SWIFT ENERGY COMPANY 2007 ANNUAL REPORT
Management's Discussion and Analysis of
Financial Condition and Results of Operations
You should read the following discussion and analysis in conjunction with our financial information and our audited consolidated financial statements and accompanying notes for the years ended December 31, 2007, 2006, and 2005 included with this report. The following information contains "Forward-Looking Statements."
Overview
We are an independent oil and natural gas company formed in 1979, and we are engaged in the exploration, development, acquisition and operation of oil and natural gas properties, with a focus on our reserves and production from the inland waters of Louisiana and from our onshore Louisiana and Texas properties.
We are the largest producer of oil in the state of Louisiana, and due to increasing emphasis on our South Louisiana operations, we have become predominantly an oil producer, with oil constituting 66% of our 2007 domestic production, and oil and natural gas liquids ("NGLs") together making up 74% of our 2007 domestic production. This emphasis has allowed us to benefit from better margins for oil production than natural gas production in recent periods.
In December 2007, we agreed to sell substantially all of our New Zealand assets to Origin Energy Limited for a minimum of $87.8 million, with an expected closing towards the end of the first quarter of 2008. Accordingly, the New Zealand operations have been classified as discontinued operations in the consolidated statements of income and cash flows and the assets and associated liabilities have been classified as held for sale in the consolidated balance sheets. The pending sale of these assets resulted in a fourth quarter 2007 non-cash charge of approximately $131 million (net of tax effects) based on the selling price and terms of the sales agreement. We expect to realize total cash proceeds of between $100 and $110 million from the sale of all of our New Zealand assets, which we anticipate completing later this year. Proceeds from the New Zealand assets sale will most likely be used to pay down a portion of our credit facility.
Unless otherwise noted, both historical information for all periods and forward-looking information provided in this Management’s Discussion and Analysis relate solely to our continuing operations located in the United States, and excludes our discontinued New Zealand operations.
In our 2007 continuing operations we had record income, cash flows, and production. Income from continuing operations increased 1% to $152.6 million and cash flows from operating activities from continuing operations increased 15% to $442.3 million, in each case compared to 2006 amounts. Production increased 12% to 10.6 MMBoe, due to increased production in our South Louisiana, Toledo Bend, and South Texas regions. We ended 2007 with domestic proved reserves of 133.8 MMBoe, an increase of 13% over year-end 2006 domestic reserves. We also had record revenues of $654.1 million for 2007, an increase of 19% over comparable 2006 levels. Our weighted average sales price received increased 8% to $61.49 per Boe for 2007 from $56.89 in 2006. Our $115.3 million, or 21%, increase in oil and gas sales revenues primarily resulted from both a 1.2 million Boe increase in production volumes and from 12% higher oil prices during 2007.
In October 2007, we acquired interests in three South Texas fields in the Maverick Basin from Escondido Resources, LP, which we collectively identify as the Cotulla properties. The total price for these interests was approximately $248.2 million after purchase price adjustments. The 12.9 MMBoe of proved reserves added through this acquisition are located in the Sun TSH field in La Salle County, the Briscoe Ranch field primarily in Dimmit County, and the Las Tiendas field in Webb County, of which 42% were proved undeveloped and which are predominantly natural gas and natural gas liquids. These properties added 0.3 MMBoe of production to our total production quantities for 2007. We plan to acquire more producing acreage in this area as well, and maintain a two rig drilling program in this area into 2008.
Our overall costs and expenses increased in 2007 by 35%. In 2008, we will continue to focus upon our capital efficiency to better manage our costs and expenses, a difficult task in the inflationary cost environment prevalent in the industry over the last several years. The largest increase in these costs and expenses in 2007 was attributable to 35% higher depreciation, depletion and amortization expense, not only due to our larger depletable property base and higher production, but also due to increases in future development costs, which reflect industry cost inflation. We expect cost pressures to continue to affect the industry throughout 2008, with tightening availability of crews as well as increasing costs of services, goods, and basic equipment.
