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    1996 Annual Report
         

FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 1996

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 1994, 1995, and 1996.

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. Additionally, prior to 1994, the Company recorded earned interests and fees from limited partnerships and joint ventures. Earned interests represented revenues in the form of interests in proved developed oil and gas properties conveyed to limited partnerships and joint ventures formed in connection with the Company’s organization and management of limited partnerships and joint ventures, representing the difference between the Company’s capital contributions to each limited partnership or joint venture and its earned revenue interest in the limited partnership’s or venture’s properties (based upon the expected levels of cash distributions to the limited partners or joint ventures). Effective January 1, 1994, the Company changed its revenue recognition policy for earned interests. The cumulative effect in 1994 of this change in accounting principle resulted in a one-time accounting adjustment of $16.8 million, or a loss of $2.52 per share (after reduction for income taxes of $8.6 million), from applying the new method retroactively. Under the Company’s current method of accounting, such amounts will not be recognized as income, thereby reducing the Company’s investment in oil and gas property. The Company believes the change in policy results in financial statements that better reflect its business focus and that are more comparable to prevalent practices in the oil and gas exploration and production industry.

In May 1992, the Company purchased interests in certain wells from the Manville Corporation for $14.3 million using funds provided by the Company’s sale of a volumetric production payment in these properties to a subsidiary of Enron Corp. Net proceeds from the sale of the production payment of approximately $13.8 million were recorded as deferred revenues. Deliveries under the volumetric production payment are recorded as oil and gas sales revenues which are offset by a corresponding reduction of deferred revenues. Under this arrangement, the Company is required to deliver a fixed quantity of hydrocarbons produced from the properties over specified periods through October 2000. Volumes remaining to be delivered under the volumetric production payment (approximately 3.0 Bcfe) are not included in the Company’s proved reserves. Under the volumetric production payment, hydrocarbons produced in excess of the amount required to be delivered are sold by the Company for its own account.

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. The actual results of the future events described in such forward-looking statements in this Annual Report, including those regarding the Company’s financial results, levels of oil and gas production or revenues, capital expenditures, and capital resource activities, could differ materially from those estimated. Among the factors that could cause actual results to differ materially are: general economic conditions, competition and government regulations, and fluctuations in oil and natural gas prices, as well as the risks and uncertainties set forth from time to time in the Company’s other public reports, filings, and public statements.

Proved Oil and Gas Reserves. From 1994 to 1995, the Company’s proved natural gas reserves increased 67.3 Bcf (88%) and its proved oil reserves increased 868,714 barrels (19%). In 1996, the Company’s proved natural gas reserves increased 82.2 Bcf (57%) and its proved oil reserves increased 62,328 barrels (1%). As detailed in Note 9 to the Company’s financial statements, the composition of these reserves has shifted, with proved undeveloped reserves comprising 37.9 Bcfe or 37% of total proved reserves at year end 1994, 74.7 Bcfe or 42% of total proved reserves at year end 1995, and 101.5 Bcfe or 39% of total proved reserves at year end 1996. This shift reflects the increased portion of the Company’s reserves generated by recent exploration and development activities, resulting in additions of substantial proved undeveloped reserves. The Company’s additions to proved reserves from its exploration and development program were 118.2 Bcfe in 1996, 72.4 Bcfe in 1995, and 24.8 Bcfe in 1994.

Proved developed reserves additions in 1996 resulted from drilling activity (which increased undeveloped reserves to a much larger degree), revisions of previous quantities estimates and higher year end 1996 prices. The increase in the Standardized Measure of Discounted Future Net Cash Flows (see Note 9 to the Company’s financial statements) and in the Estimated Present Value of Proved Reserves (see Form 10-K Excerpts--"Oil and Gas Reserves") from year end 1995 to year end 1996 is due to the addition of reserves through the Company’s drilling activity (primarily in the AWP Olmos Field and the Austin Chalk trend), to the 85% increase in year end 1996 natural gas prices ($4.47 per Mcf versus $2.41 per Mcf at year end 1995), and to the 31% increase in year end 1996 oil prices ($23.75 per Bbl at year end 1996, compared to $18.07 per Bbl a year earlier).

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 $4.47 per Mcf and the $23.75 per barrel were prices in effect as of year end 1996 and may not be indicative of future sales prices received.

 

Liquidity and Capital Resources

 

In 1991, the Company’s strategy shifted toward an increased reliance on exploration and development activities, and the Company has significantly expanded reserves added through these efforts. Previously, the Company relied on limited partnership capital as its principal financing vehicle to fund its acquisitions of producing properties. As a result of this shift in strategy, the Company has reduced its reliance on cash flows generated from and capital raised through limited partnerships. Cash and working capital are provided through internally generated cash flows and debt and equity financing.

