ee3rdqtr10q.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q/A
Amendment No. 1
(X) QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For
the Quarterly Period Ended September 30, 2007
Commission
File Number 1-8754
SWIFT
ENERGY COMPANY
TEXAS
(State
of Incorporation)
|
20-3940611
(I.R.S.
Employer Identification No.)
|
|
|
16825
Northchase Drive, Suite 400
Houston,
Texas
(Address
of principal executive offices)
|
77060
(Zip
Code)
|
(281)-874-2700
|
(Registrant’s
telephone number, including area
code)
|
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months, and (2) has been subject to such filing requirements for
the past 90 days.
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of
“accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange
Act.
Large
accelerated filer
|
þ
|
Accelerated
filer
|
o
|
Non-accelerated
filer
|
o
|
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
Indicate
the number of shares outstanding of each of the Issuer’s classes
of common
stock, as of the latest practicable date.
Common
Stock
($.01
Par Value)
(Class
of Stock)
|
30,105,226
Shares
(Outstanding
at October 31, 2007)
|
Explanatory
Note
This
Amendment No. 1 on Form 10-Q/A is filed by Swift Energy Company (Swift Energy or
the “Company”) to amend the Company’s quarterly report on Form 10-Q for the
quarter ended September 30, 2007, originally filed with the Securities and
Exchange Commission (the “SEC”) on November 1, 2007 (the “Original
Filing”). The Sarbanes Oxley Section 302 certifications of our Chief
Executive Officer and Chief Financial Officer in the Original Filing were
inadvertently dated August 1, 2007 on the EDGAR version; however, the manual
signatures were obtained on and correctly dated November 1, 2007. The sole
purpose of this amendment is to update the certifications
of our Chief Executive Officer and Chief Financial Officer. As a result, the
certifications pursuant to Section 302 and Section 906 of the Sarbanes-Oxley Act
of 2002 have been re-executed and re-filed as of the date of this Form 10-Q/A.
This
amendment is not intended to update any other information presented in the
Original Filing.
SWIFT
ENERGY COMPANY
FORM
10-Q/A
FOR
THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2007
INDEX
PART
I. FINANCIAL INFORMATION
|
PAGE
|
|
|
|
|
|
Item
1.
|
Condensed
Consolidated Financial Statements
|
|
|
|
|
|
|
|
Condensed
Consolidated Balance Sheets
|
3
|
|
|
-
September 30, 2007 and December 31, 2006
|
|
|
|
|
|
|
|
Condensed
Consolidated Statements of Income
|
4
|
|
|
-
For the Three month and Nine month periods ended September 30, 2007 and
2006
|
|
|
|
|
|
|
|
Condensed
Consolidated Statements of Stockholders’ Equity
|
5
|
|
|
-
For the Nine month period ended September 30, 2007 and year ended
December 31, 2006
|
|
|
|
|
|
|
|
Condensed
Consolidated Statements of Cash Flows
|
6
|
|
|
-
For the Nine month periods ended September 30, 2007 and
2006
|
|
|
|
|
|
|
|
Notes
to Condensed Consolidated Financial Statements
|
7
|
|
|
|
|
|
Item
2.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
23
|
|
|
|
|
|
Item
3.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
35
|
|
|
|
|
|
Item
4.
|
Controls
and Procedures
|
36
|
|
|
|
|
PART
II. OTHER INFORMATION
|
|
|
|
|
|
|
Item
1.
|
Legal
Proceedings
|
37
|
|
Item
1A.
|
Risk
Factors
|
37
|
|
Item
2.
|
Unregistered
Sales of Equity Securities and Use of Proceeds
|
None
|
|
Item
3.
|
Defaults
Upon Senior Securities
|
None
|
|
Item
4.
|
Submission
of Matters to a Vote of Security Holders
|
37
|
|
Item
5.
|
Other
Information
|
None
|
|
Item
6.
|
Exhibits
|
37
|
|
|
|
|
SIGNATURES
|
39
|
2
Item
1.
