Previous Section
    Next Section
    Table of Contents
    Financials
    PDF

Other Related Menus
    10Q Filings
    10K Filings
    SEC Filings
    1997 Annual Report
         

FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 1997

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

 

The following discussion should be read in conjunction with the Company's Consolidated Financial Statements and Notes thereto.

General

 

Swift Energy Company’s principal corporate objectives are the accumulation of crude oil and natural gas reserves for current and future production and sale and the enhancement of the net present value of those reserves. The Company was formed in 1979 and from 1985 to 1991 grew primarily through the acquisition of producing properties funded through limited partnership financing. Commencing in 1991, the Company began to reemphasize the addition of reserves through increased exploration and development drilling activity. This emphasis on exploration and development drilling has led to additions of increasing quantities of reserves in each of the years 1995, 1996, and 1997. The Company’s revenues are primarily comprised of oil and gas sales attributable to properties in which the Company owns a direct or indirect interest.

The statements contained in this Annual Report on Form 10-K ("Annual 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, and therefore involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, 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," "budget," "estimate," "expect," "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 and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and the Company’s financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on behalf of the Company, including those regarding the Company’s financial results, levels of oil and gas production or revenues, capital expenditures, and capital resource activities. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for the Company’s oil and natural gas; the uncertainty of drilling results and reserve estimates; operating hazards; requirements for capital; general economic conditions; competition and government regulations; as well as the risks and uncertainties discussed in this Annual Report, including, without limitation, the portions referenced above and the uncertainties set forth from time to time in the Company’s 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.

Proved Oil and Gas Reserves. In 1997, the Company’s proved natural gas reserves increased 88.5 Bcf (39%) and its proved oil reserves increased 2,374,609 barrels (43%) or a total of 102.8 Bcfe. From 1995 to 1996, the Company’s proved natural gas reserves increased 82.2 Bcf (57%) and its proved oil reserves increased 62,328 barrels (1%). The Company’s additions to proved reserves from its exploration and development program were 120.2 Bcfe in 1997, 118.2 Bcfe in 1996, and 72.4 Bcfe in 1995. A substantial portion of these reserves are proved undeveloped reserves comprising 144.6 Bcfe or 40% of total proved reserves at year end 1997, 101.5 Bcfe or 39% of total proved reserves at year end 1996, and 74.7 Bcfe or 42% of total proved reserves at year end 1995. This reflects the emphasis on exploration and development activities.

Proved developed reserves additions in 1997 resulted from drilling activity (which also increased undeveloped reserves) and the purchases of minerals in place, offset somewhat by revisions of previous estimates. The change in the Standardized Measure of Discounted Future Net Cash Flows (see Supplemental Information to the Company’s financial statements) and in the Estimated Present Value of Proved Reserves (see page 7—"Oil and Gas Reserves") from year end 1996 to year end 1997 is also due to the addition of reserves through the Company’s drilling activity (primarily in the AWP Olmos Field and the Austin Chalk trend) and the purchases of minerals in place (primarily in the AWP Olmos Field), offset by revisions of previous estimates and by the 38% decrease in year end 1997 natural gas prices ($2.78 per Mcf versus $4.47 per Mcf at year end 1996), and to the 34% decrease in year end 1997 oil prices ($15.76 per Bbl at year end 1997, compared to $23.75 per Bbl a year earlier). While the Company’s total proved reserves quantities at year end 1997 increased by 40% over reserves quantities a year earlier, the PV-10 Value of those reserves decreased 26% from the PV-10 Value at year end 1996. This decrease was almost totally due to the high product prices at year end 1996 detailed above. If the PV-10 Value as of year end 1997 had been calculated using the same prices in effect a year earlier, there would have been an increase in PV-10 Value from year end 1996 to year end 1997 comparable to the 40% increase in the Company’s total proved reserves quantities during that same period.

Under the Securities and Exchange Commission guidelines, the Company’s estimates of cash flows from proved reserves are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including, in the case of gas contracts, the use of fixed and determinable contractual price escalations. The $2.78 per Mcf and the $15.76 per barrel were prices in effect as of year end 1997 and may not be indicative of future sales prices received.

 

Liquidity and Capital Resources

 

During the first ten months of 1996, the Company relied upon internally generated cash flows and bank borrowings to fund its capital expenditures, and thereafter upon net proceeds from its $115.0 million public offering of 6.25% Convertible Subordinated Notes due 2006 and its internally generated cash flows, along with $7.9 million of bank borrowings in the closing weeks of 1997, all as described below. Cash and working capital in 1998 are expected to be provided through internally generated cash flows, bank borrowings, and debt and/or equity financing.