During the first half of 1995, the Company used a combination of bank financing, internally generated cash flows, and partnership financing to fund its operations. In the third quarter of 1995, the Company realized $45.7 million in net proceeds from an offering of common stock that provided sufficient capital to repay its bank financing and finance its capital expenditures for the second half of 1995. During the first ten months of 1996, the Company relied upon internally generated cash flows and bank borrowings to fund its capital expenditures. In November 1996, the Company realized $110.45 million in net proceeds from an offering of 6.25% Convertible Subordinated Notes due 2006 that provided sufficient capital to repay the Company’s bank financing and finance its capital expenditures during the remainder of 1996 and is expected to provide, along with internally generated cash flows, for capital expenditures and working capital needs through 1997. Described below are the major elements of the Company’s liquidity and capital resources.

Net Cash Provided by Operating Activities. In 1996, 1995, and 1994, the Company’s operating activities provided net cash of $37.1 million, $14.4 million, and $10.4 million, respectively. These increases were primarily due to increased production volumes and higher product prices, as discussed below. 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 and a $1.1 million increase in general and administrative costs. This increase in oil and gas sales was primarily the result of the Company’s recent increase in drilling activity and product price increases as described below. The 1995 increase of $4.0 million was primarily due to an increase in cash flows from oil and gas sales, which increased $2.9 million (16%), exclusive of the non-cash amortization of deferred revenues associated with the Company’s volumetric production payment. During 1995, the Company also had a $.7 million increase in other revenues, and a $.7 million decrease in interest expense, partially offset by a $1.2 million increase in oil and gas production costs.

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 for capital expenditures for the remainder of 1996, with the remainder of the proceeds to be used, along with internally generated cash flows, to fund capital expenditures and working capital needs. The principal terms of these Notes are more fully described in Note 5 to the Company’s financial statements.

1995 Stock Offering. 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.

Other Financing Activities. On June 30, 1993, the Company issued the 6.5% Convertible Subordinated Debentures due 2003 in the amount of $28.75 million in a public offering. Proceeds of the offering were used primarily to acquire producing oil and gas properties and to finance the Company’s expanding exploration and development program. As described in Note 5 to the Company’s financial statements included herein, in August 1996 the 6.5% Convertible Subordinated Debentures were converted by their holders into 2.34 million shares of the Company’s common stock following the Company’s July 1996 announcement that the 6.5% Debentures would be redeemed in August 1996, unless earlier converted. As a result of this conversion, the Company’s stockholders’ equity increased approximately $27.65 million.

Credit Facilities. Recently, the Company’s credit facilities have been used to fund a portion of the Company’s exploration and development activities. Formerly, the Company established credit facilities which were used principally to finance the Company’s purchase of producing oil and gas properties on an interim basis pending transfer of the properties to newly formed partnerships and joint ventures and to provide working capital. These credit facilities consist of a $100.0 million unsecured revolving line of credit with a $5.0 million borrowing base and a $7.0 million secured revolving line of credit with a $2.0 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, 1996, the Company had no outstanding balances under these borrowing arrangements, since those borrowings were repaid with proceeds from the Company’s 6.25% Convertible Subordinated Notes offering in 1996. The borrowings since year end 1995 were used, along with internally generated cash flows, principally to fund the Company’s 1996 capital expenditures described below. At December 31, 1995, the Company also had no outstanding balances under these borrowing arrangements, since those borrowings were repaid with proceeds from the Company’s 1995 stock offering.

Partnership Programs. Between 1991 and 1995, the Company offered interests in oil and gas production partnerships under its Swift Depositary Interests ("SDI") offering, and since late 1993 has offered private partnerships formed to drill for oil and gas. The SDI program concluded at the end of 1995. Four SDI partnerships were formed during 1995, with total subscriptions of approximately $12.4 million, compared to $32.1 million raised in eight 1994 SDI partnerships. In 1996, three drilling partnerships were formed, with total subscriptions of approximately $22.0 million compared to $15.9 million of subscriptions raised in three drilling partnerships in 1995 and $2.6 million raised in one partnership in 1994. The Company anticipates that it will continue to offer the drilling partnerships for the foreseeable future.

At December 31, 1996, 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 $511,000, a decrease of $348,000 when compared with the balance at December 31, 1995. Upon the Company’s decision to conclude the SDI offering in December 1995, the remaining limited partnership formation and marketing costs related to the SDI offering (approximately $1.75 million) were transferred to the oil and gas properties account.

