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FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 2003

Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations

 

The following discussion and analysis supplements and is provided to facilitate increased understanding of our 2003, 2002 and 2001 consolidated financial statements and our accompanying notes included with this report.

Overview

 

For 2003, Swift Energy experienced record revenues of $209 million and record production of 53.2 Bcfe. Our revenues were bolstered by oil and gas prices remaining strong last year. Although 2003 domestic production decreased by 1% to 33.8 Bcfe from 2002 levels we continued to focus our efforts and capital throughout the year on better infrastructure, increased production and the development of longer life oil reserves in the Lake Washington area. In January 2004, we produced more than approximately 12,000 gross barrels of oil equivalent per day (approximately 10,000 net barrels of oil equivalent per day) in Lake Washington, compared to approximately 5,000 gross barrels of oil equivalent per day (approximately 4,100 net barrels of oil equivalent per day) in January 2003. During 2003, we also began allocating capital to natural gas development in our three other domestic core areas. New Zealand accounted for 19.4 Bcfe of 2003 production, a 25% increase from 2002 levels. New Zealand natural gas and NGL contracts are denominated in New Zealand Dollars, which have significantly strengthened during 2003 against the U.S. Dollar. The currency exchange rate increased from approximately $0.52 to approximately $0.66 U.S. per $1.00 New Zealand during the year.

Our production costs were up in 2003 predominately due to some of the facility enhancement costs and increased activity and production in Lake Washington, increased severance taxes, and also due to currency exchange rates in New Zealand. Our average reserve replacement cost for 2003 was $1.17 per Mcfe, and we replaced 234% of our 2003 production. Our general and administrative expenses increased in 2003 predominantly due to our increased activities in New Zealand, a reduction in reimbursement from partnerships we managed, an increase in franchise tax expense, and increased costs related to our corporate governance activities and compliance with the Sarbanes-Oxley Act. We are working to reduce our production costs for 2004.

We again made significant strides in 2003 in improving the quality and quantity of our reserve base in accordance with our strategic plan. Year-end 2003 proved reserves of 820.4 Bcfe, representing 9.5% growth for the year, were 47% crude oil, 41% natural gas and 12% NGLs, compared to year-end 2002 proved reserves of 749.4 Bcfe, which were 42% crude oil, 44% natural gas and 14% NGLs. Proved developed reserves remained essentially the same at 59% of total reserves at year-end 2003, compared to 60% the previous year. Domestic proved reserves increased at year-end 2003 to 644.4 Bcfe, driven mainly by the reserve increase in the Lake Washington Field. Proved reserves in New Zealand increased to 176.0 Bcfe at year-end 2003, primarily attributable to drilling additions in the Kauri and Manutahi Sands. For 2003, our proved undeveloped reserves, 41% of total reserves, were slightly higher than the 30% to 40% range we had targeted. Most of these proved undeveloped reserves were in the Lake Washington area (13% of total reserves) and in the AWP Olmos area (9% of total reserves), and both areas are characterized as long reserve life fields. The 30% to 40% range is again our target for 2004 as we work to convert proved undeveloped reserves into proved producing reserves.

Our debt to PV-10 ratio has decreased from 43% in 2001 to 28% in 2002, and further decreased to 22% for 2003. Our debt to capitalization ratio was 46% at December 31, 2003, which is essentially the same as at year-end 2002, and 2001. Management continues to believe that our current cash flow is best utilized on capital projects rather than reducing debt. However, we will continue to look for opportunities in 2004 to improve our balance sheet and liquidity but expect our capital expenditures to continue to equal or modestly exceed our cash flow for the near term.

Our 2004 capital expenditure budget assumes increased drilling activity in all domestic core areas except Lake Washington. For Lake Washington, the 2004 budget assumes reduced drilling activity, 25 to 30 wells, accompanied by an extensive three-dimensional seismic survey, together with the analysis of the resulting data, to enhance our drilling program in the area for years to come. We plan to drill 15 to 18 wells in AWP Olmos, with the objective of again maintaining production levels in that area. Additionally, we expect to have ongoing exploratory efforts in our South Texas Garcia Ranch properties. In New Zealand, we plan to drill 8 to 12 wells, primarily in the areas in which we had success in 2003. We continue to see a tightening natural gas market with strengthening gas prices in New Zealand. For 2004, we believe we are positioned for production growth of 11% to 17% and reserve growth of 5% to 8%, and expect commodity prices to remain strong.

Results of Operations

Revenues. Our revenues in 2003 increased by 39% compared to revenues in 2002, due primarily to increases in oil and gas prices and production from our New Zealand and Lake Washington areas. Revenues in 2002 decreased by 18% compared to 2001 revenues primarily due to the drop in domestic natural gas prices in 2002. Revenues from our oil and gas sales comprised substantially all of net revenues for 2003, 94% of total revenues for 2002, and 99% for 2001. Natural gas production made up 53% of our production volumes in 2003, 55% in 2002, and 59% in 2001. Domestic natural gas production made up 49% of our total natural gas production volumes in 2003, 58% in 2002, and 100% in 2001.

