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FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 2005Item 7. Management's Discussion and Analysis of
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The following table provides information regarding the changes in the sources of our oil and gas sales and volumes for the years ended December 31, 2005, 2004, and 2003:
Oil and Gas Sales Oil and Gas Sales Volume
(in millions) (Bcfe)
Area 2005 2004 2003 2005 2004 2003 -------- -------- -------- ------- ------- ------- AWP Olmos $61.7 $49.9 $43.7 7.7 9.0 8.4 Brookeland 20.4 18.0 16.4 2.9 3.4 3.9 Lake Washington 229.2 152.3 59.5 26.7 23.2 12.1 Masters Creek 17.9 21.0 25.7 2.4 3.7 5.7 Other 26.7 17.5 18.9 3.3 2.8 3.7 -------- -------- -------- -------- -------- -------- Total Domestic $ 355.9 $ 258.7 $ 164.2 43.0 42.1 33.8 Rimu/Kauri 41.6 24.5 11.6 8.2 5.3 3.3 TAWN 26.3 28.1 35.2 8.3 11.0 16.1 ----------- ----------- ----------- ---------- ---------- ---------- Total New Zealand $67.9 $52.6 $46.8 16.5 16.3 19.4 ----------- ----------- ----------- ---------- ---------- ---------- Total $423.8 $311.3 $211.0 59.6 58.3 53.2 ======= ======= ======= ======= ======= =======
Oil and gas sales in 2005 increased by 36%, or $112.5 million, from the level of those revenues for 2004, and our net sales volumes in 2005 increased by 2%, or 1.3 Bcfe, over net sales volumes in 2004. Average prices for oil increased to $53.63 per Bbl in 2005 from $40.24 per Bbl in 2004. Average natural gas prices increased to $5.23 per Mcf in 2005 from $4.12 per Mcf in 2004. Average NGL prices increased to $28.04 per Bbl in 2005 from $22.52 per Bbl in 2004.
In 2005, our $112.5 million increase in oil, NGL, and natural gas sales resulted from:
Price variances that had a $100.0 million favorable impact on sales, of which $69.1 million was attributable to the 33% increase in average oil prices received, $26.3 million was attributable to the 27% increase in natural gas prices and $4.6 million was attributable to the 24% increase in NGL prices; and
Volume variances that had a $12.5 million favorable impact on sales, with $17.6 million of increases attributable to the 0.4 million Bbl increase in oil sales volumes, offset by a decrease of $4.6 million due to the 0.2 million Bbl decrease in NGL sales volumes, and a decrease of $0.5 million due to the 0.1 Bcf decrease in natural gas sales volumes.
Oil and gas sales in 2004 increased by 48%, or $100.3 million, from the level of those revenues for 2003, and our net sales volumes in 2004 increased by 10%, or 5.2 Bcfe, over net sales volumes in 2003. Average prices for oil increased to $40.24 per Bbl in 2004 from $29.89 per Bbl in 2003. Average natural gas prices increased to $4.12 per Mcf in 2004 from $3.42 per Mcf in 2003. Average NGL prices increased to $22.52 per Bbl in 2004 from $17.60 per Bbl in 2003.
In 2004, our $100.3 million increase in oil, NGL, and natural gas sales resulted from:
Price variances that had a $70.6 million favorable impact on sales, of which $48.9 million was attributable to the 35% increase in average oil prices received, $16.6 million was attributable to the 20% increase in natural gas prices and $5.1 million was attributable to the 28% increase in NGL prices; and
Volume variances that had a $29.7 million favorable impact on sales, with $40.4 million of increases attributable to the 1.4 million Bbl increase in oil sales volumes and $3.8 million to the 217,000 Bbl increase in NGL sales volumes, offset by a decrease of $14.5 million due to the 4.3 Bcf decrease in natural gas sales volumes primarily from our TAWN area in New Zealand.