Lake Washington is our most significant field and provides approximately 62% of our domestic production. In the fourth quarter of 2007, its production fell 13% from third quarter 2007 levels. In the fourth quarter of 2007, along with experiencing natural declines in production as our wells mature, we reduced the choke size of several wells in the Newport area to preserve reservoir pressure in anticipation of the pressure maintenance program that will commence with the Westside facility start-up by mid 2008. We continue to drill deeper wells, higher flowing pressure wells, and wells with higher associated natural gas content, and our system must also handle more mature wells that may produce larger volumes of water that require artificial lift. We believe the pressure maintenance activities planned for 2008 and Westside facility start-up by mid 2008 will improve the majority of these production constraints.
Our year-end 2007 domestic proved reserves were 44% crude oil, 43% natural gas, and 13% NGLs, compared to 52% crude oil, 38% natural gas, and 10% NGLs a year earlier, with 48% of our domestic proved reserves being proved developed at December 31, 2007. Our 2007 domestic production was 66% crude oil, down from 71% in 2006. Domestic proved reserves increased to 133.8 MMBoe at year-end 2007 from 118.4 MMBoe at year-end 2006.
Our financial position remains strong even with our recent increase in debt levels during the fourth quarter of 2007. Our debt to capitalization ratio was 41% at December 31, 2007, compared to 32% at year-end 2006, as debt levels increased in 2007, with debt per domestic Boe of $4.39 at year-end 2007 a 36% increase compared to $3.22 a year earlier. Our debt to domestic PV-10 ratio decreased to 15% at December 31, 2007 from 16% compared to a year earlier, as higher year-end reserves volumes and prices were largely offset by increased borrowings against our line of credit at that date.
Our capital expenditures from continuing operations of $650.6 million increased by $162.4 million from 2006 to 2007, primarily due to our acquisition of the Cotulla properties in South Texas and the increase in our spending on drilling and development, predominantly in our South Louisiana region. These expenditures were primarily funded by $442.3 million of cash provided by operating activities from continuing operations, and an increase in debt levels of $205.6 million.
Our current 2008 capital expenditure budget is $425 million to $475 million, net of minor non-core dispositions and excluding any property acquisitions. Based upon current market conditions and our estimates, our capital expenditures for 2008 should be within our anticipated cash flow from operations and currently we have budgeted approximately two-thirds of these amounts for our South Louisiana region, and on an overall basis three-fourths for developmental activities. For 2008, we are targeting production from our continuing operations to increase 10% to 15% and domestic proved reserves to increase 5% to 9% both over 2007 levels. We may also increase our capital expenditure budget if commodity prices rise during the year or if strategic opportunities warrant. If 2008 capital expenditures exceed our cash flow from operating activities, we can fund these expenditures with our credit facility.
During 2008, we plan to further develop our inventory of properties in South Louisiana using our expertise and experience gained in expanding and producing in Lake Washington, together with significant 3-D seismic information, to exploit our other prospect areas covered by similar geological features. This broad prospect inventory will allow us to be selective in choosing drilling opportunities so we can create long-life reserves while at the same time raising our production.
Results of Continuing Operations — Years Ended 2007, 2006, and 2005
Revenues.