Condensed
Consolidated Balance Sheets
Swift
Energy Company and Subsidiaries
(in
thousands, except share amounts)
|
|
September
30, 2007
|
|
|
December
31, 2006
|
|
|
|
(Unaudited)
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
Current
Assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$
|
11,711
|
|
|
$
|
1,058
|
|
Accounts
receivable-
|
|
|
|
|
|
|
|
|
Oil
and gas sales
|
|
|
58,409
|
|
|
|
63,935
|
|
Joint
interest owners
|
|
|
1,177
|
|
|
|
1,844
|
|
Other
Receivables
|
|
|
1,133
|
|
|
|
1,231
|
|
Deferred
tax asset
|
|
|
---
|
|
|
|
2,383
|
|
Other
current assets
|
|
|
46,466
|
|
|
|
22,122
|
|
Total
Current Assets
|
|
|
118,896
|
|
|
|
92,573
|
|
|
|
|
|
|
|
|
|
|
Property
and Equipment:
|
|
|
|
|
|
|
|
|
Oil
and gas, using full-cost accounting
|
|
|
|
|
|
|
|
|
Proved
properties
|
|
|
2,569,223
|
|
|
|
2,264,832
|
|
Unproved
properties
|
|
|
107,689
|
|
|
|
112,136
|
|
|
|
|
2,676,912
|
|
|
|
2,376,968
|
|
Furniture,
fixtures, and other equipment
|
|
|
34,633
|
|
|
|
28,041
|
|
|
|
|
2,711,545
|
|
|
|
2,405,009
|
|
Less
– Accumulated depreciation, depletion, and amortization
|
|
|
(1,073,797
|
)
|
|
|
(921,697
|
)
|
|
|
|
1,637,748
|
|
|
|
1,483,312
|
|
Other
Assets:
|
|
|
|
|
|
|
|
|
Debt
issuance costs
|
|
|
7,527
|
|
|
|
7,382
|
|
Restricted
assets
|
|
|
2,398
|
|
|
|
2,415
|
|
|
|
|
9,925
|
|
|
|
9,797
|
|
|
|
$
|
1,766,569
|
|
|
$
|
1,585,682
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
|
Accounts
payable and accrued liabilities
|
|
$
|
67,212
|
|
|
$
|
74,425
|
|
Accrued
capital costs
|
|
|
60,925
|
|
|
|
55,282
|
|
Accrued
interest
|
|
|
8,577
|
|
|
|
8,764
|
|
Undistributed
oil and gas revenues
|
|
|
2,071
|
|
|
|
7,504
|
|
Total
Current Liabilities
|
|
|
138,785
|
|
|
|
145,975
|
|
Long-Term
Debt
|
|
|
400,000
|
|
|
|
381,400
|
|
Deferred
Income Taxes
|
|
|
279,958
|
|
|
|
224,967
|
|
Asset
Retirement Obligation
|
|
|
35,141
|
|
|
|
33,695
|
|
Lease
Incentive Obligation
|
|
|
1,549
|
|
|
|
1,728
|
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'
Equity:
|
|
|
|
|
|
|
|
|
Preferred
stock, $.01 par value, 5,000,000 shares authorized, none
outstanding
|
|
|
---
|
|
|
|
---
|
|
Common
stock, $.01 par value, 85,000,000 shares authorized, 30,518,791 and
30,170,004 shares issued, and 30,083,821 and 29,742,918 shares
outstanding, respectively
|
|
|
305
|
|
|
|
302
|
|
Additional
paid-in capital
|
|
|
401,980
|
|
|
|
387,556
|
|
Treasury
stock held, at cost, 434,970 and 427,086 shares,
respectively
|
|
|
(7,420
|
)
|
|
|
(6,125
|
)
|
Retained
earnings
|
|
|
516,271
|
|
|
|
415,868
|
|
Accumulated
other comprehensive income, net of income tax
|
|
|
---
|
|
|
|
316
|
|
|
|
|
911,136
|
|
|
|
797,917
|
|
|
|
$
|
1,766,569
|
|
|
$
|
1,585,682
|
|
See
accompanying notes to condensed consolidated financial statements.