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. In 1996, 10 of the earliest public income partnerships were liquidated, and in early 1997 eight private drilling partnerships will be liquidated. The Company intends to make similar proposals to other partnerships for an orderly sale of their properties and liquidation of the partnerships over the next several years. The Company may offer to acquire certain portions of the remaining property interests owned by these limited partnerships.

Working Capital. The Company’s working capital increased significantly from $3.2 million at December 31, 1995, to $68.7 million at December 31, 1996. This increase is primarily the result of the receipt of net proceeds from the 6.25% Convertible Subordinated Notes offerings in November 1996.

Since year end 1995, the Company’s receivable account from limited partnerships decreased significantly due to (a) repayments made with funds generated from property sales proceeds realized by these partnerships and (b) an increase in oil and gas prices received by these partnerships. Both of these increased the cash flows of the partnerships, thus allowing them to reduce their balances owed to the Company.

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 840 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.

Capital Expenditures. The Company’s capital expenditures were approximately $91.5 million, $40.0 million, and $34.5 million for 1996, 1995, and 1994, respectively. The 1996 capital expenditures included (a) $69.1 million (75% of 1996 capital expenditures) on developmental drilling (primarily in the AWP Olmos Field and Austin Chalk trend), (b) $2.7 million (3%) on exploratory drilling, (c) $12.7 million (14%) on prospect costs (principally prospect leasehold, seismic and geological costs of unproven prospects for the Company’s account), (d) the purchase of $1.5 million (2%) of limited partner interests in previously formed partnerships through the right of presentment arrangement provided in those partnerships, (e) $3.7 million (4%) invested in foreign business opportunities in Russia ($2.7 million), in Venezuela ($0.5 million), and in New Zealand ($0.5 million), as described in Note 9 to the Company’s financial statements, and (f) $1.8 million (2%) spent on fixed assets. In 1996, the Company participated in drilling 153 wells (11 exploratory and 142 development wells with 7 exploratory successes and 134 development successes). The steady growth in the Company’s unproved property account, which is not being amortized, is indicative of the shift to a focus on drilling activity, as the Company acquires prospect acreage. This unproved property account also reflects $3.7 million of capital expenditures in 1996 made in relation to the Company’s foreign business opportunities, as described above.

Capital expenditures for 1997 are estimated to be approximately $113.0 million, including investments in all areas in which 1996 capital was spent. Approximately $85.0 million of the 1997 budget is allocated to exploration and development drilling, with approximately 83% to be spent in the Company’s two primary development areas in Texas. The Company’s plan anticipates drilling 158 development and 20 exploratory wells in 1997.

The Company believes that 1997’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 remainder of the net proceeds from the November 1996 Convertible Subordinated Notes offering, will be sufficient to finance the costs associated with its 1997 budgeted capital expenditures. Further liquidity needs may also be met by its existing credit facilities.

Results of Operations

 

Revenues. The Company’s revenues in 1996 increased by 110% over revenues in 1995 and by 14% in 1995 over 1994 revenues, principally due to increases in oil and gas sales revenues.

Oil and Gas Sales. The Company’s net sales volumes in 1996 (including the volumetric production payment associated with each year’s production) increased by 74% (8.3 Bcfe) over net sales volumes in 1995, while 1995 net sales volumes increased by 17% (1.6 Bcfe) over net sales volumes in 1994. Combined oil and gas sales revenues in 1996 increased by 134% ($30.2 million) over those revenues for 1995, while in 1995 those revenues increased by 14% ($2.7 million) over oil and gas sales in 1994. Average prices for oil increased from $14.35 per Bbl in 1994 to $15.66 per Bbl in 1995 and to $19.82 per Bbl in 1996, while average gas prices decreased from $1.93 per Mcf in 1994 to $1.77 per Mcf in 1995 and then rose significantly to $2.57 per Mcf in 1996. The Company’s $30.2 million increase in oil and gas sales during 1996 was comprised of volume variances of $13.8 million from the 7.8 Bcf increase in gas sales volumes and $1.2 million from the 78,000-barrel increase in oil sales volumes, while price variances contributed $12.7 million from the increase in average gas prices received and $2.5 million from the increase in average oil prices received.

The increase in oil and gas sales for 1996 was 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 1996 oil and gas sales from the AWP Olmos Field were $29.8 million ($5.3 million in 1995) from 11.1 Bcfe of net sales volumes (3.4 Bcfe in 1995) for an increase of 7.7 Bcfe, while the Austin Chalk trend generated oil and gas sales of $10.1 million ($4.4 million in 1995) from 3.6 Bcfe of net sales volumes (2.1 Bcfe in 1995) for an increase of 1.5 Bcfe.