Our revenues in 2007 increased by 19% compared to revenues in 2006 primarily due to increased production from our South Louisiana region and higher oil prices, and our revenues in 2006 increased by 55% compared to 2005 revenues due to increases in oil production from our South Louisiana area and increases in oil prices. Revenues for 2007, 2006, and 2005 were substantially comprised of oil and gas sales. Crude oil production was 66% of our production volumes in 2007, 71% in 2006, and 66% in 2005. Natural gas production was 26% of our production volumes in 2007, 24% in 2006, and 27% in 2005.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, 2007, 2006, and 2005:
Oil and Gas Sales (In Millions)
Net Oil and Gas Sales Volumes (MBoe)
2007
2006
2005
2007
2006
2005
1,517
872
8,139
89
10,617
Oil and gas sales in 2007 increased by 21%, or $115.3 million, from the level of those revenues for 2006, and our net sales volumes in 2007 increased by 12%, or 1.2 MMBoe, over net sales volumes in 2006. Average prices for oil increased to $71.92 per Bbl in 2007 from $64.28 per Bbl in 2006. Average natural gas prices were virtually unchanged at $6.42 per Mcf in 2007 compared to $6.44 per Mcf in 2006. Average NGL prices increased to $49.72 per Bbl in 2007 from $38.70 per Bbl in 2006.
In 2007, our $115.3 million increase in oil, NGL, and natural gas sales resulted from:
• Volume variances that had a $53.5 million favorable impact on sales, with $20.9 million of increases attributable to the 0.3 million Bbl increase in oil sales volumes, $12.1 million due to the 0.3 million Bbl increase in NGL sales volumes, and $20.5 million due to the 3.2 Bcf increase in natural gas sales volumes; and
• Price variances that had a $61.8 million favorable impact on sales, of which $53.8 million was attributable to the 12% increase in average oil prices received, and $8.5 million was attributable to the 28% increase in NGL prices, partially offset by a decrease of $0.5 million attributable to the $0.02 per Mcf decrease in natural gas prices.
Oil and gas sales in 2006 increased by 51%, or $181.6 million, from the level of those revenues for 2005, and our net sales volumes in 2006 increased by 32%, or 2.3 MMBoe, over net sales volumes in 2005. Average prices for oil increased to $64.28 per Bbl in 2006 from $53.45 per Bbl in 2005. Average natural gas prices decreased to $6.44 per Mcf in 2006 from $7.40 per Mcf in 2005. Average NGL prices increased to $38.70 per Bbl in 2006 from $34.00 per Bbl in 2005.
In 2006, our $181.6 million increase in oil, NGL, and natural gas sales resulted from:
• Volume variances that had a $119.7 million favorable impact on sales, with $107.5 million of increases attributable to the 2.0 million Bbl increase in oil sales volumes, and $13.8 million due to the 1.9 Bcf increase in natural gas sales volumes, partially offset by a decrease of $1.6 million due to the 48,000 Bbl decrease in NGL sales volumes; and
• Price variances that had a $61.9 million favorable impact on sales, of which $72.8 million was attributable to the 20% increase in average oil prices received and $2.2 million was attributable to the 14% increase in NGL prices, both slightly offset by a decrease of $13.1 million attributable to the 13% decrease in natural gas prices.
The following table provides additional information regarding our quarterly oil and gas sales from continuing operations excluding any effects of our hedging activities:
During 2007, 2006, and 2005, we recognized net gains of $0.2 million and $4.0 million and net losses of $1.1 million, respectively, related to our derivative activities. This activity is recorded in "Price-risk management and other, net" on the accompanying statements of income. Had these gains and losses been recognized in the oil and gas sales account, our average oil sales price would have been $71.91, $64.58, and $53.42 for 2007, 2006, and 2005, respectively, and our average natural gas sales price would have been $6.43, $6.59, and $7.32 for 2007, 2006, and 2005, respectively.
In 2006, we settled all insurance claims with our insurers relating to hurricanes Katrina and Rita for approximately $30.5 million and entered into a confidential final settlement agreement. The receipt of these amounts resulted in a benefit of $7.7 million in 2006 recorded in "Price-risk management and other, net," for the portion of the above referenced settlement, which we have determined to be non-property damage related claims. Approximately $22.8 million of the above referenced settlement was determined to be property damage related claims. We recorded $14.1 million of the property related settlement as a reduction to "Proved properties" on the accompanying consolidated balance sheet, as this related to reimbursement of capital costs we incurred. We also recorded $8.7 million of the property related settlement as a reduction to "Lease operating cost" on the accompanying consolidated statement of income, as this related to reimbursement of repair costs which had been expensed as incurred. In the accompanying consolidated statement of cash flows, we have recorded the reimbursement which reduced "Proved properties" as a reduction of "Cash Used in Investing Activities – continuing operations" and the remainder of the insurance settlement was recorded as an increase to "Cash Provided by Operating Activities – continuing operations."