3
Condensed
Consolidated Statements of Income (Unaudited)
Swift
Energy Company and Subsidiaries
(in
thousands, except per share amounts)
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
09/30/07
|
|
|
09/30/06
|
|
|
09/30/07
|
|
|
09/30/06
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas sales
|
|
$
|
179,525
|
|
|
$
|
173,369
|
|
|
$
|
488,228
|
|
|
$
|
453,316
|
|
Price-risk
management and other, net
|
|
|
1,695
|
|
|
|
90
|
|
|
|
2,254
|
|
|
|
3,489
|
|
|
|
|
181,220
|
|
|
|
173,459
|
|
|
|
490,482
|
|
|
|
456,805
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General
and administrative, net
|
|
|
10,265
|
|
|
|
8,018
|
|
|
|
29,295
|
|
|
|
23,323
|
|
Depreciation,
depletion and amortization
|
|
|
53,568
|
|
|
|
45,868
|
|
|
|
150,894
|
|
|
|
120,151
|
|
Accretion
of asset retirement obligation
|
|
|
388
|
|
|
|
172
|
|
|
|
1,170
|
|
|
|
666
|
|
Lease
operating costs
|
|
|
21,530
|
|
|
|
12,926
|
|
|
|
59,960
|
|
|
|
45,844
|
|
Severance
and other taxes
|
|
|
20,152
|
|
|
|
18,490
|
|
|
|
55,465
|
|
|
|
49,211
|
|
Interest
expense, net
|
|
|
5,700
|
|
|
|
5,776
|
|
|
|
19,742
|
|
|
|
17,436
|
|
Debt
retirement cost
|
|
|
---
|
|
|
|
---
|
|
|
|
12,765
|
|
|
|
---
|
|
|
|
|
111,603
|
|
|
|
91,250
|
|
|
|
329,291
|
|
|
|
256,631
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Income Taxes
|
|
|
69,617
|
|
|
|
82,209
|
|
|
|
161,191
|
|
|
|
200,174
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision
for Income Taxes
|
|
|
27,335
|
|
|
|
31,397
|
|
|
|
59,811
|
|
|
|
73,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income
|
|
$
|
42,282
|
|
|
$
|
50,812
|
|
|
$
|
101,380
|
|
|
$
|
126,295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per
Share Amounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic: Net
Income
|
|
$
|
1.41
|
|
|
$
|
1.74
|
|
|
$
|
3.39
|
|
|
$
|
4.33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted: Net
Income
|
|
$
|
1.38
|
|
|
$
|
1.68
|
|
|
$
|
3.32
|
|
|
$
|
4.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average Shares Outstanding
|
|
|
30,051
|
|
|
|
29,252
|
|
|
|
29,937
|
|
|
|
29,161
|
|
See
accompanying notes to condensed consolidated financial statements.