The following table provides additional information regarding our quarterly oil and gas sales:
Sales Volume
Average Sales Price
Natural
Oil NGL Gas Combined Oil NGL Gas (MBbl) (MBbl) (Bcf) (Bcfe) (Bbl) (Bbl) (Mcf) 2003: First 690 174 7.6 12.9 $ 32.73 $ 21.90 $ 3.71 Second 822 211 7.1 13.3 $ 27.97 $ 15.81 $ 3.47 Third 917 247 6.7 13.6 $ 29.24 $ 16.81 $ 3.17 Fourth 941 191 6.6 13.4 $ 30.10 $ 16.71 $ 3.29 --------- ---------- ---------- ---------- Total 3,370 823 28.0 53.2 $ 29.89 $ 17.60 $ 3.42 ====== ====== ====== ====== 2004: First 1,124 277 5.9 14.3 $ 34.14 $ 22.30 $ 3.64 Second 1,142 269 5.8 14.3 $ 37.24 $ 18.84 $ 4.19 Third 1,076 251 6.0 13.9 $ 41.99 $ 23.33 $ 3.97 Fourth 1,380 243 6.1 15.9 $ 46.33 $ 26.01 $ 4.67 --------- ---------- ---------- ---------- Total 4,722 1,040 23.7 58.3 $ 40.24 $ 22.52 $ 4.12 ====== ====== ====== ====== 2005: First 1,321 223 6.3 15.5 $ 47.66 $ 26.79 $ 4.25 Second 1,426 209 6.1 15.9 $ 50.24 $ 22.95 $ 4.67 Third 1,059 204 5.9 13.5 $ 59.66 $ 31.84 $ 5.29 Fourth 1,353 202 5.3 14.7 $ 58.31 $ 30.83 $ 6.97 --------- ---------- ---------- ---------- Total 5,159 838 23.6 59.6 $ 53.63 $ 28.04 $ 5.23 ====== ====== ====== ======
Costs and Expenses. Our expenses in 2005 increased $36.0 million, or 17%, compared to 2004 expenses. The majority of the increase was due to a $25.9 million increase in DD&A, an $11.8 million increase in severance and other taxes, and a $6.1 million increase in lease operating costs, all of which are primarily due to increased commodity prices and production volumes in 2005. This increase was partially offset by the absence of $9.5 million of debt retirement costs incurred in 2004. Our expenses in 2004 increased $50.7 million, or 32%, compared to 2003 expenses. The majority of the increase was due to an $18.5 million increase in DD&A, an $11.4 million increase in severance and other taxes, and a $7.4 million increase in lease operating costs, all of which were primarily due to increased production volumes and oil and gas commodity prices in 2004.
Our 2005 general and administrative expenses, net, increased $4.4 million, or 25%, from the level of such expenses in 2004, while 2004 general and administrative expenses, net, increased $3.7 million, or 26%, over 2003 levels. The increase in both 2005 and 2004 were primarily due to increased salaries and burdens associated with our expanded workforce and the expensing of restricted stock compensation in 2005. A portion of the increase in 2004 costs was also attributable to Sarbanes-Oxley Act compliance costs increasing over the prior year. These costs, while remaining high, have stabilized from 2004 to 2005. For the years 2005, 2004, and 2003, our capitalized general and administrative costs totaled $18.8 million, $13.1 million, and $11.5 million, respectively. Our net general and administrative expenses per Mcfe produced increased to $0.37 per Mcfe in 2005 from $0.30 per Mcfe in 2004 and $0.27 per Mcfe in 2003. Our 2005 cost per Mcfe was adversely affected by the approximate 6.0 to 6.5 Bcfe of production that was deferred, and not produced in 2005, because of Hurricanes Katrina and Rita. The portion of supervision fees recorded as a reduction to general and administrative expenses was $7.8 million for 2005, $5.8 million for 2004, and $3.6 million for 2003.
DD&A increased $25.9 million, or 32%, in 2005 from 2004 levels, while 2004 DD&A increased $18.5 million, or 29%, from 2003 levels. Domestically, DD&A increased $18.8 million in 2005 due to increases in the depletable oil and gas property base, slightly higher production in the 2005 period and lower reserves volumes. In New Zealand, DD&A increased by $7.1 million in 2005 due to the same reasons. In 2004, our domestic DD&A increased by $17.6 million due to increases in the depletable oil and gas property base, higher production in the 2004 period and slightly lower reserves volumes. Our New Zealand DD&A increased by $0.9 million in 2004 due to increases in the depletable oil and gas property base along with lower reserves volumes, partially offset by lower production in the 2004 period. Our DD&A rate per Mcfe of production was $1.80 in 2005, $1.40 in 2004, and $1.19 in 2003, resulting from increases in per unit cost of reserves additions.
We recorded $0.8 million, $0.7 million, and $0.9 million of accretions to our asset retirement obligation in 2005, 2004, and 2003, respectively.