Costs and Expenses.
Our expenses in 2007 increased $107.0 million, or 35%, compared to 2006 expenses for the reasons noted below.Our 2007 general and administrative expenses, net, increased $6.5 million, or 24%, from the level of such expenses in 2006, while 2006 general and administrative expenses, net, increased $8.8 million, or 46%, over 2005 levels. The increases in both 2007 and 2006 were primarily due to increased salaries and burdens associated with our expanded workforce, but were also impacted by increased restricted stock grants each year and the expensing of stock options that began in 2006. Costs also increased in 2007 due to ongoing support costs of our new computer system implemented in 2007. For the years 2007, 2006, and 2005, our capitalized general and administrative costs totaled $26.4 million, $24.1 million, and $14.5 million, respectively. Our net general and administrative expenses per Boe produced increased to $3.22 per Boe in 2007 from $2.92 per Boe in 2006 and $2.63 per Boe in 2005. The portion of supervision fees recorded as a reduction to general and administrative expenses was $11.8 million for 2007, $8.7 million for 2006, and $7.4 million for 2005.
DD&A increased $49.1 million, or 35%, in 2007, from 2006 levels and increased $58.1 million, or 72%, from 2005 levels. The increases in both years are due to increases in the depletable oil and natural gas property base, including future development costs, and higher production, partially offset by higher reserves volumes. Industry costs for services and goods have increased over the last three year period and have contributed to the increase in our DD&A expense. Our DD&A rate per Boe of production was $17.74 in 2007, $14.74 in 2006, and $11.31 in 2005, resulting from increases in per unit cost of reserves additions.
We recorded $1.4 million, $0.9 million, and $0.6 million of accretions to our asset retirement obligation in 2007, 2006, and 2005, respectively.
Our lease operating costs increased $20.9 million, or 42%, over the level of such expenses in 2006, while 2006 costs increased $15.0 million, or 43%, over 2005 levels. Lease operating costs increased during 2007 and 2006 due to higher production from our three domestic regions, including costs from properties acquired in the fourth quarters of 2006 and 2007, increasing costs for industry goods and services, and higher natural gas and NGL processing costs in 2007. A portion of the increase in 2007 and 2006 was from increased well insurance premiums which increased after hurricanes Katrina and Rita. Our lease operating costs per Boe produced were $6.68, $5.29, and $4.87 in 2007, 2006, and 2005, respectively.
Severance and other taxes increased $12.6 million, or 21%, over 2006 levels, while in 2006 these taxes increased $23.4 million, or 62%, over 2005 levels. The increases in each year were due primarily to higher commodity prices and increased production in our three domestic regions. Severance and other taxes, as a percentage of oil and gas sales, were approximately 11.3%, 11.4% and 10.6% in 2007, 2006 and 2005, respectively. 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 increased in 2006, the overall percentage of severance costs to sales also increased.
Our total interest cost in 2007 was $37.6 million, of which $9.5 million was capitalized. Our total interest cost in 2006 was $32.8 million, of which $9.2 million was capitalized. Our total interest cost in 2005 was $32.1 million, of which $7.2 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 $12.0 million in 2007 and $11.9 million in both 2006 and 2005. Interest expense on our 9-3/8% senior subordinated notes due 2012 issued in April 2002 and retired in 2007, including amortization of debt issuance costs, totaled $8.9 million in 2007 and $19.2 million in both 2006 and 2005. Interest expense on our 7-1/8% senior notes due 2017 and issued in June 2007, including amortization of debt issuance costs, totaled $10.6 million in 2007. Interest expense on our bank credit facility, including commitment fees and amortization of debt issuance costs, totaled $6.1 million in 2007, $1.5 million in 2006, and $1.0 million in 2005. Other interest cost was $0.1 million in each of 2007, 2006 and 2005. We capitalize a portion of interest related to unproved properties. The increase in interest expense in 2007 was primarily due to an increase in borrowings against our line of credit facility, partially offset by an increase in capitalized interest costs. The decrease in interest expense in 2006 was primarily due to an increase in capitalized interest costs, partially offset by an increase in borrowings against our line of credit facility.