4
Condensed
Consolidated Statements of Stockholders’ Equity
Swift
Energy Company and Subsidiaries
(in
thousands, except share amounts)
|
|
Common
Stock
(1)
|
|
|
Additional
Paid-in Capital
|
|
|
Treasury
Stock
|
|
|
Unearned
Compensation
|
|
|
Retained
Earnings
|
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
Total
|
|
Balance,
December 31, 2005
|
|
$
|
295
|
|
|
$
|
365,086
|
|
|
$
|
(6,446
|
)
|
|
$
|
(5,850
|
)
|
|
$
|
254,303
|
|
|
$
|
(70
|
)
|
|
$
|
607,318
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
issued for benefit plans (22,358 shares)
|
|
|
-
|
|
|
|
714
|
|
|
|
321
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,035
|
|
Stock
options exercised (652,829 shares)
|
|
|
7
|
|
|
|
11,831
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
11,838
|
|
Adoption
of SFAS No. 123R
|
|
|
-
|
|
|
|
(5,875
|
)
|
|
|
-
|
|
|
|
5,850
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(25
|
)
|
Excess
tax benefits from stock-based awards
|
|
|
-
|
|
|
|
4,811
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
4,811
|
|
Employee
stock purchase plan (22,425 shares)
|
|
|
-
|
|
|
|
671
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
671
|
|
Issuance
of restricted stock (35,776 shares)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Amortization
of stock compensation
|
|
|
-
|
|
|
|
10,318
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10,318
|
|
Comprehensive
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
161,565
|
|
|
|
-
|
|
|
|
161,565
|
|
Other
comprehensive income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
386
|
|
|
|
386
|
|
Total
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
161,951
|
|
Balance,
December 31, 2006
|
|
$
|
302
|
|
|
$
|
387,556
|
|
|
$
|
(6,125
|
)
|
|
$
|
-
|
|
|
$
|
415,868
|
|
|
$
|
316
|
|
|
$
|
797,917
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
issued for benefit plans (32,817 shares) (2)
|
|
|
-
|
|
|
|
953
|
|
|
|
471
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,424
|
|
Stock
options exercised (148,665 shares) (2)
|
|
|
1
|
|
|
|
1,901
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,902
|
|
Purchase
of treasury shares (40,701 shares) (2)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,766
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,766
|
)
|
Adoption
of FIN 48 (2)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(977
|
)
|
|
|
-
|
|
|
|
(977
|
)
|
Employee
stock purchase plan (17,678 shares) (2)
|
|
|
-
|
|
|
|
619
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
619
|
|
Issuance
of restricted stock (182,444 shares) (2)
|
|
|
2
|
|
|
|
(2
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Amortization
of stock compensation (2)
|
|
|
-
|
|
|
|
10,953
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
10,953
|
|
Comprehensive
income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income (2)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
101,380
|
|
|
|
-
|
|
|
|
101,380
|
|
Other
comprehensive loss (2)
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(316
|
)
|
|
|
(316
|
)
|
Total
comprehensive income (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
101,064
|
|
Balance,
September 30, 2007 (2)
|
|
$
|
305
|
|
|
$
|
401,980
|
|
|
$
|
(7,420
|
)
|
|
$
|
-
|
|
|
$
|
516,271
|
|
|
$
|
-
|
|
|
$
|
911,136
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)$.01
par value.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2)Unaudited.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed consolidated financial
statements.
|
5
Condensed
Consolidated Statements of Cash Flows (Unaudited)
Swift
Energy Company and Subsidiaries
(in
thousands)
|
|
Nine
Months Ended September 30,
|
|
|
|
2007
|
|
|
2006
|
|
Cash
Flows from Operating Activities:
|
|
|
|
|
|
|
Net
income
|
|
$
|
101,380
|
|
|
$
|
126,295
|
|
Adjustments
to reconcile net income to net cash provided
|
|
|
|
|
|
|
|
|
by
operating activities-
|
|
|
|
|
|
|
|
|
Depreciation,
depletion, and amortization
|
|
|
150,894
|
|
|
|
120,151
|
|
Accretion
of asset retirement obligation
|
|
|
1,170
|
|
|
|
666
|
|
Deferred
income taxes
|
|
|
59,688
|
|
|
|
67,169
|
|
Stock-based
compensation expense
|
|
|
7,783
|
|
|
|
5,057
|
|
Debt
retirement cost – cash and non-cash
|
|
|
12,765
|
|
|
|
---
|
|
Other
|
|
|
(127
|
)
|
|
|
(3,677
|
)
|
Change
in assets and liabilities-
|
|
|
|
|
|
|
|
|
(Increase)
decrease in accounts receivable
|
|
|
6,193
|
|
|
|
(14,548
|
)
|
Increase
in accounts payable and accrued liabilities
|
|
|
1,644
|
|
|
|