Oil and gas sales in 2003 increased by 49%, or $69.8 million, from the level of those revenues for 2002, and our net sales volumes in 2003 increased by 7%, or 3.4 Bcfe, over net sales volumes in 2002. Average prices received for oil increased to $29.89 per Bbl in 2003 from $24.52 per Bbl in 2002. Average gas prices received increased to $3.42 per Mcf in 2003 from $2.30 per Mcf in 2002. Average NGL prices received increased to $17.60 per Bbl in 2003 from $12.82 per Bbl in 2002. The increase in production during the 2003 period was primarily from our New Zealand and Lake Washington areas.

In 2003, our $69.8 million increase in oil, NGL, and gas sales resulted from:

•Price variances that had a $59.0 million favorable impact on sales, of which $31.4 million was attributable to the 49% increase in average gas prices received and $27.6 million was attributable to the 32% increase in average combined oil and NGL prices received; and

•Volume variances that had a $10.8 million favorable impact on sales, with $8.8 million of increases coming from the 422,000 Bbl increase in oil and NGL sales volumes, and $2.0 million of the increases from the 0.9 Bcf increase in gas sales volumes.

In 2002, oil and gas sales decreased by 22%, or $40.0 million, from the level of those revenues in 2001 even though our net sales volumes in 2002 increased by 11%, or 5.0 Bcfe, over net sales volumes in 2001. Average combined prices received for oil and NGLs decreased to $20.88 per Bbl in 2002 from $22.64 per Bbl in 2001. Average gas prices received decreased to $2.30 per Mcf in 2002 from $4.23 per Mcf in 2001. The increase in production during the 2002 period was primarily from our New Zealand and Lake Washington areas.

In 2002, our $40.0 million decrease in oil, NGL, and gas sales resulted from:

•Price variances that had a $59.0 million unfavorable impact on sales, of which $6.6 million was attributable to the 8% decrease in average combined oil and NGL prices received and $52.4 million was attributable to the 46% decrease in average gas prices received; and

• Volume variances that had a $19.0 million favorable impact on sales, with $16.2 million of increases coming from the 715,000 Bbl increase in oil and NGL sales volumes, and $2.8 million of the increases from the 0.7 Bcf increase in gas sales volumes.

 

 

The following table provides additional information regarding the changes in the sources of our oil and gas sales and volumes from our four domestic core areas and two New Zealand core areas:

Oil and Gas Sales       Net Oil and Gas 

Sales Volume
(in millions) (Bcfe)
Area 2003 2002 2003 2002
-------- -------- ------- -------
AWP Olmos  $43.7 $33.1 8.4 10.9
Brookeland 16.4 11.9 3.9 4.1
Lake Washington  59.5 18.5 12.1 4.4
Masters Creek 25.7 32.3

5.7

9.7
Other  18.9 16.3 3.7 5.2
    -------- -------- -------- --------
   Total Domestic $ 164.2 $ 112.1 33.8 34.3
Rimu/Kauri 11.6 4.0 3.3 1.5
TAWN 35.2 25.1 16.1 14.0
----------- ----------- ---------- ----------
Total New Zealand $46.8 $29.1 19.4 15.5
----------- ----------- ---------- ----------
Total $211.0 $141.2 53.2 49.8

 

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

Net Oil and Gas Sales Volume

Average Sales Price
---------------------------------------------- -------------------------------
Oil and Oil and
NGLs Gas Combined NGLs Gas
(MBbl) (Bcf) (Bcfe) (Bbl) (Mcf)
------- ------ --------- ---------- --------
2001:
First   603 6.7 10.3 $27.63 $6.86
Second 691 7.1 11.3 $26.05 $4.66
Third  813 6.8 11.7 $23.76 $2.94
Fourth  948 5.9 11.5 $16.02 $2.21
------- ------ ---------
3,055 26.5 44.8 $22.64 $4.23
------- ------ ---------
2002:
First  944 6.6 12.3 $16.10 $1.72
Second  1,002 6.7 12.7 $20.98 $2.60
Third  908 6.7 12.2 $23.05 $2.32
Fourth  916 7.1 12.6 $23.55 $2.55
------- ------ ---------
3,770 27.1 49.8 $20.88 $2.30
------- ------ ---------
2003:
First 

864

7.6

12.9

$30.55

$3.71
Second 

1,033

7.1

13.3

$25.48

$3.47
Third 

1,164

6.7

13.6

$26.60

$3.17
Fourth 

1,132

6.6

13.4

$27.84

$3.29
------- ------ ---------

4,193

28.0

53.2

$27.47

$3.42

------- ------ ---------

 

 

In the table above, for 2002 and 2003, natural gas liquids have been combined with oil for reporting purposes. Natural gas liquids production for 2002 was 1,174 MBbls, at an average price of $12.82 per barrel; and for 2003, was 823 MBbls, at an average price of $17.60 per barrel.

