above certain levels, each holder of notes will have the right to require the Company to repurchase the notes at 101% of the principal amount thereof, together with accrued and unpaid interest to the date of repurchase, but after the repayment of any Senior Indebtedness, as defined.

The Company’s senior notes at September 30, 1999 consist of $125,000,000 of 10.25% Senior Subordinated Notes due 2009. The notes were issued at 99.236% of the principal amount on August 4, 1999, and will mature on August 1, 2009. The notes are unsecured senior subordinated obligations and are subordinated in right of payment to all our existing and future senior debt, including our bank debt. Interest on the notes is payable semiannually on February 1 and August 1, and commences with the first payment on February 1, 2000. On or after August 1, 2004, the notes are redeemable for cash at the option of Swift, with certain restrictions, at 105.125% of principal, declining to 100% in 2007. In addition, prior to August 1, 2002, we may redeem up to 33.33% of the notes with the proceeds of qualified offerings of our equity at 110.25% of the principal amount of the notes, together with accrued and unpaid interest. Upon certain changes in control of the Company, each holder of notes will have the right to require the Company to repurchase the notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase.

(4) STOCKHOLDERS' EQUITY

 

In August of 1999, we sold 4.6 million shares of common stock in a public offering for $9.75 per share, with net proceeds of approximately $42.1 million.

(5) ACQUISITION OF PROPERTIES

 

We purchased oil and gas interests in the Brookeland and Masters Creek Fields from Sonat Exploration Company in the third quarter of 1998 for approximately $85.5 million in cash. Of this purchase price, $55.2 million was allocated to producing properties, $15.0 million to 20% interests in two natural gas processing plants, and $15.3 million to 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 17.5 Bcfe in the first nine 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:

		Nine months ended September 30, 1998
(Thousands, except per share amounts)		(Unaudited)
Revenue		$90,299
Net Income Before Non-Cash Charge		$16,017
Net Loss		$(43,893)
Per Share Amounts--
Basic		$(2.66)
Diluted		$(2.66)

(6) FOREIGN ACTIVITIES

 

New Zealand. Since October 1995, the New Zealand Minister of Energy has issued to 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. On October 18, 1999, this expanded permit was again extended to include approximately 12,800 adjacent offshore acres. This permit now contains approximately 100,700 acres. Under the terms of the expanded permit, we were required to commence drilling one exploratory well prior to August 12, 1999.

We spudded an exploratory well in July which has been drilled to its total depth. While drilling, hydrocarbon shows were encountered and further evaluation of the well will be done through production tests. The production tests are expected to commence in mid- November. Our portion of the drilling costs incurred at September 30, 1999 are approximately $4.6 million. We expect to conclude the production tests of this well during the fourth quarter of 1999, with our portion of such costs estimated to be $1.4 million. Should this exploratory well fail to discover economic reserves, in the fourth quarter of 1999 we would be required to charge against earnings the drilling costs plus a portion of the capitalized costs in the unproved properties portion of oil and gas properties, with the estimated potential aggregate impairment currently estimated to total up to $7.5 million. 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, under which we obtained from Marabella a 25% working interest in another New Zealand petroleum exploration permit and under which Marabella became 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 17.5% working interest owner. Additionally, Swift obtained a 7.5% working interest in another New Zealand permit from Antrim Oil and Gas Limited, a Canadian company, and Antrim became a 5% participant in our permit. An exploratory well was drilled and temporarily abandoned on Antrim’s permit during the second quarter of 1999, and we charged our $290,000 portion of the costs on this well against earnings in that quarter. As of September 30, 1999, our investment in New Zealand totaled approximately $9.1 million. We have included these costs in the unproved properties portion of oil and gas properties.

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, and 1998, 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 nine months of 1999, we relied upon our internally generated cash flows of $48.6 million to fund capital expenditures of $34.9 million. We expect internally generated cash flows, together with the remaining net proceeds of approximately $26.6 million from our third quarter public sale of senior notes and common stock, to provide cash and working capital through 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 nine months of 1999, net cash provided by our operating activities increased by 28% to $48.6 million, as compared to $38.1 million during the first nine months a year earlier. The 1999 increase of $10.5 million was primarily due to $20.1 million of additional oil and gas sales. However, this increase was substantially offset by the $4.8 million increase in oil and gas production costs and the $5.0 million increase in interest expense.