Our lease operating costs per Mcfe produced were $0.79 in 2005, $0.71 in 2004 and $0.64 in 2003. Our 2005 cost per Mcfe was adversely affected by the approximate 6.0 to 6.5 Bcfe of production that was deferred, and not produced in 2005, because of Hurricanes Katrina and Rita. There were no supervision fees recorded as a reduction to production costs in 2005 or 2004, while there were $1.5 million in 2003. Our lease operating costs in 2005 increased $6.1 million, or 15%, over the level of such expenses in 2004, while 2004 costs increased $7.4 million, or 22% over 2003 levels. Approximately $4.7 million of the increase in lease operating costs during 2005 was related to our domestic operations, which increased primarily due to hurricane related costs, along with increased oil production from our Lake Washington area. Our lease operating cost in New Zealand increased in 2005 by $1.4 million due to increases in plant operating costs related to increased staffing in this area. Approximately $1.2 million of the increase in 2004 was due to our New Zealand operations as production increased over 2003 levels.
Severance and other taxes increased $11.8 million, or 39% over 2004 levels, while in 2004 these taxes increased $11.4 million, or 60% over 2003 levels. The increases were due primarily to higher commodity prices and increased Lake Washington and Rimu/Kauri production in each of the periods. Severance taxes on oil in Louisiana are 12.5% of oil sales, which is higher than in the other states where we have production. As our percentage of oil production in Louisiana increases, the overall percentage of severance costs to sales also increases. Severance and other taxes, as a percentage of oil and gas sales, were approximately 10.0%, 9.8% and 9.0% in 2005, 2004 and 2003, respectively.
Our total interest cost in 2005 was $32.1 million, of which $7.2 million was capitalized. Our total interest cost in 2004 was $34.2 million, of which $6.5 million was capitalized. Our total interest cost in 2003 was $34.2 million, of which $6.8 million was capitalized. Interest expense on our 7-5/8% senior notes due 2011 issued in June 2004, including amortization of debt issuance costs, totaled $11.9 million in 2005 and $6.2 million in 2004. Interest expense on our 9-3/8% senior subordinated notes due 2012 issued in April 2002, including amortization of debt issuance costs, totaled $19.2 million in both 2005 and 2004, and $19.1 million in 2003. Interest expense on our 10-1/4% senior subordinated notes issued in August 1999 and repurchased and retired in 2004, including amortization of debt issuance costs, totaled $7.4 million in 2004 and $13.2 million in 2003. Interest expense on our bank credit facility, including commitment fees and amortization of debt issuance costs, totaled $1.0 million in 2005, $1.5 million in 2004, and $1.6 million in 2003. Other interest cost was $0.3 million in 2003. We capitalize a portion of interest related to unproved properties. The decrease of interest expense in 2005 was primarily due to the lower interest rate applicable to the 7-5/8% notes issued in June 2004 versus the 10-1/4% notes retired at that time. The increase in interest expense in 2004 was due to lower capitalized interest than in 2003.
In 2004, we incurred $9.5 million of debt retirement costs related to the repurchase and redemption of our 10-1/4% senior subordinated notes due 2009. The costs were comprised of approximately $6.5 million of premiums paid to repurchase the notes, $2.2 million to write-off unamortized debt issuance costs, $0.6 million to write-off unamortized debt discount and approximately $0.2 million of other costs.
Our overall effective tax rate was 35.1% for 2005, and 32.5% for 2004 and 2003. The effective tax rate for 2005, 2004 and 2003 was lower than the statutory tax rates primarily due to reductions from the New Zealand statutory rate attributable to the currency effect on the New Zealand deferred tax calculation. The provision for 2005 included the reversal of a New Zealand repatriation allowance offset by an adjustment to correct an error in a prior year’s tax returns and higher state tax rate estimates. The effective tax rate for 2004 included favorable corrections to tax basis amounts discovered while preparing the prior year’s tax returns, partially offset by higher deferred state income taxes. Income tax expense in 2003 included higher domestic state income taxes and other items.
As discussed in Note 1 to the consolidated financial statements, we adopted SFAS No. 143 “Accounting for Asset Retirement Obligations” on January 1, 2003. Our adoption of SFAS No. 143 resulted in a one-time net of taxes charge of $4.4 million, which was recorded as a cumulative effect of change in accounting principle in the 2003 consolidated statement of income.