Net Cash Provided by Operating Activities. In 1997, 1996, and 1995, the Company’s operating activities provided net cash of $55.3 million, $37.1 million, and $14.4 million, respectively. These increases were primarily due to increased production volumes, as discussed below. The 1997 increase of $18.2 million was primarily due to an increase in cash flows from oil and gas sales, which increased $16.5 million (32%), exclusive of the non-cash amortization of deferred revenues associated with the Company’s volumetric production payment. The 1996 increase of $22.7 million in net cash from operations was primarily due to the cash flows from oil and gas sales, which increased $30.4 million (146%), exclusive of the non-cash amortization of deferred revenues associated with the Company’s volumetric production payment, partially offset by a $1.6 million increase in oil and gas production costs, a $1.1 million increase in general and administrative costs, plus changes to assets and liabilities and deferred income taxes. These 1997 and 1996 increases in oil and gas sales were primarily the result of the Company’s increased drilling activity, as well as being affected by product price fluctuations, as described below.

Sale of Convertible Subordinated Notes. In November 1996, the Company issued $115.0 million of 6.25% Convertible Subordinated Notes due November 15, 2006, in a public offering. Proceeds of the offering were used for repayment in full of all the Company’s bank borrowings ($33.1 million on November 25, 1996) and, together with internally generated cash flows, to fund capital expenditures through 1997 and working capital needs. The principal terms of these Notes are more fully described in Note 4 to the Company’s financial statements.

Other Financing Activities. During the third quarter of 1995, the Company sold 5.75 million shares of common stock in a public offering at $8.50 per share, with net proceeds of $45.7 million principally used to repay outstanding indebtedness and finance the Company’s exploration and development activities. As described in Note 4 to the Company’s financial statements included herein, in August 1996 the $28.75 million of 6.5% Convertible Debentures sold in 1993 were converted by their holders into 2.34 million shares of the Company’s common stock following the Company’s July 1996 announcement of their redemption. As a result of this conversion, the Company’s stockholders’ equity increased approximately $27.65 million.

Credit Facilities. In the first ten months of 1996 and in the closing weeks of 1997, the Company’s credit facilities have been used to fund a portion of the Company’s exploration and development activities. Currently, these credit facilities consist of a $100.0 million unsecured revolving line of credit with a $40.0 million borrowing base and a $7.0 million secured revolving line of credit with a $5.5 million borrowing base. The principal terms and restrictions of these credit facilities are described in Note 4 to the Company’s financial statements included herein.

At December 31, 1997, the Company had outstanding borrowings of $7,915,000 under the credit facilities. At December 31, 1996, and until mid-December 1997, the Company had no outstanding balances under these borrowing arrangements, since the balance of those borrowings was repaid in November 1996 with proceeds from the Company’s public sale of $115.0 million of 6.25% Convertible Subordinated Notes.

Partnership Programs. Since late 1993, the Company has offered private partnerships formed to drill for oil and gas. During 1997, the Company formed three drilling partnerships with subscriptions of approximately $16.8 million and in 1996 formed three partnerships with subscriptions of approximately $22.0 million. The Company anticipates that it will continue to offer such drilling partnerships for the foreseeable future.

At December 31, 1997, limited partnership formation and marketing costs (which under the current drilling partnership offerings are borne by the Company as part of the Company’s general partner contribution) amounted to $297,000, a decrease of $213,000 when compared with the balance at December 31, 1996.

During 1996, the limited partners in 18 partnerships, which had been in operation over nine years and had produced a substantial majority of their reserves, voted to sell their remaining properties and liquidate the limited partnerships. Of these partnerships, 10 were the earliest public income partnerships (formed in 1984 to 1986) and were liquidated in 1996, and in early 1997 eight private drilling partnerships (formed in 1979 to 1985) were liquidated. During 1997, the limited partners in an additional 11 partnerships, formed in 1990 and 1991, voted to sell their properties and liquidate the limited partnerships, which liquidation is expected in early 1998. As the public income partnerships formed since 1986 grow older, it is anticipated that proposals will continue to be made to the investors in those partnerships to sell their properties and liquidate the partnerships.