7,404
|
|
Increase
(decrease) in income taxes payable
|
|
|
(884
|
)
|
|
|
338
|
|
Increase
(decrease) in accrued interest
|
|
|
(187
|
)
|
|
|
1,828
|
|
Net
Cash Provided by Operating Activities
|
|
|
340,319
|
|
|
|
310,683
|
|
|
|
|
|
|
|
|
|
|
Cash
Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
Additions
to property and equipment
|
|
|
(335,898
|
)
|
|
|
(295,502
|
)
|
Proceeds
from the sale of property and equipment
|
|
|
219
|
|
|
|
20,336
|
|
Net
cash received as operator of partnerships and joint
ventures
|
|
|
485
|
|
|
|
855
|
|
Other
|
|
|
---
|
|
|
|
(31
|
)
|
Net
Cash Used in Investing Activities
|
|
|
(335,194
|
)
|
|
|
(274,342
|
)
|
|
|
|
|
|
|
|
|
|
Cash
Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
Proceeds
from long-term debt
|
|
|
250,000
|
|
|
|
---
|
|
Payments
of long-term debt
|
|
|
(200,000
|
)
|
|
|
---
|
|
Net
payments of bank borrowings
|
|
|
(31,400
|
)
|
|
|
---
|
|
Net
proceeds from issuances of common stock
|
|
|
2,521
|
|
|
|
4,289
|
|
Excess
tax benefits from stock-based awards
|
|
|
---
|
|
|
|
1,483
|
|
Purchase
of treasury shares
|
|
|
(1,766
|
)
|
|
|
---
|
|
Payments
of debt retirement costs
|
|
|
(9,376
|
)
|
|
|
---
|
|
Payments
of debt issuance costs
|
|
|
(4,451
|
)
|
|
|
---
|
|
Net
Cash Provided by Financing Activities
|
|
|
5,528
|
|
|
|
5,772
|
|
|
|
|
|
|
|
|
|
|
Net
Increase in Cash and Cash Equivalents
|
|
$
|
10,653
|
|
|
$
|
42,113
|
|
|
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents at Beginning of Period
|
|
|
1,058
|
|
|
|
53,005
|
|
|
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents at End of Period
|
|
$
|
11,711
|
|
|
$
|
95,118
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Disclosures of Cash Flows Information:
|
|
|
|
|
|
|
|
|
Cash
paid during period for interest, net of amounts
capitalized
|
|
$
|
19,008
|
|
|
$
|
14,721
|
|
Cash
paid during period for income taxes
|
|
$
|
1,007
|
|
|
$
|
6,373
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to condensed consolidated financial statements.
6
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
(1) General
Information
The
condensed consolidated financial statements included herein have been prepared
by Swift Energy Company (“Swift Energy” or the “Company”) and reflect necessary
adjustments, all of which were of a recurring nature unless otherwise disclosed
herein, and are in the opinion of our management necessary for a fair
presentation. Certain information and footnote disclosures normally included in
financial statements prepared in accordance with accounting principles generally
accepted in the United States have been omitted pursuant to the rules and
regulations of the Securities and Exchange Commission. We believe that the
disclosures presented are adequate to allow the information presented not to be
misleading. The condensed consolidated financial statements should be read in
conjunction with the audited financial statements and the notes thereto included
in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006 as
filed with the Securities and Exchange Commission.
(2) Summary
of Significant Accounting Policies
Holding
Company Structure
In
December 2005, we implemented a holding company structure pursuant to Texas and
federal law in a manner designed to be a non-taxable transaction. The new parent
holding company assumed the Swift Energy Company name and continued to trade on
the New York Stock Exchange. The purposes of this new holding company structure
are to separate Swift Energy’s domestic and international operations to better
reflect management practices, to improve our economics, and to provide greater
administrative and organizational flexibility. Under the new organizational
structure, four new subsidiaries were formed with the Texas parent holding
company wholly owning three Delaware subsidiaries, which in turn wholly own
Swift Energy's operating subsidiaries. Swift Energy Operating, LLC is the
operator of record for Swift Energy's domestic properties. Swift Energy's name,
charter, bylaws, officers, board of directors, authorized shares and shares
outstanding remain substantially identical. Our international operations
continue to be conducted through Swift Energy International, Inc. Swift Energy
amended its bank credit agreement, debt indentures and various other plans and
documents to accommodate the internal reorganization, but our day-to-day conduct
of business was not impacted. Accordingly, there was no impact on our
financial position or results of operations.