Net Income. Our net income in 2005 of $115.8 million was 69% higher than our 2004 net income of $68.5 million due to higher commodity prices and increased production.
Our net income in 2004 of $68.5 million was 129% higher than our 2003 net income of $29.9 million due to higher commodity prices and increased production.
Contractual Commitments and Obligations
Our contractual commitments for the next five years and thereafter as of December 31, 2005 are as follows:
2006 2007 2008 2009 2010 Thereafter Total (In thousands)
Non-cancelable operating leases (1) $ 3,404 $ 3,401 $ 3,042 $ 2,655 $ 2,751 $ 13,394 $ 28,647 Asset retirement obligation(2) 261 261 261 261 261 18,051 19,356 Construction at the corporate office 7,337 — — — — — 7,337 Drilling rigs, seismic and pipe inventory 28,110 1,807 — — — — 29,917 7-5/8% senior notes due 2011(3) — — — — — 150,000 150,000 9-3/8% senior subordinated notes due 2012(3) — — — — — 200,000 200,000 Credit facility(4) — — — — — — — ---------- ---------- ---------- ---------- ---------- ---------- ---------- Total $ 39,112 $ 5,469 $ 3,303 $ 2,916 $ 3,012 $ 381,445 $ 435,257 ======= ======= ======= ======= ======= ======= =======
(1) Our most significant office lease is in Houston, Texas extends until 2015.
(2) Amounts shown by year are the fair values at December 31, 2005.
(3) Amounts do not include the interest obligation, which is paid semiannually.
(4) The credit facility expires in October 2008 and these 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. The price of oil has increased over the last two years and is at historical highs when compared to longer-term historical prices. Factors such as worldwide supply disruptions, worldwide economic conditions, weather conditions, fluctuating currency exchange rates, political conditions in major oil producing regions, especially the Middle East, can cause fluctuations in the price of oil. Domestic natural gas prices continue to remain high when compared to longer-term historical prices. 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.
Income Tax Regulations
The tax laws in the jurisdictions we operate in are continuously changing and professional judgments regarding such tax laws can differ.
Liquidity and Capital Resources
During 2005, we largely relied upon our net cash provided by operating activities of $285.3 million to fund capital expenditures of $235.5 million and $28.9 million of acquisitions. During 2004, we relied upon our net cash provided by operating activities of $182.6 million, the issuance of our 7-5/8% senior notes due 2011, proceeds from the sale of non-core properties and equipment of $5.1 million, less the repayment of our 10-1/4% senior subordinated notes due 2009 to fund capital expenditures of $171.1 million and acquisitions of $27.2 million.
Net Cash Provided by Operating Activities. For 2005, our net cash provided by operating activities was $285.3 million, representing a 56% increase as compared to $182.6 million generated during 2004. The $102.8 million increase in 2005 was primarily due to an increase of $112.5 million in oil and gas sales, attributable to higher commodity prices and production, offset in part by higher lease operating costs due to higher domestic production and severance taxes as a result of higher commodity prices. In 2004, net cash provided by operating activities increased by 65% to $182.6 million, as compared to $110.8 million in 2003. The 2004 increase of $71.8 million was primarily due to an increase of $100.3 million in oil and gas sales, attributable to higher commodity prices and production, offset in part by higher lease operating costs due to higher domestic production and severance taxes as a result of higher commodity prices in 2004.
Accounts Receivable. Included in the “Accounts receivable” balance, which totaled $39.0 million at December 31, 2004, on the accompanying balance sheets, were approximately $2.3 million of receivables related to hydrocarbon volumes produced from 2001 and 2002 that had been disputed since early 2003. As a result of the dispute, we did not record a receivable with regard to any 2003 disputed volumes and our contract governing these sales expired in 2003. Based on settlement discussions, we settled our claim with this counter-party in July 2005 by receiving a cash payment for less than our gross receivable. Accordingly, in the second quarter of 2005, we increased our reserve for this claim by approximately $0.6 million, which is recorded in “Price-risk management and other, net” on the accompanying statements of income.
We assess the collectibility of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At December 31, 2005 and 2004, we had an allowance for doubtful accounts of less than $0.1 million and $0.5 million, respectively. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balances on the accompanying balance sheets.
Sarbanes-Oxley Compliance Costs. We have incurred substantial costs to comply with the Sarbanes-Oxley Act of 2002. These expenditures have reduced our net cash provided by operating activities in each of the last three years. In 2005, 2004 and 2003, Sarbanes-Oxley Act compliance costs, including internal and external costs, are reflected in “General and administrative, net” on the accompanying statements of income.