Working Capital. The Company’s working capital has decreased from $68.7 million at December 31, 1996, to $1.5 million at December 31, 1997. This decrease is primarily the result of the Company’s capital expenditures as described below.

Since year end 1996, the Company’s receivable account from limited partnerships and its receivable account from joint interest owners increased $1.8 million and $4.3 million, respectively, due to the increase in drilling activity between the periods.

Due to the nature of the Company’s business highlighted above, the individual components of working capital fluctuate considerably from period to period. The Company incurs significant working capital requirements in connection with its role as operator of approximately 650 wells, its accelerated drilling programs, and the management of affiliated partnerships. In this capacity, the Company is responsible for certain day-to-day cash management, including the collection and disbursement of oil and gas revenues and related expenses.

Common Stock Repurchase Program. In March 1997, the Company’s Board of Directors approved a common stock repurchase program for up to $20.0 million of the Company’s common stock and subsequently extended the program through June 30, 1998. Purchases of shares are made in the open market. Under this program, through December 31, 1997, the Company used $8.52 million of working capital to acquire 387,800 shares at an average cost of $21.97 per share.

Common Stock Dividend. In October 1997, the Company declared a 10% stock dividend to shareholders of record. The transaction was valued based on the closing price ($28.8125) of the Company’s common stock on the New York Stock Exchange on October 1, 1997. As a result of the issuance of 1,494,606 shares of the Company’s common stock as a dividend, retained earnings were reduced by $43,063,335, with the common stock and additional paid-in capital accounts increased by the same amount.

Capital Expenditures. The Company’s capital expenditures were approximately $132.0 million, $91.5 million, and $40.0 million for 1997, 1996, and 1995, respectively. The 1997 capital expenditures included (a) $90.3 million (68% of 1997 capital expenditures) on developmental drilling (primarily in the AWP Olmos Field and Austin Chalk trend), (b) $10.7 million (8%) on exploratory drilling, (c) $18.4 million (14%) on domestic prospect costs (principally prospect leasehold, seismic, and geological costs of unproven prospects for the Company’s account), (d) the purchase of $8.4 million (6%) of producing property interests, $7.1 million from third parties (primarily in the AWP Olmos Field), along with the purchase of $1.3 million of limited partner interests in previously formed partnerships through the right of presentment arrangement provided in those partnerships, (e) $3.2 million (3%) invested in foreign business opportunities in Russia ($0.7 million), Venezuela ($0.8 million), and New Zealand ($1.7 million), as described in Note 8 to the Company’s financial statements, and (f) $0.9 million (1%) spent on fixed assets. In 1997, the Company participated in drilling 182 wells (15 exploratory and 167 development wells with 7 exploratory successes and 159 development successes). The steady growth in the Company’s unproved property account ($41.8 million), which is not being amortized, is indicative of the shift to a focus on drilling activity as the Company acquires prospect acreage, including $3.2 million of capital expenditures in 1997 made in relation to the Company’s foreign business opportunities, as described above.

Capital expenditures for 1998 are estimated to be approximately $154.8 million, including investments in all areas in which 1997 capital was spent. Approximately $123.9 million of the 1998 budget is allocated to exploration and development drilling, with approximately 73% of this amount to be spent in the Company’s two primary development areas in Texas. The Company’s plan anticipates drilling 113 development and 21 exploratory wells in 1998.

The Company believes that 1998’s anticipated internally generated cash flows (expected to increase as the Company’s production base increases as a result of its accelerated drilling program), together with the existing credit facilities, will be sufficient to finance the costs associated with its currently budgeted 1998 capital expenditures.

Results of Operations

 

Revenues. The Company’s revenues in 1997 increased by 32% over revenues in 1996 and by 110% in 1996 over 1995 revenues, principally due to increases in oil and gas sales revenues.

