Of the $45,902,357 of domestic unproved property costs (primarily seismic and lease acquisition costs) at December 31, 1999, excluded from the amortizable base, $10,367,938 was incurred in 1999, $25,271,433 was incurred in 1998, $5,540,914 was incurred in 1997, and $4,722,072 was incurred in prior years. When we are in an active drilling mode, we evaluate the majority of these unproved costs within a two to three year time frame. In response to past market conditions, we decreased our 1999 drilling expenditures when compared to recent years, which when coupled with the $15.3 million of leasehold properties acquired in the Brookeland and Masters Creek Fields acquisition in 1998, may extend the evaluation timeframe of such costs.

Of the $11,760,382 of net foreign unproved property costs at December 31, 1999, being excluded from the amortizable base, $6,758,874 was incurred in 1999, $2,521,761 was incurred in 1998, $1,731,561 was incurred in 1997, and $748,186 was incurred in prior years. All of these costs were incurred in New Zealand, as the costs incurred in Russia and Venezuela were impaired in the third quarter of 1998 (see Note 1 to the Consolidated Financial Statements). We expect to complete our evaluation of the New Zealand well drilled during the second half of 1999 by early 2000. For the remaining New Zealand properties, we expect to complete our evaluation over the next two to three years.

Costs Incurred. The following table sets forth costs incurred related to our oil and gas operations:

	Year Ended December 31,
	1999	1998	1997
	-----------------	-----------------	-----------------
Acquisition of proved properties	$ 18,526,939	$ 59,487,524	$ 8,417,318
Lease acquisitions1,2	10,382,672	38,658,047	21,603,732
Exploration3	11,019,430	12,578,124	10,705,115
Development	39,891,868	54,821,131	82,885,549
	-----------------	-----------------	-----------------
Total acquisition, exploration, and development4	$ 79,820,909	$ 165,544,826	$ 123,611,714
	-----------------	-----------------	-----------------
Processing plants	$1,607,559	$15,000,000	$                   ---
Field compression facilities	171,535	2,228,101	7,444,070
	-----------------	-----------------	-----------------
Total plants and facilities	$1,779,094	$17,228,101	$7,444,070
	-----------------	-----------------	-----------------
Total costs incurred	$81,600,003	$182,772,927	$131,055,784
	==========	==========	==========

¹Lease acquisitions for 1999, 1998, and 1997 include expenditures of $1,131,014, $464,274, and $1,731,561, respectively, relating to our initiatives in New Zealand. Lease acquisitions for 1998 and 1997 include expenditures of $421,602 and $828,133, respectively, relating to initiatives in Venezuela; and $592,841 and $658,145, respectively, relating to initiatives in Russia.

²These are actual amounts as incurred by year, including both proved and unproved lease costs. The annual lease acquisition amounts added to proved oil and gas properties (being amortized) for 1999, 1998, and 1997 were $16,020,693, $13,853,129 and $7,384,385, respectively.

³Exploration for 1999 and 1998 include $5,918,100 and $2,057,487, respectively, relating to New Zealand.

⁴Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $8,500,000, $12,300,000, and $11,700,000 in 1999, 1998, and 1997, respectively. In addition, total includes $4,142,098, $3,849,665, and $2,326,691 in 1999, 1998, and 1997, respectively, of capitalized interest on unproved properties.

 

Results of Operations. The following table sets forth results of our oil and gas operations:

	Year Ended December 31,
	1999	1998	1997
	---------------------	---------------------	---------------------
Oil and gas sales	$ 108,898,696	$ 80,067,837	$ 69,015,189
Oil and gas production costs	(19,645,740)	(13,138,980)	(8,778,876)
Depreciation and depletion	(41,410,106)	(38,490,222)	(23,443,273)
Write-down of oil and gas properties	---	(90,772,628)	---
	---------------------	---------------------	---------------------
	47,842,850	(62,333,993)	36,793,040
Provision (benefit) for income taxes	16,792,840	(21,380,560)	12,015,816
	---------------------	---------------------	---------------------
Results of producing activities	$ 31,050,010	$ (40,953,433)	$ 24,777,224
	===========	===========	===========
Amortization per physical unit of production
(equivalent Mcf of gas)	$0.97	$ 0.99	$ 0.92
	===========	===========	===========