Costs and Expenses. Our expenses in 2003 increased $26.6 million, or 20%, compared to 2002 expenses. The majority of the increase was due to the $11.4 million increase in oil and gas production costs and the $6.8 million increase in depreciation, depletion and amortization, both of which increased as our production volumes increased in 2003. Our expenses in 2002 decreased by $86.4 million, or 40%, compared to 2001 expenses. This decrease was due primarily to the $98.9 million non-cash write-down of domestic oil and gas properties in 2001.

As discussed in Note 1 to the Consolidated Financial Statements, we adopted SFAS No. 143 on January 1, 2003. Our adoption of SFAS No. 143 resulted in a one-time net of taxes charge of $4.4 million, which is recorded as a “Cumulative Effect of Change in Accounting Principle” in the 2003 consolidated statement of income. We adopted SFAS No. 133, amended by SFAS No. 137 and SFAS No. 138, on January 1, 2001. Our adoption of SFAS No. 133 resulted in a one-time net of taxes charge of $0.4 million, which is recorded as a “Cumulative Effect of Change in Accounting Principle” in the 2001 consolidated statement of income.

Our 2003 general and administrative expenses, net increased $3.5 million, or 33%, from the level of such expenses in 2002, while 2002 general and administrative expenses increased $2.4 million, or 29%, over 2001 levels. These increases in 2002 and 2003 are due primarily to our increased activities in New Zealand and a reduction in reimbursement from partnerships we managed as almost all of these partnerships have liquidated. In addition, our 2003 expense increased due to an increase in franchise tax expense and increased costs related to our corporate governance activities and compliance with the Sarbanes-Oxley Act. Our general and administrative expenses per Mcfe produced increased to $0.27 per Mcfe in 2003 from $0.21 per Mcfe in 2002 and $0.18 per Mcfe in 2001. The portion of supervision fees recorded as a reduction to general and administrative expenses was $3.6 million for 2003, $3.2 million for 2002, and $3.5 million for 2001.

Depreciation, depletion, and amortization of our oil and gas properties, or DD&A, increased $6.8 million, or 12%, in 2003 from 2002 levels, while 2002 DD&A decreased $3.3 million, or 6%, from 2001 levels. Domestically, DD&A increased $1.0 million in 2003 due to increases in the depletable oil and gas property base, offset by slightly lower production in the 2003 period and higher reserve volumes that were added primarily through our Lake Washington activities. In New Zealand, DD&A increased by $5.8 million in 2003 due to increased production in the 2003 period. In 2002, our domestic DD&A decreased by $15.6 million due to lower production in the 2002 period and the domestic non-cash write-down of oil and gas properties in the fourth quarter of 2001 that decreased our depletable base, along with higher reserve volumes that were added primarily through our Lake Washington activities. In New Zealand, our 2002 DD&A increased $12.3 million as our production and the depletable oil and gas property base both increased in the 2002 period due primarily to the TAWN acquisition. Our DD&A rate per Mcfe of production was $1.19 in 2003, $1.13 in 2002, and $1.33 in 2001, reflecting variations in per unit cost of reserves additions.

We recorded $0.9 million of accretion on our asset retirement obligation in 2003 associated with the adoption of SFAS No. 143 implemented on January 1, 2003.

Our production costs per Mcfe produced were $0.99 in 2003, $0.83 in 2002, and $0.82 in 2001. The portion of supervision fees recorded as a reduction to production costs was $1.5 million for 2003, $2.1 million for 2002, and $3.3 million for 2001. Our production costs in 2003 increased $11.4 million, or 27%, over such expenses in 2002, while those expenses in 2002 increased $4.8 million, or 13%, over such expenses in 2001. Approximately $6.2 million of the increase in production costs during 2003 was related to domestic severance taxes, which increased along with commodity prices and higher production from our Lake Washington area in that period. In New Zealand, production costs increased by $5.2 million in 2003 mainly due to royalty payments made on higher production in the period. In 2002 production costs increased as our New Zealand activities increased, partially offsetting the domestic production costs decrease, which mainly was due to a decrease in production volumes.

Interest expense on our Senior Notes issued in April 2002, including amortization of debt issuance costs, totaled $19.1 million in 2003 and $13.5 million in 2002. Interest expense on our Senior Notes issued in July 1999, including amortization of debt issuance costs, totaled $13.2 million in both 2003 and 2002 and $13.1 million in 2001. Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $1.6 million in 2003, $3.6 million in 2002, and $5.8 million in 2001. Other interest cost was $0.3 million in 2003. The total interest cost in 2003 was $34.2 million, of which $6.9 million was capitalized. The total interest cost in 2002 was $30.3 million, of which $7.0 million was capitalized. The 2001 total interest cost was $18.9 million, of which $6.3 million was capitalized. We capitalize that portion of interest related to unproved properties. The increase in interest expense in 2003 and 2002 was attributed to the replacement of our bank borrowings in April 2002 with the Senior Notes issued in 2002 that carry a higher interest rate.