The increase in oil and gas sales for 1995 was also primarily the result of the Company’s development drilling in the AWP Olmos Field and the Austin Chalk trend. The Company began drilling on additional acreage adjacent to its original leasehold acreage in the AWP Olmos Field during the second quarter of 1995, which resulted in oil and gas sales of $2.3 million from 1.0 Bcfe of net sales volume. Austin Chalk trend wells that were placed into production during 1995 contributed oil and gas sales of $3.1 million from 1.6 Bcfe of net sales volume. As a percentage of total revenues, oil and gas sales rose from 78% of total revenues in 1994 to 87% of total revenues in 1996.

Supervision Fees. These fees continue to increase, having grown from $3.75 million in 1994 to $3.84 million in 1995 to $4.47 million in 1996, 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.

Costs and Expenses. General and administrative expenses in 1996 increased $1.1 million (21%) over such expenses in 1995, while 1995 general and administrative expenses increased $58,000 (1%) over 1994. The increase in costs in 1996 reflects the increase in the Company’s activities. However, the Company’s general and administrative expenses per Mcfe produced decreased from $0.54 per Mcfe produced in 1994 to $0.47 per Mcfe produced in 1995 and $0.33 per Mcfe produced in 1996. 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 $0.15 per Mcfe produced in 1994, $0.13 per Mcfe produced in 1995, and $0.10 per Mcfe produced in 1996.

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 therefrom. The Company’s DD&A rate per Mcfe of production was $0.82 in 1994, $0.79 in 1995, and $0.85 in 1996, reflecting variations in the per unit cost of reserves additions. Since 1994, DD&A also has been favorably affected by the reduction in the Company’s oil and gas properties account as a result of the change in accounting principle relating to earned interests which occurred in 1994 as discussed in Note 2 to the Company’s financial statements.

Production costs in 1996 increased $1.6 million (23%) over such expenses in 1995, while those expenses in 1995 increased $1.2 million (21%) over 1994. The increases in each of the periods relate to the increase in the Company’s oil and gas sales volumes. However, the Company’s production costs per Mcfe produced have decreased to $0.43 in 1996, from $0.61 and $0.59 per Mcfe produced in 1995 and 1994, respectively. As discussed above, the Company’s increase in production is primarily through its drilling activities in the AWP Olmos Field and the Austin Chalk trend, where the Company already has an established operating base. The increase in production costs is 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. 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. Therefore, the increase in drilling activity and production has not been accompanied by a proportionate increase in operating costs. This tax exemption has had a positive impact on the Company’s production costs during 1995 and 1996, although under the new rules, the proportionate amount of the exemption is likely to be reduced in future periods.

Interest expense in 1996 on the Debentures, including amortization of debt issuance costs, totaled $1.0 million ($2.0 million in 1995 and $2.0 million in 1994), while interest expense on the credit facilities, including commitment fees, totaled $1.1 million ($1.7 million in 1995 and $1.7 million in 1994), and interest expense on the Notes, including amortization of debt issuance costs, totaled $0.7 million for a 1996 total of $2.8 million (of which $2.1 million was capitalized). The 1995 total was $3.7 million (of which $2.6 million was capitalized), while the 1994 total was $3.7 million (of which $1.9 million was capitalized). The Company capitalizes that portion of interest related to its exploration, partnership, and foreign business development activities. The lower amount of interest expense in 1996 was attributable to a smaller average balance under the Company’s credit lines necessary to finance the Company’s capital expenditures, as well as paying only six months of interest on the Debentures, as they were converted into common stock in the third quarter of 1996.

Net Income (Loss). Net income of $19.0 million and earnings per share of $1.40 for 1996 were 287% and 159% higher, respectively, than net income of $4.9 million and earnings per share of $0.54 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 the period, 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. The Company’s consolidated effective tax rate was 33.9%, 28.7%, and 23.0% in 1996, 1995, and 1994, respectively.

Net income of $4.9 million and earnings per share of $0.54 for 1995 were 32% higher and 4% lower, respectively, than "income before cumulative effect of change in accounting principle" of $3.7 million and earnings per share of $0.56 in 1994. The increase in net income in 1995 was primarily due to an increase in production volumes and the related oil and gas sales therefrom. The 1995 decrease in earnings per share reflected a 37% increase in weighted average shares outstanding for the period, as a result of the sale of $5.75 million shares of common stock in the third quarter of 1995.

Net loss for 1994 of $13.0 million included a cumulative effect of a change in accounting principle (see Note 2 to the Company’s financial statements) of $16.8 million.


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