Existing Credit Facility. We had no borrowings under our bank credit facility at December 31, 2005, and $7.5 million in outstanding borrowings at December 31, 2004. Our bank credit facility at December 31, 2005 consisted of a $400.0 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 reaffirmed by our bank group at $250.0 million, effective November 1, 2005. We maintain the commitment amount at $150.0 million, which amount was set at our request effective May 9, 2003. Under the terms of our bank credit facility, we can increase this commitment amount to the total amount of the borrowing base at our discretion, subject to the terms of the credit agreement. Our revolving credit facility includes requirements to maintain certain minimum financial ratios (principally pertaining to adjusted working capital ratios and EBITDAX), and limitations on incurring other debt. We are in compliance with the provisions of this agreement.
Our access to funds from our credit facility is not restricted under any “material adverse condition” clause, a clause that is common for credit agreements to include. A “material adverse condition” clause can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have an adverse or material effect on our operations, financial condition, prospects or properties, and would impair our ability to make timely debt repayments. Our credit facility includes covenants that require us to report events or conditions having a material adverse effect on our financial condition. The obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect.
Working Capital. Our working capital improved from a deficit of $14.2 million at December 31, 2004, to a surplus of $16.6 million at December 31, 2005. The improvement primarily resulted from an increase in cash and cash equivalents and an increase in accounts receivable for oil and gas sales due to higher sales volumes and commodity prices.
Repurchase of 10-1/4% Senior Subordinated Notes Due 2009. In June 2004, we repurchased $32.1 million of our 10-1/4 senior subordinated notes due 2009 pursuant to a tender offer, and recorded debt retirement costs of $2.7 million related to this repurchase. In July 2004, we repurchased approximately $0.5 million of these notes, and as of August 1, 2004, we redeemed the remaining $92.5 million of these notes. We have recorded a total of $9.5 million in debt retirement costs related to the total repurchase of these notes.
Debt Maturities. Our credit facility extends until October 1, 2008. Our $150.0 million of 7-5/8% senior notes mature July 15, 2011, and our $200.0 million of 9-3/8% senior subordinated notes mature May 1, 2012.
Capital Expenditures. In 2005 we relied upon our net cash provided by operating activities of $285.3 million to fund capital expenditures of $235.5 million and acquisitions of $28.9 million. Our total capital expenditures of approximately $264.5 million in 2005 included:
Domestic expenditures of $215.8 million as follows:
New Zealand expenditures of $48.7 million as follows:
We have spent considerable time and capital in 2005 and 2004 on significant facility capacity upgrades in the Lake Washington field to increase facility capacity to approximately 28,000 barrels per day for crude oil, up from 9,000 barrels per day capacity in the first quarter of 2003. We have upgraded three production platforms, added new compression for the gas lift system, and installed a new oil delivery system and permanent barge loading facility.
We successfully completed 45 of 64 wells in 2005, for a success rate of 70%. Domestically, we completed 37 of 45 development wells for a success rate of 82% and completed five of nine exploration wells. A total of 32 wells were drilled in the Lake Washington area, of which 21 were completed, and 18 wells were drilled in the AWP Olmos area, all of which were completed. In New Zealand, we completed two of five development wells, and one of five exploratory wells.
Our 2006 capital expenditure budget is $300 million to $325 million, net of $5 million to $10 million of dispositions and excluding any acquisitions. Approximately 85% of the budget is targeted for domestic activities, with about 15% planned for activities in New Zealand. We plan to spend $175 million to $195 million in our South Louisiana region, which includes Lake Washington, Bay de Chene and Cote Blanche Island. Of this amount, approximately $40 million to $50 million will be focused in Bay de Chene and Cote Blanche Island and includes approximately $11 million designated for the Cote Blanche Island 3-D seismic acquisition planned for 2006. The $5 million to $10 million of dispositions relate to non-core properties planned for later in 2006. We expect that our 2006 capital expenditures to remain below our cash flows provided from operating activities during 2006, similar to 2005. During 2006, we may utilize our free cash flow to expand our capital budget and accelerate our drilling inventory plans to take advantage of current commodity prices, potential acquisitions, debt repayment or stock repurchases. For 2006, we are targeting an increase of 14% to 18% for total production and an increase of 5% to 8% for proved reserves, over the 2005 levels.