In the fourth quarter of 2001, we recognized a domestic non-cash write-down of oil and gas properties, as discussed in Note 1 to the Consolidated Financial Statements. Lower prices for both oil and natural gas at December 31, 2001, necessitated a pre-tax domestic full-cost ceiling write-down of $98.9 million, or $63.5 million after tax. In addition to this domestic ceiling write-down, we also expensed $2.1 million of charges in the fourth quarter of 2001 for certain delinquent accounts receivable, the majority of which were related to gas sold to Enron, and a write-off of debt issuance costs for a planned offering that was cancelled based upon market conditions following the events of September 11, 2001.

Income tax expense in 2003 includes a reduction of approximately $1.3 million from the U.S. statutory rate, primarily from the result of the currency exchange rate effect on the New Zealand deferred tax. This amount is partially offset by higher deferred state taxes and other items.

Net Income (Loss). Our net income in 2003 of $29.9 million was 151% higher and basic earnings per share (“Basic EPS”) of $1.09 were 142% higher than our 2002 net income of $11.9 million and Basic EPS of $0.45. Our earnings per diluted share (“Diluted EPS”) in 2003 of $1.08 were 140% higher than our 2002 Diluted EPS of $0.45. These amounts increased in the 2003 period as oil and gas sales increased due to higher commodity prices and increased production.

Our net income in 2002 of $11.9 million was 153% higher and Basic EPS of $0.45 was 150% higher than our 2001 net loss of $(22.3) million and Basic EPS of $(0.90). Our Diluted EPS in 2002 of $0.45 was 150% higher than our 2001 Diluted EPS of $(0.90). These amounts increased in 2002 due to overall lower costs, as a non-cash write-down of oil and gas properties occurred in 2001 and not in 2002, offset somewhat by lower revenue in 2002 due to lower commodity prices.

Proved Oil and Gas Reserves. At year-end 2003, our total proved reserves were 820.4 Bcfe with a PV-10 Value of $1.5 billion. In 2003, our proved natural gas reserves increased 9.1 Bcf, or 3%, while our proved oil reserves increased 10.3 MMBbl, or 15%, for a total equivalent increase of 71.0 Bcfe, or 9%. In 2002, our proved natural gas reserves increased by 1.8 Bcf, or 1%, while our proved oil reserves increased by 17.0 MMBbl, or 32%, for a total equivalent increase of 103.6 Bcfe, or 16%. We added reserves over the past three years through both our drilling activity and purchases of minerals in place. Through drilling we added 105.6 Bcfe (36.1 Bcfe of which came from New Zealand) of proved reserves in 2003, 83.9 Bcfe (15.9 Bcfe of which came from New Zealand) in 2002, and 105.8 Bcfe (17.4 Bcfe of which came from New Zealand) in 2001. Through acquisitions we added 0.5 Bcfe of proved reserves in 2003, 74.2 Bcfe in 2002, and 54.6 Bcfe in 2001. At year-end 2003, 59% of our total proved reserves were proved developed, compared with 60% at year-end 2002 and 50% at year-end 2001.

The PV-10 Value of our total proved reserves increased 33% from the PV-10 Value at year-end 2002. Gas prices increased in 2003 to $4.56 per Mcf from $3.49 per Mcf at year-end 2002, compared to $2.51 per Mcf at year-end 2001. Oil prices increased in 2003 to $30.16 per barrel from $29.27 per Bbl at year-end 2002, compared to $18.45 in 2001. Under SEC guidelines, estimates of proved reserves must be made using year-end oil and gas sales prices and are held constant throughout the life of the properties. Subsequent changes to such year-end oil and gas prices could have a significant impact on the calculated PV-10 Value. While our total proved reserves quantities increased by 3% during 2001, the PV-10 Value of those reserves decreased 74%, due to much lower prices at year-end 2001 than at year-end 2000. Between those two year-ends, there was a 75% decrease in natural gas prices and a 25% decrease in oil prices. This decrease in prices resulted in 47.1 Bcfe of downward reserves revisions, solely attributed to the decrease in prices at year-end 2001. The year-end 2001 gas price of $2.51 was significantly lower than the average gas price of $4.23 we received during 2001. The year-end 2001 oil price of $18.45 per barrel was also lower than the average oil price of $22.64 we received in 2001.