Financing Activities. In August 1999, in two concurrent public offerings, we sold $125.0 million of  10.25% Senior Subordinated Notes and 4.6 million shares of common stock for $44.9 million. The notes were issued at 99.236% of the principal amount on August 4, 1999, and will mature on August 1, 2009. Proceeds from the two offerings were used to repay all of our bank borrowings ($136.0 million on August 4, 1999). The remainder of the proceeds will be used, together with internally generated cash flows, to fund capital expenditures and working capital needs through 1999. The principal terms of these notes are more fully described in Note 3 to our condensed consolidated financial statements.

Credit Facility. At September 30, 1999, we had no outstanding borrowings under our credit facility. At December 31, 1998, we had outstanding borrowings of $146.2 million under that facility. At September 30, 1999, our credit facility consists of a $250.0 million revolving line of credit with a $140.0 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 credit facility extends until August 18, 2002. Our $115.0 million convertible notes mature November 15, 2006. Our $125.0 million senior notes mature August 1, 2009.

 

Working Capital. Our working capital increased from $3.8 million at December 31, 1998, to $36.6 million at September 30, 1999, primarily due to $26.6 million of remaining proceeds from our third quarter 1999 public offerings of common stock and senior notes, and due to our internally generated funds exceeding our capital expenditures during that period.

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 770 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 common stock held as treasury stock to fund our employer liability in the 401(k) program for our employees.

 

Capital Expenditures. During the first nine months of 1999, we used $34.9 million to fund capital expenditures for property, plant, and equipment. These capital expenditures included:

• $25.0 million for drilling costs, both development and exploratory;
• $8.8 million of domestic prospect costs, principally prospect leasehold, seismic and geological costs of unproved prospects for our account;
• $0.7 million invested in New Zealand; and
• $0.4 million spent primarily for computer equipment, software and furniture and fixtures.  

In the remaining three months of 1999, we expect to spend approximately $30.0 million on capital expenditures, including investments in all areas in which investments were made during the first nine months of the year as described above. Eighteen wells were drilled in the first nine months of 1999, and thirteen were successful. Twelve of the successful wells were development wells. For the remaining three months of 1999, we anticipate drilling an additional 13 wells, made up of 11 development wells and two exploratory wells. We estimate capital expenditures for 1999 to be approximately $65 million, an increase from the original 1999 budget of $54 million, but still substantially lower than budgets in prior years. This upward adjustment in the 1999 capital expenditures budget is in response to the recent improvement in commodity prices. Approximately $50 million of the revised 1999 budget is allocated to drilling, primarily in our core fields. The remaining $15 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 the unspent proceeds from our third quarter financing activities, will be sufficient to finance the costs associated with our currently budgeted remaining 1999 capital expenditures. We anticipate that our 2000 capital expenditures budget will be in excess of the revised 1999 budget, also in response to the recent improvements in commodity prices.

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

 

Revenues. Our revenues increased 27% during the third 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 55% increase in oil prices received and the 48% increase in gas prices received.

 

Oil and Gas Sales. Our oil and gas sales increased 29% to $30.7 million in the third quarter of 1999, compared to $23.9 million for the comparable period in 1998. Our natural gas production decreased 15% and oil production decreased 12% resulting in a 14%, or 1.7 Bcfe, decrease over volumes in the same period in 1998. These volume decreases were more than offset by the increased prices received. The decrease in production volumes resulted primarily from our decision to reduce development drilling during the latter part of 1998 and the first half of 1999 due to low oil and gas prices. Additionally, several new Masters Creek wells, with their high initial rates of production, were placed into production last year during the third quarter.

Our $6.8 million increase in oil and gas sales during the third quarter of 1999 resulted from:

• Price increases which had a favorable impact on sales of $10.2 million, with $6.2 million of the increase coming from the increase in average gas prices received and $4.0 million coming from the increase in average oil prices received; offset by
• Volume decreases which had an unfavorable impact on sales of $3.4 million, with $2.4 million of the decrease coming from the 1.2 Bcf decrease in gas sales volumes and $1.0 million of the decrease coming from the 83,000 barrel decrease in oil sales volumes.

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

Field		Revenues (In Millions)				Net Sales Volumes (Bcfe)
		1999		1998		1999		1998
AWP Olmos		$8.8		$8.5		3.2		4.1
Brookeland		$4.3		$3.7		1.3		1.8
Giddings		$2.5		$2.7		0.9		1.6
Masters Creek		$13.2		$8.2		4.1		3.8

 

Due to the decrease in the 1999 capital expenditures budget, and the resulting curtailment of drilling, the natural production decline in three of these fields was not offset by newly developed production.

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