Oil and Gas Sales. The Company’s net sales volumes in 1997 (including the volumetric production payment associated with each year’s production) increased by 31% (6.0 Bcfe) over net sales volumes in 1996, while 1996 net sales volumes increased by 74% (8.3 Bcfe) over net sales volumes in 1995. Oil and gas sales revenues in 1997 increased by 31% ($16.2 million) over those revenues for 1996, while in 1996 those revenues increased by 134% ($30.2 million) over oil and gas sales in 1995. Average prices for oil increased from $15.66 per Bbl in 1995 to $19.82 per Bbl in 1996 and then decreased to $17.59 per Bbl in 1997, while average gas prices increased from $1.77 per Mcf in 1995 to $2.57 per Mcf in 1996 and to $2.68 per Mcf in 1997. The Company’s $16.2 million increase in oil and gas sales during 1997 was comprised of volume increases that added $14.5 million of sales from the 5.7 Bcf increase in gas sales volumes and $1.0 million of sales from the 49,000 barrel increase in oil sales volumes, while price variances contributed $2.2 million in increased sales from the increase in average gas prices received, offset somewhat by a $1.5 million decrease in sales from the decrease in average oil prices received. The Company’s $30.2 million increase in oil and gas sales during 1996 was comprised of volume increases that added $13.8 million of sales from the 7.8 Bcf increase in gas sales volumes and $1.2 million of sales from the 78,000 barrel increase in oil sales volumes, while price variances contributed $12.7 million in increased sales from the increase in average gas prices received and $2.5 million in increased sales from the increase in average oil prices received.

The increases in oil and gas sales for 1997 and 1996 were primarily the result of production from the Company’s accelerated drilling program, most notably from the Company’s two primary development areas, the AWP Olmos Field and the Austin Chalk trend. The Company’s 1997 oil and gas sales from the AWP Olmos Field were $42.2 million ($29.9 million in 1996) from 15.5 Bcfe of net sales volumes (11.2 Bcfe in 1996) for an increase of 4.3 Bcfe, while the Austin Chalk trend generated 1997 oil and gas sales of $12.9 million ($9.4 million in 1996) from 4.9 Bcfe of net sales volumes (3.4 Bcfe in 1996) for an increase of 1.5 Bcfe.

Revenues from oil and gas sales comprised 86%, 87%, and 78%, respectively, of total revenues for 1997, 1996, and 1995. The majority (83%, 77%, and 62%, respectively) of these oil and gas revenues in these periods were derived from the sale of the Company’s gas production. The Company expects oil and gas sales to continue to increase as a direct consequence of the addition of oil and gas reserves through the Company’s active drilling program.

Average prices received from oil and gas production can have a dramatic impact on the Company’s oil and gas sales revenues. This is evident not only in the yearly comparisons as described above but also when comparing fourth quarter 1997 revenues to those for the fourth quarter of 1996. While oil and gas production volumes increased 1.0 Bcfe (17%) during the fourth quarter of 1997 when compared to the fourth quarter of 1996, oil and gas sales increased only $1.1 million (6%) due to average oil prices received being 25% lower and average gas prices received being 6% lower than in the fourth quarter of 1996.

Supervision Fees. These fees continue to increase, having grown from $3.8 million in 1995 to $4.5 million in 1996 to $5.2 million in 1997, primarily due to the annual escalation in well overhead rates and the increase in drilling activity by the Company, which in turn increases the drilling well overhead portion of such fees paid to the Company as operator of these wells.

Costs and Expenses. General and administrative expenses in 1997 decreased $0.3 million (4%) from the level of such expenses in 1996, while 1996 general and administrative expenses increased $1.1 million (21%) over 1995 levels. The slight decrease in these costs in 1997 over 1996 reflected the Company’s ability to continue increasing its drilling activity without increasing such costs in 1997. The increase in costs in 1996 over 1995 reflected the increase in the Company’s activities. The Company’s general and administrative expenses per Mcfe produced have decreased in each of the past three years from $0.47 per Mcfe produced in 1995 to $0.33 per Mcfe produced in 1996 to $0.24 per Mcfe produced in 1997. The majority of the companies in the oil and gas industry treat supervision fees as a reduction of their general and administrative expenses. If the Company were to follow this practice, these expenses net of supervision fees would have decreased to $0.13 per Mcfe produced in 1995, $0.10 per Mcfe produced in 1996, and $0.04 per Mcfe produced in 1997.

Depreciation, depletion, and amortization (DD&A) has steadily increased, primarily due to the Company’s reserves additions and associated costs and to the related sale of increased quantities of oil and gas produced therefrom. The Company’s DD&A rate per Mcfe of production was $0.79 in 1995, $0.85 in 1996, and $0.95 in 1997, reflecting variations in the per unit cost of reserves additions.