 

Contractual Commitments and Obligations

Our contractual commitments for the next five years and thereafter as of December 31, 2003 are as follows:

2004

2005

2006

2007

2008

Thereafter

Total

Non-cancelable operating lease commitments

$2,143,447

$492,613

$159,065

$156,649

$125,132

$13,500

$3,090,406

Capital commitments due to pipeline operators

96,244

---

---

---

---

---

96,244

Asset Retirement Obligation (1)

1,703,549

2,603,866

---

129,478

74,286

5,626,294

10,137,473

Drilling Rig and Seismic Commitments

5,919,000

---

---

---

---

---

5,919,000

Senior Notes due 2009 (2)

---

---

---

---

---

125,000,000

125,000,000

Senior Notes due 2012 (2)

---

---

---

---

---

200,000,000

200,000,000

Credit Facility which expires in October 2005 (3)

---

15,900,000

---

---

---

---

15,900,000

------------------

------------------

------------------

------------------

------------------

------------------

------------------

$9,862,240

$18,996,479

$159,065

$286,127

$199,418

$330,639,794

$360,143,123

 

1Amounts shown by year are the fair values at December 31, 2003.

2These amounts do not include the interest obligation, which is paid semiannually.

3These amounts exclude a $0.8 million standby letter of credit outstanding under this facility.

 

Commodity Price Trends and Uncertainties

Oil and natural gas prices historically have been volatile and are expected to continue to be volatile in the future. Worldwide supply disruptions, such as the reduction in crude oil production from Venezuela, together with perceived risks associated with the unrest in Iraq, along with other factors, have caused the price of oil to increase significantly in 2003 when compared to historical prices. Other factors such as actions taken by OPEC, worldwide economic conditions, weather conditions, and fluctuating currency exchange rates can cause wide fluctuations in the price of oil. Domestic natural gas prices increased significantly in the first quarter of 2003 when compared to historical prices and have since declined somewhat. North American weather conditions, the industrial and consumer demand for natural gas, storage levels of natural gas, and the availability and accessibility of natural gas deposits in North America can cause significant fluctuations in the price of natural gas. Such factors are beyond our control.

Liquidity and Capital Resources

During 2003, we largely relied upon cash provided by operating activities of $110.8 million, proceeds from bank borrowings of $15.9 million, and proceeds from the sale of property and equipment of $10.2 million to fund capital expenditures of $144.5 million. During 2002, we principally relied upon cash provided by operating activities of $71.6 million, net proceeds from the issuance of long-term debt of $195.0 million, and net proceeds from our public stock offering of $30.5 million, less the repayment of bank borrowings of $134.0 million, to fund capital expenditures of $155.2 million. For 2004, we believe that our credit facility and cash flow will be sufficient to fund our planned capital expenditures.

Net Cash Provided by Operating Activities. In 2003, net cash provided by our operating activities increased by 55% to $110.8 million, as compared to $71.6 million in 2002 and $139.9 million in 2001. The 2003 increase of $39.2 million was primarily due to an increase of oil and gas sales of $69.8 million due to higher commodity prices and production. The 2002 decrease of $68.3 million was primarily due to a reduction of oil and gas sales of $40.0 million due to lower commodity prices and to an increase in interest of $10.6 million due to higher debt balances and interest rates in 2002.

Existing Credit Facilities. At December 31, 2003, we had $15.9 million in outstanding borrowings under our credit facility. At December 31, 2002, we had no outstanding borrowings under this facility. Our credit facility at year-end 2003 consisted of a $300.0 million revolving line of credit with a $250.0 million borrowing base. The borrowing base is re-determined at least every six months and was reconfirmed by our bank group and increased to $250.0 million, effective November 1, 2003. We requested that the commitment amount with our bank group be reduced to $150.0 million effective May 9, 2003. Under the terms of the credit facility, we can increase this commitment amount back to the total amount of the borrowing base at our discretion, subject to the terms of the credit agreement. Our 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 in compliance with the provisions of this agreement. The credit facility extends until October 2005.

Our $125.0 million Senior Notes mature on August 1, 2009 and are callable August 1, 2004. Our $200.0 million Senior Notes mature on May 1, 2012. The indentures underlying our Senior Notes contain covenants that impose restrictions on us. Under the indentures, we are limited to the amount of debt that we can incur such that in general, after giving pro forma effect to such new debt, the consolidated interest coverage ratio would not exceed 2.5 to 1.0, or our indebtedness under our bank credit facility does not exceed the greater of $250.0 million or $150.0 million plus 25% of adjusted consolidated net tangible assets as defined under the indentures. The aggregate amount of our common stock that we can repurchase is limited to $5.0 million under the indenture governing our Senior Notes due 2012 and $2.0 million under the indenture governing our Senior Notes due 2009. We believe that these restrictions will not have any material effect upon our business for the foreseeable future.

In January 2004, we filed a universal shelf registration statement with the SEC to allow us to offer up to $350 million of our securities in the future. Upon effectiveness of the registration statement, for a period of two years we may periodically offer one or more of these securities in amounts, prices and on terms to be announced when and if the securities are offered. The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus supplement at the time of any such offering.