Our capital expenditures were approximately $171.1 million in 2004 and $144.5 million in 2003. During 2004, we relied upon our net cash provided by operating activities of $182.6 million, the issuance of our 7-5/8% senior notes due 2011, proceeds from the sale of non-core properties and equipment of $5.1 million, less the repayment of our 10-1/4% senior subordinated notes due 2009 to fund capital expenditures of $171.1 million and acquisitions of $27.2 million. During 2003, we relied upon our net cash provided by operating activities of $110.8 million, proceeds from bank borrowings of $15.9 million, and proceeds from the sale of non-core properties and equipment of $10.2 million to fund capital expenditures of $144.5 million. Our total capital expenditures in 2004 of approximately $198.3 million included:
Domestic expenditures of $162.5 million as follows:
New Zealand expenditures of $35.8 million as follows:
In 2004, we participated in drilling 44 domestic development wells and ten domestic exploratory wells, of which 37 development wells and four exploratory wells were completed. In New Zealand we drilled 11 development wells, of which ten were completed, and one unsuccessful exploratory well.
New Accounting Principles
EITF 04-05 addresses when a limited partnership should be consolidated by its general partner. EITF 04-05 presumes that a sole general partner in a limited partnership controls the limited partnership, and therefore should consolidate the limited partnership. The presumption of control can be overcome if the limited partners have (a) the substantive ability to remove the sole general partner or otherwise dissolve the limited partnership or (b) substantive participating rights. The EITF reached a tentative conclusion on the circumstances in which either kick-out rights or participating rights would be considered substantive and preclude consolidation by the general partner. The FASB ratified the EITF consensus at the June 2005 EITF meeting. We do not believe this EITF will have a material impact on our consolidated financial statements because we believe our limited partners have substantive kick-out rights under paragraph B20 of FIN 46R.
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS No. 123R is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, and supercedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and amends SFAS No. 95, Statement of Cash Flows. SFAS No. 123R requires all employee share-based payments, including grants of employee stock options, to be recognized in the financial statements based on their fair values. SFAS No. 123 discontinues the ability to account for these equity instruments under the intrinsic value method as described in APB Opinion No. 25. SFAS No. 123R requires the use of an option pricing model for estimating fair value, which is amortized to expense over the service periods. The requirements of SFAS No. 123R are effective for fiscal periods beginning after June 15, 2005. SFAS No. 123R permits public companies to adopt its requirements using one of two methods, we have chosen the “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS No. 123R for all share-based payments granted after the effective date and based on the requirements of SFAS No. 123 for all awards granted to employees prior to the adoption date of SFAS No. 123R that remain unvested on the adoption date.
In April 2005, the SEC issued a release announcing that it would provide for a phased-in implementation process for SFAS No. 123R. As a result, our required date to adopt SFAS No. 123R was January 1, 2006. Also in April 2005, the SEC issued Staff Accounting Bulleting No. 107, Share-Based Payment, which provides guidance on the implementation of SFAS No. 123R. SAB No. 107 provides guidance on valuing options, estimating volatility and expected terms of the option awards, and discusses the SEC’s views on share-based payment transactions with non-employees, the capitalization of compensation cost and accounting for income tax effects of share-based payment arrangements upon adoption of SFAS No. 123R.
We will adopt the provisions of SFAS No. 123R effective January 1, 2006 using the modified prospective method. As permitted by Statement 123, the Company previously accounted for share-based payments to employees using APB Opinion No. 25’s intrinsic value method and, as such, generally recognizes no compensation cost for employee stock options. Accordingly, the adoption of Statement No. 123R’s fair value method is expected to have a significant impact on our results of operations. However, it will have no impact on our overall financial position. We use the Black-Scholes-Merton formula to estimate the value of stock options granted to employees and expect to continue to use this acceptable option valuation model after the required adoption of SFAS No. 123R. The significance of the impact of adoption will depend on levels of outstanding unvested share-based payments on the date of adoption and share-based payments granted in the future. However, had we adopted Statement No. 123R in prior periods, the impact of that standard would have approximated the impact of Statement No. 123 as described in the disclosure of pro forma net income and earnings per share under “Stock Based Compensation.” We are still evaluating the effect of adopting this standard, but do not believe the Cumulative Effect of Change in Accounting Principle will be material to our results of operations.