 

Supplemental Reserve Information. The following information presents estimates of our proved oil and gas reserves, which are all located onshore in the United States. All of our reserves were determined by us and audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent petroleum consultants. Gruy’s report dated February 9, 2000, is set forth as an exhibit to the Form 10-K Report for the year ended December 31, 1999, and should be referred to in connection with the following information:

Estimates of Proved Reserves
		Oil and
	Natural Gas	Condensate
	(Mcf)	(Bbls)
	-------------------	-------------------
Proved reserves as of December 31, 19961	225,758,201	5,484,309
Revisions of previous estimates2	(22,774,899)	(427,412)
Purchases of minerals in place	30,342,398	580,278
Sales of minerals in place	(1,155,706)	(50,909)
Extensions, discoveries, and other additions	102,479,883	2,945,037
Production3	(20,344,208)	(672,385)
	-------------------	-------------------
Proved reserves as of December 31, 19971	314,305,669	7,858,918
Revisions of previous estimates2	(42,958,447)	(2,291,223)
Purchases of minerals in place	54,189,901	7,237,298
Sales of minerals in place	(1,727,878)	(39,932)
Extensions, discoveries, and other additions	55,951,332	2,993,540
Production3	(27,359,742)	(1,800,676)
	-------------------	-------------------
Proved reserves as of December 31, 19981	352,400,835	13,957,925
Revisions of previous estimates2	(31,189,451)	2,058,725
Purchases of minerals in place	9,159,780	1,822,858
Sales of minerals in place	(3,762,799)	(260,287)
Extensions, discoveries, and other additions	30,107,908	5,791,966
Production3	(26,756,524)	(2,564,924)
	-------------------	-------------------
Proved reserves as of December 31, 19991	329,959,749	20,806,263
	==========	==========
Proved developed reserves,
December 31, 1996	135,424,880	3,622,480
December 31, 1997	191,108,214	4,288,696
December 31, 1998	197,105,963	7,142,566
December 31, 1999	174,046,096	8,437,299

¹Proved reserves exclude quantities subject to our volumetric production payment agreement.

²Revisions of previous estimates are related to upward or downward variations based on current engineering information for production rates, volumetrics, and reservoir pressure. Additionally, changes in quantity estimates are affected by the increase or decrease in crude oil and natural gas prices at each year-end. Proved reserves, as of December 31, 1999, were based upon prices in effect at year-end. The weighted average of such year-end prices were $2.58 per Mcf of natural gas and $23.69 per barrel of oil, compared to $2.23 per Mcf and $11.23 per barrel as of December 31, 1998.

³Natural gas production for 1997, 1998, and 1999 excludes 1,015,226, 866,232, and 728,235 Mcf, respectively, delivered under our volumetric production payment agreement.

 

Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:

	Year Ended December 31,
	1999	1998	1997
	------------------------	------------------------	------------------------
Future gross revenues	$ 1,371,541,850	$ 972,852,038	$ 994,828,072
Future production costs	(353,594,258)	(294,307,549)	(273,475,056)
Future development costs	(156,738,446)	(118,420,782)	(92,946,811)
	------------------------	------------------------	------------------------
Future net cash flows before income taxes	861,209,146	560,123,707	628,406,205
Future income taxes	(226,725,033)	(123,875,660)	(135,587,216)
	------------------------	------------------------	------------------------
Future net cash flows after income taxes	634,484,113	436,248,047	492,818,989
Discount at 10% per annum	(195,540,279)	(145,974,944)	(199,980,649)
	------------------------	------------------------	------------------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves	$ 438,943,834	$ 290,273,103	$ 292,838,340
	============	============	============

 

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

1. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.

2. The estimated future gross revenues of proved reserves are priced on the basis of year-end prices, except in those instances where fixed and determinable gas price escalations are covered by contracts limited to the price we reasonably expect to receive.