Working Capital. Our working capital declined from a negative $17.1 million at December 31, 2002, to a negative $35.1 million at December 31, 2003. The decrease was primarily due to an increase in accounts payable and accrued liabilities due to our year-end 2003 drilling activities. Consistent with prior years, we can draw on our available credit facility to remedy our working capital deficit if needed.

Capital Expenditures. In 2003, our capital expenditures of approximately $144.5 million included:

Domestic activities of $114.4 million, or 79% of total expenditures, as follows:

  • $57.0 million, or 39%, on developmental drilling, primarily in our Lake Washington area;

  • $25.9 million, or 18%, for the construction of production and surface facilities, mainly in our Lake Washington area;

  • $11.9 million, or 8%, on exploratory drilling, primarily in our Lake Washington area;

  • $11.4 million, or 8%, on domestic prospect costs, principally leasehold, seismic, and geological costs;

  • $4.4 million, or 3%, on field compression facilities;

  • $2.0 million, or 1%, for producing property acquisitions, including the purchase of property interests from partnerships managed by us;

  • $0.9 million, or less than 1%, for fixed assets; and

  • $0.9 million, or less than 1%, on gas processing plants in the Brookeland and Masters Creek areas.

New Zealand activities of $30.1 million, or 21% of total expenditures, as follows:

  • $15.1 million, or 10%, on developmental activities primarily to further delineate the Rimu and Kauri areas;
  • $6.4 million, or 4%, on prospect costs;
  • $5.7 million, or 4%, on gas processing plants;
  • $2.3 million, or 2%, for exploratory drilling mainly for the Tuihu exploratory well;
  • $0.3 million, or less than 1%, on producing properties acquisitions; and
  • $0.3 million, or less than 1%, for fixed assets.

In 2003, we participated in drilling 63 domestic development wells and eight domestic exploratory wells, of which 53 development wells and five exploratory wells were completed. In New Zealand we drilled three development wells and one exploratory well. Only one of these four wells, the exploratory well, was unsuccessful.

We currently plan to spend $130 to $150 million in total capital expenditures in 2004, excluding acquisition costs and net of approximately $5 million to $15 million in non-core property dispositions. The budget for 2004, as always, is dependent upon operational performance and commodity pricing levels during the year. Domestic activities account for 80% of budgeted spending, with the largest allocation going to the Lake Washington area.

We believe that the anticipated internally generated cash flows for 2004, together with bank borrowings under our credit facility, will be sufficient to finance the costs associated with our currently budgeted 2004 capital expenditures. If producing property acquisitions become attractive during 2004, we will explore the use of debt and/or equity offerings to fund such activity.

Our capital expenditures were approximately $155.2 million in 2002 and $275.1 million in 2001. During 2001, we relied both upon internally generated cash flows of $139.9 million and upon additional borrowings of $123.4 million from our bank credit facility to fund capital expenditures of $275.1 million. During 2002, we principally relied upon cash provided by operating activities of $71.6 million, net proceeds from the issuance of long-term debt of $195.0 million, and net proceeds from our public stock offering of $30.5 million, less the repayment of bank borrowings of $134.0 million, to fund capital expenditures of $155.2 million. Our capital expenditures in 2002 included:

New Zealand activities of $95.2 million, or 61% of total expenditures, as follows:

  • $56.1 million, or 36%, on property acquisitions, with approximately $51.7 million spent on the TAWN acquisition and the remainder for the cash portion of our Bligh and Antrim acquisitions;
  • $12.6 million, or 8%, on developmental drilling to further delineate the Rimu and Kauri areas;
  • $10.6 million, or 7%, on gas processing plants, principally the Rimu Production Station;
  • $10.3 million, or 7%, for exploratory drilling in the Rimu and Kauri areas;
  • $5.2 million, or 3%, on prospect costs, principally seismic and geological costs; and
  • $0.4 million, or less than 1%, for fixed assets, principally computers and office furniture and fixtures.

Domestic activities of $60.0 million, or 39% of total expenditures, as follows:

  • $34.4 million, or 22%, on developmental drilling;
  • $11.1 million, or 7%, on domestic prospect costs, principally leasehold, seismic, and geological costs;
  • $8.3 million, or 5%, on exploratory drilling;
  • $2.3 million, or 1%, for producing property acquisitions, including the purchase of property interests from partnerships managed by us;
  • $2.0 million, or 1%, on gas processing plants in the Brookeland and Masters Creek areas;
  • $1.1 million, or less than 1%, on field compression facilities; and
  • $0.8 million, or less than 1%, for fixed assets.

In 2002, we participated in drilling 23 domestic development wells and seven domestic exploratory wells, of which 17 development wells and three exploratory wells were completed. In New Zealand we drilled three development wells and three exploratory wells. One of the development wells and one of the exploratory wells were unsuccessful.

Critical Accounting Policies

The following summarizes several of our critical accounting policies. See a complete list of significant accounting policies in Note 1 to the Consolidated Financial Statements.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from estimates. Significant estimates include proved reserve volumes, DD&A, and deferred income taxes.