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections: a replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS No. 154 requires voluntary changes in accounting principles to be applied retrospectively, unless it is impracticable. SFAS No. 154’s retrospective application requirement replaces APB 20’s requirement to recognize most voluntary changes in accounting principle by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. If retrospective application for all prior periods is impracticable, the method used to report the change and the reason the retrospective application is impracticable are to be disclosed.
Under SFAS No. 154, retrospective application will be the transition method in the unusual instance that a newly issued accounting pronouncement does not provide specific transition guidance. It is expected that many pronouncements will specify transition methods other than retrospective. SFAS No. 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005, and the adoption of this statement is expected to have no impact on our financial position or results of operations.
In July 2005, the FASB issued an exposure draft “Accounting for Uncertain Tax Positions, a proposed interpretation of FASB Statement No. 109.” The proposed interpretation would apply to all open tax positions under FASB No. 109. The conclusions in this interpretation include: initial recognition of tax benefits, recognition and de-recognition of tax positions, measurement of tax benefits and classifications of tax liabilities. The comment period on this exposure draft ended in September 2005, and we are currently assessing the impact, if any, that this interpretation would have on our financial position and results of operations. The FASB has not issued an effective date for this interpretation, and a final standard will likely be issued in 2006.
Proved Oil and Gas Reserves
At year-end 2005, our total proved reserves were 761.8 Bcfe with a PV-10 Value of $3.2 billion (PV-10 is a non-GAAP measure, see the section titled “Oil and Natural Gas Reserves” in our Business and Properties section for a reconciliation of this non-GAAP measure to the closest GAAP measure, the standardized measure). In 2005, our proved natural gas reserves decreased 30.8 Bcf, or 10%, while our proved oil reserves decreased 0.7 MMBbl, or 1%, and our NGL reserves decreased 0.5 MMBbl, or 3%, for a total equivalent decrease of 38.1 Bcfe, or 5%. In 2004, our proved natural gas reserves decreased by 17.6 Bcf, or 5%, while our proved oil reserves increased by 1.8 MMBbl, or 3%, and our NGL reserves decreased by 2.3 MMBbl, or 14%, for a total equivalent decrease of 20.5 Bcfe, or 3%. We added reserves over the past three years through both our drilling activity and purchases of minerals in place. Through drilling we added 31.6 Bcfe (2.0 of which came from New Zealand) of proved reserves in 2005, 7.2 Bcfe (all of which was domestic) in 2004, and 105.6 Bcfe (36.1 Bcfe of which came from New Zealand) in 2003. Through acquisitions we added 28.9 Bcfe of proved reserves in 2005, 43.4 Bcfe in 2004, and 0.5 Bcfe in 2003. At year-end 2005, 50% of our total proved reserves were proved developed, compared with 56% at year-end 2004 and 59% at year-end 2003.
The PV-10 Value of our total proved reserves at year-end 2005 increased 57% from the PV-10 Value at year-end 2004. Gas prices increased in 2005 to $8.94 per Mcf from $5.16 per Mcf at year-end 2004, compared to $4.56 per Mcf at year-end 2003. Oil prices increased in 2005 to $60.12 per Bbl from $41.07 per Bbl at year-end 2004, compared to $30.16 in 2003. Under SEC guidelines, estimates of proved reserves must be made using year-end oil and gas sales prices and are held constant for that year’s reserve calculation 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.
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 (GAAP) requires us to make estimates and assumptions that affect the reported amount of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates underlying these financial statements include:
While we are not aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period during which the adjustment occurs.
Property and Equipment. 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 exploration, development, and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the years 2005, 2004, and 2003, such internal costs capitalized totaled $18.8 million, $13.1 million, and $11.5 million, respectively. Interest costs are also capitalized to unproved oil and gas properties. For the years 2005, 2004, and 2003, capitalized interest on unproved properties totaled $7.2 million, $6.5 million, and $6.8 million, respectively. Interest not capitalized and general and administrative costs related to production and general overhead are expensed as incurred.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and gas properties (including gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using period-end prices, adjusted for the effects of hedging, 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 December 31, 2005 consisted of natural gas price floors with strike prices lower than the period-end price and thus did not materially affect prices used in this calculation. This calculation is done on a country-by-country basis.
The calculation of the Ceiling Test and provision for DD&A 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 estimates. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered. Our reserves estimates are prepared in accordance with Securities and Exchange Commission guidelines; and, are audited on an annual basis at year-end by a firm of independent petroleum engineers in accordance with standards approved by the Board of Directors of the Society of Petroleum Engineers.