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 nine months ended September 30, 2007 and 2006, such
capitalized internal costs totaled $23.0 million and $20.7 million,
respectively. Interest costs are also capitalized to unproved oil and gas
properties. For the nine months ended September 30, 2007 and 2006,
capitalized interest on unproved properties totaled $7.2 million and $6.6
million, respectively. Interest not capitalized and general and
administrative costs related to production and general overhead are expensed as
incurred.
No gains
or losses are recognized upon the sale or disposition of oil and gas properties,
except in transactions involving a significant amount of reserves or where the
proceeds from the sale of oil and gas properties would significantly alter the
relationship between capitalized costs and proved reserves of oil and gas
attributable to a cost center. Internal costs associated with selling
properties are expensed as incurred.
Future
development costs are estimated property-by-property based on current economic
conditions and are amortized to expense as our capitalized oil and gas property
costs are amortized.
7
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
We
compute the provision for depreciation, depletion, and amortization of oil and
gas properties by the unit-of-production method. Under this method, we compute
the provision by multiplying the total unamortized costs of oil and gas
properties—including future development costs, natural gas processing
facilities, and both capitalized asset retirement obligations and undiscounted
abandonment costs of wells to be drilled, net of salvage values, but excluding
costs of unproved properties—by an overall rate determined by dividing the
physical units of oil and gas produced during the period by the total estimated
units of proved oil and gas reserves at the beginning of the period. This
calculation is done on a country-by-country basis, and the period over which we
will amortize these properties is dependent on our production from these
properties in future years. Furniture, fixtures, and other equipment,
held at cost, are depreciated by the straight-line method at rates based on the
estimated useful lives of the property, which range between two and 20 years.
Repairs and maintenance are charged to expense as incurred. Renewals and
betterments are capitalized.
Geological
and geophysical (G&G) costs incurred on developed properties are recorded in
“Proved properties” and therefore subject to amortization. G&G
costs incurred that are directly associated with specific unproved properties
are capitalized in “Unproved properties” and evaluated as part of the total
capitalized costs associated with a prospect. The cost of unproved properties
not being amortized is assessed quarterly, on a country-by-country basis, to
determine whether such properties have been impaired. In determining whether
such costs should be impaired, we evaluate current drilling results, lease
expiration dates, current oil and gas industry conditions, international
economic conditions, capital availability, foreign currency exchange rates, the
political stability in the countries in which we have an investment, and
available geological and geophysical information. Any impairment assessed is
added to the cost of proved properties being amortized. To the extent
costs accumulate in countries where there are no proved reserves, any costs
determined by management to be impaired are charged to expense.
Full-Cost
Ceiling Test
At the
end of each quarterly reporting period, the unamortized cost of oil and gas
properties, including natural 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”). We did not have any hedges in place at September 30,
2007. This calculation is performed on a country-by-country
basis.
The
calculation of the Ceiling Test and provision for depreciation, depletion, and
amortization (“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.
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.
Principles
of Consolidation
The
accompanying consolidated financial statements include the accounts of Swift
Energy Company and its wholly owned subsidiaries, which are engaged in the
exploration, development, acquisition, and operation of oil and natural gas
properties, with a focus on inland waters and onshore oil and natural gas
reserves in Louisiana and Texas, as well as onshore oil and natural
gas reserves in New
8
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
Zealand.
Our undivided interests in natural gas processing plants are accounted for using
the proportionate consolidation method, whereby our proportionate share of
assets, liabilities, revenues, andexpenses are included in the appropriate
classifications in the accompanying consolidated financial statements.
Intercompany balances and transactions have been eliminated in preparing the
accompanying consolidated financial statements.