Property and Equipment. We follow the “full-cost” method of accounting for oil and gas property and equipment costs as described in detail in Note 1 to our Consolidated Financial Statements. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and gas reserves are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. For the years 2003, 2002, and 2001, internal costs capitalized totaled $11.5 million, $10.7 million, and $11.6 million, respectively. Interest costs related to unproved properties are also capitalized to unproved oil and gas properties. For the years 2003, 2002, and 2001, capitalized interest on unproved properties totaled $6.8 million, $7.0 million, and $6.3 million, respectively. Interest not capitalized and general and administrative costs related to production and general overhead are expensed as incurred.

Full-Cost Ceiling Test. These capitalized costs are subject to a ceiling test, however, which limits the unamortized cost of oil and gas properties, including deferred income taxes, to the sum of the estimated future net revenues from proved properties, excluding cash outflows from asset retirement obligations, using hedge adjusted 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”). Our hedges at year-end 2003 consisted of natural gas price floors with strike prices lower than the period end price and thus did not affect prices used in this calculation.

At December 31, 2003 and 2002, our unamortized costs of natural gas and oil properties did not exceed the ceiling amount. At December 31, 2003, our PV-10 value was calculated based upon quoted market prices of $4.56 per Mcf for gas and $30.16 per barrel for oil, adjusted for market differentials. In the fourth quarter of 2001, as a result of low oil and gas prices at December 31, 2001, we reported a non-cash write-down on a before-tax basis of $98.9 million ($63.5 million after tax) on our domestic properties. We had no write-down on our New Zealand properties. A decline in natural gas and oil prices from year-end 2003 levels or other factors, without mitigating circumstances, could cause a future non-cash write-down of capitalized costs and a non-cash charge against future earnings.

Accounts Receivable. Included in the total “Accounts receivable” balance, which totaled $28.6 million and $20.9 million at December 31, 2003 and 2002, respectively, on the accompanying balance sheet, was approximately $2.3 million of receivables related to volumes produced from 2001 and 2002 that we were notified were disputed in early 2003. Accordingly, we did not record a receivable to date with regard to 2003 volumes. We assess the collectibility of trade and other receivables. Based on our judgment, we would accrue a reserve when we believe a receivable may not be collected. At December 31, 2003 and 2002, we had an allowance for doubtful accounts of $0.8 million and $0.3 million, respectively. These allowance for doubtful accounts balances have been deducted from the total “Accounts receivable” balances on the balance sheet included in our Consolidated Financial Statements.

Price-Risk Management Activities.  We have a price-risk management policy to use derivative instruments to protect against declines in oil and gas prices, mainly through the purchase of price floors and collars. We adopted SFAS No. 133 effective January 1, 2001, which requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met as further described in Note 1 to our Consolidated Financial Statements.

Accordingly, we marked our open contracts at December 31, 2000, to fair value at that date, resulting in a one-time net of taxes charge of $0.4 million, which was recorded as a Cumulative Effect of Change in Accounting Principle. During 2003, 2002 and 2001, we recognized net losses (gains) of $2.8 million, $0.2 million and ($1.2 million), respectively, relating to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying statements of income. At December 31, 2003, we had recorded $0.3 million, net of taxes of $0.2 million, of derivative losses in “Other comprehensive loss” on the accompanying balance sheet. This amount represents the change in fair value for the effective portion of our transactions that qualified as cash flow hedges. The ineffectiveness reported in “Price-risk management and other, net” for 2003 and 2002 was not material. We expect to reclassify all amounts held in “Other comprehensive loss” into the statement of income within the next six months when the forecasted sale of hedge products occurs.

As of December 31, 2003, we had in place natural gas price floors in effect for the January 2004 contract month through the June 2004 contract month that cover our domestic natural gas production for January 2004 to June 2004. The natural gas price floors cover notional volumes of 3,300,000 Mmbtu with a weighted average floor price of $4.77. When we entered into these transactions they were designated as a hedge of the variability in cash flows associated with the forecasted sale of natural gas production. Changes in the fair value of a hedge that is highly effective and is designated and qualifies as a cash flow hedge, to the extent that the hedge is effective, are initially recorded in Other Comprehensive Income (Loss). When the hedged transactions are recorded upon the actual sale of oil and natural gas, these gains or losses are reclassified from Other Comprehensive Income (Loss) and recorded in “Price-risk management and other, net” on the statement of income. The fair value of our derivatives are computed using the Black-Scholes option pricing model and are periodically verified against quotes from brokers. The fair value of these instruments at December 31, 2003, was $0.5 million and is recognized on the balance sheet in “Other current assets.”

In January 2004, we entered into additional natural gas “floors” covering contract periods April 2004 to June 2004, which cover our natural gas production for January 2004 to June 2004. Notional volumes are 200,000 MMBtu per month at a weighted average floor price of $5.00 per MMBtu.