Given the volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline from our period-end prices used in the Ceiling Test, even if only for a short period, it is possible that non-cash write-downs of oil and gas properties could occur in the future.
Price-Risk Management Activities. The Company follows SFAS No. 133, which requires that changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The statement also establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) is recorded in the balance sheet as either an asset or a liability measured at its fair value. Hedge accounting for a qualifying hedge allows the gains and losses on derivatives to offset related results on the hedged item in the income statements and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. Changes in the fair value of derivatives that do not meet the criteria for hedge accounting, and the ineffective portion of the hedge, are recognized currently in income.
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. During 2005, 2004 and 2003, we recognized net losses of $1.1 million, $1.3 million and $2.8 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, 2005, the Company had recorded $0.1 million, net of taxes of less than $0.1 million, of derivative losses in “Accumulated other comprehensive income (loss), net of income tax” on the accompanying balance sheet. This amount represents the change in fair value for the effective portion of our hedging transactions that qualified as cash flow hedges. The ineffectiveness reported in “Price-risk management and other, net” for 2005, 2004, and 2003 was not material. We expect to reclassify all amounts currently held in “Accumulated other comprehensive income (loss), net of income tax” into the statement of income within the next six months when the forecasted sale of hedged production occurs.
At December 31, 2005, we had in place price floors in effect for February 2006 through the June 2006 contract month for natural gas, that cover a portion of our domestic natural gas production for February 2006 to June 2006. The natural gas price floors cover notional volumes of 2,075,000 MMBtu, with a weighted average floor price of $8.39 per MMBtu. Our natural gas price floors in place at December 31, 2005 are expected to cover approximately 35% to 40% of our estimated domestic natural gas production from February 2006 to June 2006.
When we entered into these transactions discussed above, 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 documented and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded in “Accumulated other comprehensive income (loss), net of income tax.” When the hedged transactions are recorded upon the actual sale of oil and natural gas, these gains or losses are reclassified from “Accumulated other comprehensive income (loss), net of income tax” and recorded in “Price-risk management and other, net” on the accompanying statement of income. The fair value of our derivatives is computed using the Black-Scholes option pricing model and is periodically verified against quotes from brokers. The fair value of these instruments at December 31, 2005, was $0.3 million and is recognized on the accompanying balance sheet in “Other current assets.”
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 accompanying 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. We issued restricted stock for the first time in 2004 and again in 2005, and recorded expense related to these shares of $1.2 million and less than $0.1 million for 2005 and 2004, respectively, in “General and administrative, net” on the accompanying statements of income. No stock-based employee compensation cost is reflected in net income for employee stock options, 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, the New Zealand “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.
Related-Party Transactions
We are the operator of a number of properties owned by affiliated limited partnerships and, accordingly, charge these entities operating fees. The operating fees charged to the partnerships totaled approximately $0.2 million in 2005, 2004 and 2003, and are recorded as reductions of general and administrative, net. We also have been reimbursed for administrative, and overhead costs incurred in conducting the business of the limited partnerships, which totaled less than $0.1 million, $0.2 million, and $0.4 million in 2005, 2004, and 2003, respectively, and are recorded as reductions in general and administrative, net. Included in “Accounts receivable” and “Accounts payable and accrued liabilities” on the accompanying balance sheets, is approximately $0.4 million and $0.5 million, respectively, in receivables from and payables to the partnerships at December 31, 2005.
We receive research, technical writing, publishing, and website-related services from Tec-Com Inc., a corporation located in Knoxville, Tennessee and controlled and majority owned by the sister of the Company's Chairman of the Board and aunt of the Company’s Chief Executive Officer. In 2005, 2004 and 2003, we paid approximately $0.4 million per year to Tec-Com for such services pursuant to the terms of the contract between the parties. The contract was renewed June 30, 2004 on substantially the same terms and expires June 30, 2007. We believe that the terms of this contract are consistent with third party arrangements that provide similar services.
As a matter of corporate governance policy and practice, related party transactions are annually presented and considered by the Corporate Governance Committee of our Board of Directors in accordance with the Committee's charter.
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 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; disruption of operations and damages due to hurricanes or tropical storms; 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 in this report and set forth from time to time in our other public reports, filings, and public statements.
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