3. The future gross revenue streams are reduced by estimated future costs to develop and to produce the proved reserves, as well as certain abandonment costs based on year-end cost estimates and the estimated effect of future income taxes.

4. Future income taxes are computed by applying the statutory tax rate to future net cash flows reduced by the tax basis of the properties, the estimated permanent differences applicable to future oil and gas producing activities, and tax carry forwards.

The estimates of cash flows and reserves quantities shown above are based on year-end oil and gas prices for each period. Under Securities and Exchange Commission rules, companies that follow the full-cost accounting method are required to make quarterly Ceiling Test calculations, using prices in effect as of the period end date presented (see Note 1 to the Consolidated Financial Statements). Application of these rules during periods of relatively low oil and gas prices, even if of short-term seasonal duration, may result in write-downs.

The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and gas property reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment, and the risks inherent in reserve estimates.

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

	Year Ended December 31,
	1999	1998	1997
	------------------------	------------------------	------------------------
Beginning balance	$ 290,273,103	$ 292,838,340	$ 367,232,302
	------------------------	------------------------	------------------------
Revisions to reserves proved in prior years--
Net changes in prices, production costs, and future
development costs	123,447,890	(107,301,930)	(237,149,170)
Net changes due to revisions in quantity estimates	(23,746,974)	(47,924,995)	(27,188,512)
Accretion of discount	34,078,501	35,034,478	47,068,172
Other	2,032,696	(34,966,058)	(37,336,420)
	------------------------	------------------------	------------------------
Total revisions	135,812,113	(155,158,505)	(254,605,930)
New field discoveries and extensions, net of future
production and development costs	102,582,467	73,956,430	110,396,029
Purchases of minerals in place	39,282,292	87,628,829	29,290,334
Sales of minerals in place	(5,360,428)	(1,928,900)	(2,373,547)
Sales of oil and gas produced, net of production costs	(88,196,672)	(65,680,050)	(58,786,505)
Previously estimated development costs incurred	39,149,732	51,622,419	55,742,684
Net change in income taxes	(74,598,773)	6,994,540	45,942,973
	------------------------	------------------------	------------------------
Net change in standardized measure of discounted
future net cash flows	148,670,731	(2,565,237)	(74,393,962)
	------------------------	------------------------	------------------------
Ending balance	$ 438,943,834	$ 290,273,103	$ 292,838,340
	==============	==============	==============

 

Quarterly Results. The following table presents summarized quarterly financial information for the years ended December 31, 1998 and 1999:

			Income (Loss)				Basic Earnings		Diluted Earnings
			Before		Net Income		(Loss)		(Loss)
	Revenues		Income Taxes		(Loss)		Per Share		Per Share
	-----------------		-------------------		-----------------		-----------------		-----------------
1998
First Quarter	$ 16,475,229		$ 4,835,502		$ 3,229,615		$         0.20		$          0.20
Second Quarter	16,340,730		4,270,153		2,896,470		0.18		0.18
Third Quarter1	24,557,553		(87,052,299)		(57,431,015)		(3.50)		(3.50)
Fourth Quarter	25,095,709		4,555,063		3,079,726		0.19		0.19
	-----------------		-----------------		-----------------
Total	$ 82,469,221		$ (73,391,581)		$ (48,225,204)		$    (2.93)		$    (2.93)
1999
First Quarter	$ 21,488,087		$ 1,905,419		$ 1,281,755		$          0.08		$          0.08
Second Quarter	23,928,734		4,786,405		3,152,027		0.20		0.20
Third Quarter	31,279,295		10,934,826		7,107,637		0.37		0.36
Fourth Quarter	33,974,891		12,109,501		7,745,155		0.37		0.36
	-----------------		-----------------		-----------------
Total	$ 110,671,007		$ 29,736,151		$ 19,286,574		$    1.07		$     1.07
	==========		==========		==========

¹The loss in the third quarter of 1998 was the result of a pre-tax write-down of oil and gas properties of $90.8 million ($59.9 million after tax). See Note 1 to the Consolidated Financial Statements.

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