Revenue
Recognition
Oil and
gas revenues are recognized when production is sold to a purchaser at a fixed or
determinable price, when delivery has occurred and title has transferred, and if
collectibility of the revenue is probable. Beginning in 2007, processing costs
for natural gas and natural gas liquids (NGLs) that are paid in-kind are
recorded in “Lease operating costs” prior to that time these costs were deducted
from revenues. Swift Energy uses the entitlement method of accounting
in which we recognize our ownership interest in production as revenue. If our
sales exceed our ownership share of production, the natural gas balancing
payables are reported in “Accounts payable and accrued liabilities” on the
accompanying balance sheet. Natural gas balancing receivables are reported in
“Other current assets” on the accompanying balance sheet when our ownership
share of production exceeds sales. As of September 30, 2007, we did not have any
material natural gas imbalances.
Reclassification
of Prior Period Balances
Certain
reclassifications have been made to prior period amounts to conform to the
current year presentation.
Accounts
Receivable
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 both
September 30, 2007 and December 31, 2006, we had an allowance for doubtful
accounts of less than $0.1 million. The allowance for doubtful
accounts has been deducted from the total “Accounts receivable” balances on the
accompanying balance sheets.
Inventories
We value
inventories at the lower of cost or market. Cost of crude oil
inventory is determined using the weighted average method and all other
inventory is accounted for using the first in, first out method
(“FIFO”). The major categories of inventories, which are included in
“Other current assets” on the accompanying balance sheets, are shown as
follows:
(in
thousands)
|
|
Balance
at
September
30, 2007
|
|
|
Balance
at
December
31, 2006
|
|
|
|
|
|
|
|
|
Materials,
Supplies and Tubulars
|
|
$
|
11,876
|
|
|
$
|
10,611
|
|
Crude
Oil
|
|
|
738
|
|
|
|
474
|
|
Total
|
|
$
|
12,614
|
|
|
$
|
11,085
|
|
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:
9
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
·
|
the
estimated quantities of proved oil and natural gas reserves used to
compute depletion of oil and natural gas properties and the related
present value of estimated future net cash flows
there-from,
|
·
|
estimates
of future costs to develop and produce
reserves,
|
·
|
accruals
related to oil and gas revenues, capital expenditures and lease operating
expenses,estimates of insurance recoveries related to property
damage,
|
·
|
estimates
in the calculation of stock compensation
expense,
|
·
|
estimates
of our ownership in properties prior to final division of interest
determination,
|
·
|
the
estimated future cost and timing of asset retirement
obligations,
|
·
|
estimates
made in our income tax calculations, and
|
·
|
estimates
in the calculation of the fair value of hedging
assets.
|
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 new
accounting pronouncements, 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.
Income
Taxes
Under
SFAS No. 109, “Accounting for Income Taxes,” deferred taxes are determined based
on the estimated future tax effects of differences between the financial
statement and tax basis of assets and liabilities, given the provisions of the
enacted tax laws.
On
January 1, 2007, we adopted the recognition and disclosure provisions of FASB
Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an
Interpretation of FASB Statement No. 109" ("FIN 48"). Under FIN 48, tax
positions are evaluated for recognition using a more-likely-than-not threshold,
and those tax positions requiring recognition are measured as the largest amount
of tax benefit that is greater than fifty percent likely of being realized upon
ultimate settlement with a taxing authority that has full knowledge of all
relevant information. As a result of adopting FIN 48, we reported a $1.0 million
decrease to our January 1, 2007 retained earnings balance and a corresponding
increase to our deferred tax liability. This is also the total balance of our
unrecognized tax benefits, which would fully impact our effective tax rate if
recognized. We do not expect to recognize significant increases or decreases in
unrecognized tax benefits during the year ended December 31, 2007.
Our
policy is to record interest and penalties relating to income taxes in income
tax expense. As of December 31, 2006 and September 30, 2007 no
interest or penalties relating to income taxes have been
recognized.
Our U.S.
Federal and State of Louisiana income tax returns from 1998 forward remain
subject to examination by tax authorities. Our Texas franchise tax returns for
2005 and prior years have been audited by the Texas State
Comptroller. There are no unresolved items related to those
audits. No other state returns are significant to our financial
position. Our New Zealand income tax returns from 2002 forward remain
subject to examination by the local tax authority.