In 2007 we incurred $12.8 million of debt retirement costs related to the redemption of our 9-3/8% senior notes due 2012. The costs were comprised of approximately $9.4 million of premiums paid to repurchase the notes, and $3.4 million to write-off unamortized debt issuance costs.
Our overall effective tax rate was 37.6% for 2007, 39.2% for 2006 and 37.3% for 2005. The effective tax rate for 2007 and 2006 was higher than the statutory rate primarily because of state income taxes and valuation allowances. For 2005, the effective tax rate was higher than the statutory rate primarily because of state income taxes.
Income from Continuing Operations. Our income from continuing operations for 2007 of $152.6 million was 1% higher than our 2006 income from continuing operations of $151.1 million due to higher oil prices and increased production, partially offset by increased costs including the retirement of our 9-3/8% senior notes due 2012.
Our income from continuing operations in 2006 of $151.1 million was 54% higher than our 2005 income from continuing operations of $97.9 million due to higher commodity prices and increased production.
Net Income.
Our net income in 2007 of $21.3 million was 87% lower than our 2006 net income of $161.6 million, mainly due to our loss from discontinued operations of $131.3 million. Our net income in 2006 of $161.6 million was 40% higher than our 2005 net income of $115.8 million due to higher oil prices and increased production.Discontinued Operations
In December 2007, Swift agreed to sell substantially all of our New Zealand assets for approximately $87.8 million. Accordingly, the New Zealand operations have been classified as discontinued operations in the consolidated statements of income and cash flows and the assets and associated liabilities have been classified as held for sale in the consolidated balance sheets. We began a strategic review of our New Zealand assets in the second quarter of 2007 which culminated in the agreement to sell substantially all of these assets in the fourth quarter of 2007, with an expected closing towards the end of the first quarter of 2008. Proceeds from the New Zealand assets sale will most likely be used to pay down a portion of our credit facility. We expect to sell the remaining New Zealand assets sometime in 2008.
In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-lived Assets" ("SFAS 144"), the results of operations and the non-cash asset write-down for the New Zealand operations have been excluded from continuing operations and reported as discontinued operations for the current and prior periods. Furthermore, the assets included as part of this divestiture have been reclassified as held for sale in the Balance Sheet for prior periods. During the fourth quarter of 2007, the Company assessed its long-lived assets in New Zealand based on the selling price and terms of the sales agreement and recorded a non-cash asset write-down of $143.2 million related to these assets. This write-down is recorded in "Income (loss) from discontinued operations, net of taxes" on the accompanying statement of income.
As of December 31, 2007, operations in New Zealand had represented approximately 6% of our total assets and 12% of our 2007 sales volumes. These revenues and expenses were historically reported under our New Zealand operating segment and are now reported under discontinued operations. The following table summarizes selected data pertaining to discontinued operations (in thousands except per share and per Boe amounts):
$ 42,394 $ 64,039 $ 67,894 1,221 862 999 43,615 64,901 68,893 23,147 30,051 26,354 22,491 20,872 20,230 143,152 --- --- 188,790 50,923 46,584 (145,175 ) 13,978 22,309 (13,874 ) 3,487 4,412 $ (131,301 ) $ 10,491 $ 17,898 $ (4.29 ) $ 0.35 $ 0.61 1,387