Production costs in 1997 increased $3.0 million (36%) over such expenses in 1996, while those expenses in 1996 increased $1.6 million (23%) over 1995. The increases in each of the periods primarily relate to the increase in the Company’s oil and gas sales volumes. The Company’s production costs per Mcfe produced were $0.45 in 1997, $0.43 in 1996, and $0.61 in 1995. As discussed above, the Company’s increase in production is primarily through its drilling activities in the AWP Olmos Field and Austin Chalk trend, where the Company already has an established operating base. The increase in production costs has been partially offset by an exemption in these same fields from the 7.5% Texas severance tax applicable to gas production from certain natural gas wells certified to be in tight formations or to be deep wells by the Texas Railroad Commission. This exemption in 1996 was a major contributor in reducing the Company’s production costs per Mcfe produced from the 1995 rate of $0.61 to the 1996 rate of $0.43. Additionally, commencing September 1, 1996, certain wells certified as "high cost gas" wells are entitled to a reduction of severance tax based upon a formula amount but not the full exemption of 7.5% received on certified wells drilled prior to September 1, 1996. This tax exemption has had a positive impact on the Company’s production costs during 1996 and 1997, although under the new rules, the proportionate amount of the exemption was decreased in the 1997 period, thus contributing to the $0.02 increase in production costs per Mcfe produced in 1997 when compared to 1996.

Interest expense in 1997 on the Notes, including amortization of debt issuance costs, totaled $7.5 million, compared to $0.7 million on the Notes and $1.0 million on the Debentures in 1996 and $2.0 million on only the Debentures in 1995, while interest expense on the credit facilities, including commitment fees, totaled $0.1 million ($1.1 million in 1996 and $1.7 million in 1995), for a 1997 total of $7.6 million (of which $2.6 million was capitalized). The 1996 total was $2.8 million (of which $2.1 million was capitalized), while the 1995 total was $3.7 million (of which $2.6 million was capitalized). The Company capitalizes a portion of interest related to certain exploration, partnership, and foreign business development activities. The increase in interest expense in 1997 is attributable to the larger outstanding principal amount on the Notes ($115.0 million) compared to the Debentures ($28.75 million), offset to some degree by larger outstanding balances under the Company’s credit facilities in 1996 and by the $2.4 million in interest income earned in 1997 on the portion of the net proceeds of the Notes invested pending use. The lower amount of interest expense in 1996, compared to 1995 was attributable to a smaller average balance under the Company’s credit lines necessary to finance the Company’s capital expenditures, as well as to paying only six months of interest on the Debentures as they were converted into common stock in the third quarter of 1996.

Net Income. Net income of $22.3 million and earnings per share of $1.35 for 1997 were 17% and 6% higher, respectively, than net income of $19.0 million and earnings per share of $1.27 in 1996. This increase in net income primarily reflected the effect of a 31% increase in oil and gas sales revenues as a result of a 36% increase in natural gas production, an 8% increase in crude oil production, and a slight 4% increase in gas prices received, offset somewhat by an 11% decrease in oil prices received. The lower percentage increase in earnings per share reflects a 10% increase in weighted average shares outstanding in 1997 as a result of the conversion of the Debentures into 2.34 million shares of common stock in the third quarter of 1996. The Company’s consolidated effective tax rate was 32.7%, 33.9%, and 28.7% in 1997, 1996, and 1995, respectively.

Net income of $19.0 million and earnings per share of $1.27 for 1996 were 287% and 159% higher, respectively, than net income of $4.9 million and earnings per share of $0.49 in 1995. This increase in net income primarily reflected the effect of a 134% increase in oil and gas sales revenues as a result of a 98% increase in natural gas production, a 14% increase in crude oil production, and product price improvements. The lower percentage increase in earnings per share reflects a 49% increase in weighted average shares outstanding for 1996 as a result of the sale of 5.75 million shares of common stock in the third quarter of 1995 and the conversion of the Debentures into 2.34 million shares of common stock in the third quarter of 1996.

Year 2000. A comprehensive assessment of the year 2000 issue has been conducted and a compliance plan is currently underway. The Company is in the process of receiving verification of year 2000 compliance from all hardware and software vendors. The Company does not expect that the cost to modify its information technology infrastructure will be material to its financial condition or results of operation. The Company also does not anticipate any material disruption in its operations as a result of any year 2000 compliance issues.


This page was last updated on Saturday, February 08, 2003, at 07:46:29 PM.

Copyright © 1994-2008 by Swift Energy Company.
Click here to go to our home page or search page.
Please note the terms of use for the Swift Energy web site.
If you have comments or questions, see our feedback or requests pages.
Contact Swift Energy Company Stockholder Relations through e-mail info@swiftenergy.com or telephone (281) 874-2700.