See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for additional discussion of commodity risk.

Stock Based Compensation. We have three stock-based compensation plans, which are described more fully in Note 6 to our Consolidated Financial Statements. We account for those plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. No stock-based employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of the grant; or in the case of the employee stock purchase plan, the purchase price is 85% of the lower of the closing price of our common stock as quoted on the New York Stock Exchange at the beginning or end of the plan year or a date during the year chosen by the participant.

Foreign Currency. We use the U.S. Dollar as our functional currency in New Zealand. The functional currency is determined by examining the entities’ cash flows, commodity pricing environment and financing arrangements. We have both assets and liabilities denominated in New Zealand Dollars, predominantly our portion of our “Deferred income taxes” and a portion of our “Asset Retirement Obligation” on the accompanying balance sheet. For accounts other than “Deferred income taxes,” as the currency rate changes between the U.S. Dollar and the New Zealand Dollar, we recognize transaction gains and losses in “Price-risk management and other, net” on the accompanying statements of income. We recognize transaction gains and losses on “Deferred income taxes” in “Provision for Income Taxes” on the accompanying statement of income.

New Accounting Pronouncements. In June 2002, the FASB issued SFAS No. 141, “Business Combinations,” and SFAS No. 142 “Goodwill and Intangible Assets.” We adopted these statements on July 1, 2001, and January 1, 2002, respectively. An issue has arisen for companies engaged in oil and gas exploration and production regarding the application of SFAS No. 141 and SFAS No. 142 as they relate to mineral rights held under lease or other contractual arrangements and as to whether costs associated with these rights should be classified as intangible assets on the balance sheet, apart from other capitalized oil and gas property costs. We understand that the Emerging Issues Task Force of the FASB has placed this issue on its agenda, although the date and the outcome of the resolution of the issue is unknown.

Historically we have classified our oil and gas mineral rights held under lease as tangible assets along with our other oil and gas properties, which is in accordance with the Securities and Exchange Commission’s (“SEC”) full cost accounting rules, and we intend to continue to do so until further guidance is provided. We have estimated the amount associated with these mineral rights using historical depletion rates, estimates of the timing of impairment of unproved properties and assuming the cost for the mineral rights was unaffected by the ceiling test write-down recorded in December 2001 because we cannot associate the ceiling test write-down with particular types of costs. Based on these limitations and assumptions, we estimate the net cost of mineral rights that would be reclassified from oil and gas properties to intangible assets to be approximately $55-60 million at December 31, 2003 and approximately $45-50 million at December 31, 2002. These amounts are from July 1, 2001 (the date we adopted SFAS No. 141) to December 31, 2003 as we are not able to calculate amounts to reclassify before that period as our property records did not break out that information. Only our balance sheet accounts would be affected by the reclassification, and our results of operations and cash flows would not be materially impacted by any such reclassification.

Related-Party Transactions

We have been the operator of a number of properties owned by our affiliated limited partnerships and, accordingly, charge these entities operating fees. The operating fees charged to the partnerships in 2003, 2002, and 2001 totaled approximately $0.2 million, $0.3 million, and $0.9 million, respectively, and are recorded as reductions of general and administrative expense and oil and gas production expense. We also have been reimbursed for direct, administrative, and overhead costs incurred in conducting the business of the limited partnerships, which totaled approximately $0.4 million, $1.0 million, and $3.1 million in 2003, 2002, and 2001, respectively. In partnerships in which the limited partners voted to sell their remaining properties and liquidate their limited partnerships, we also have been reimbursed for direct, administrative, and overhead costs incurred in the disposition of such properties, which costs totaled approximately $0.1 million, $0.5 million, and $2.4 million in 2003, 2002, and 2001, respectively.

Forward-Looking Statements

The statements contained in this report that are not historical facts are forward-looking statements as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended. Such forward-looking statements may pertain to, among other things, financial results, capital expenditures, drilling activity, development activities, cost savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters, and competition. Such forward-looking statements generally are accompanied by words such as “plan,” “future,” “estimate,” “expect,” “budget,” “predict,” “anticipate,” “projected,” “should,” “believe,” or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions, upon current market conditions, and upon engineering and geologic information available at this time, and is subject to change and to a number of risks and uncertainties, and, therefore, actual results may differ materially. Among the factors that could cause actual results to differ materially are: volatility in oil and natural gas prices, internationally or in the United States; availability of services and supplies; fluctuations of the prices received or demand for our oil and natural gas; the uncertainty of drilling results and reserve estimates; operating hazards; requirements for capital; general economic conditions; changes in geologic or engineering information; changes in market conditions; competition and government regulations; as well as the risks and uncertainties discussed herein and set forth from time to time in our other public reports, filings, and public statements. Also, because of the volatility in oil and gas prices and other factors, interim results are not necessarily indicative of those for a full year.


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