In the
third quarter of 2007 we increased the valuation allowance for our capital loss
carryforward assets by $2.6 million to cover the full value of the
carryforward. The increase in the valuation allowance is due to
changes in the Company’s property disposition plans and increased income tax
expense by $2.6 million in that period.
Accounts
Payable and Accrued Liabilities
Included
in “Accounts payable and accrued liabilities,” on the accompanying balance
sheets, at September 30, 2007 and December 31, 2006 are liabilities of
approximately $11.5 million and $13.9 million, respectively, representing the
amount by which checks issued, but not presented by vendors to Swift Energy’s
banks for collection, exceeded balances in the applicable disbursement bank
accounts.
10
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT
ENERGY COMPANY AND SUBSIDIARIES
Accumulated
Other Comprehensive Income, Net of Income Tax
We follow
the provisions of SFAS No. 130, “Reporting Comprehensive Income,” which
establishes standards for reporting comprehensive income. In addition
to net income, comprehensive income or loss includes all changes to equity
during a period, except those resulting from investments and distributions to
the owners of Swift Energy. At September 30, 2007, we did not record
any derivative gains or losses in “Accumulated other comprehensive income, net
of income tax” on the accompanying balance sheet. The components of
accumulated other comprehensive income and related tax effects were as
follows:
(in
thousands)
|
|
Gross
Value
|
|
|
Tax
Effect
|
|
|
Net
of Tax Value
|
|
|
|
|
|
|
|
|
|
|
|
Other
comprehensive income at December 31, 2006
|
|
$
|
503
|
|
|
$
|
(187
|
)
|
|
$
|
316
|
|
Change
in fair value of cash flow hedges
|
|
|
(184
|
)
|
|
|
68
|
|
|
|
(116
|
)
|
Effect
of cash flow hedges settled during the period
|
|
|
(319
|
)
|
|
|
119
|
|
|
|
(200
|
)
|
Other
comprehensive income at September 30, 2007
|
|
$
|
---
|
|
|
$
|
---
|
|
|
$
|
---
|
|
Total
comprehensive income was $42.1 million and $52.2 million for the third quarter
of 2007 and 2006, respectively. Total comprehensive income was $101.1
and $127.3 million for the first nine months of 2007 and 2006,
respectively.
Price-Risk
Management Activities
Swift
Energy 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 the third quarters of 2007 and 2006, we recognized a
net gain of $1.0 million and a net loss of $0.4 million, respectively, relating
to our derivative activities. During the first nine months of 2007
and 2006, we recognized a net gain of $0.3 million and a net gain of $1.6
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 September 30, 2007, we had not
recorded any derivative gains or losses in “Accumulated other comprehensive
income, net of income tax” on the accompanying balance sheet as we did not have
any hedges in place at that time. This line item on the balance sheet
represents the change in fair value for the effective portion of our hedging
transactions that are qualified as cash flow hedges. The amount of
ineffectiveness reported in “Price-risk management and other, net” for the first
nine months of 2007 and 2006 was not material.
When we
entered into the 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-Merton option pricing model and is
periodically verified against quotes from brokers. Supervision
Fees
Consistent
with industry practice, we charge a supervision fee to the wells we operate
including our wells in which we own up to a 100% working
interest. Supervision fees, to the extent they do not exceed actual
costs incurred, are recorded as a reduction to “General and administrative,
net.” All of ourdomestic supervision fees are based on COPAS
determined rates; the remainder (less than 2% for each period presented) is
attributable to our New Zealand operations and is based on agreements that are
similar to COPAS. The amount of supervision fees charged in 2006 and
2007 did not exceed our actual costs incurred. The total amount of
supervision fees charged to the wells we operate were $8.0 million and $6.4
million in the first nine months of 2007 and 2006, respectively.
11
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued
SWIFT
ENERGY COMPANY AND SUBSIDIARIES
Asset
Retirement Obligation
In June
2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143,
“Accounting for Asset Retirement Obligations.” The statement requires
entities to record the fair value of a liability for legal obligations
associated with the retirement obligations of tangible long-lived assets in the
period in which it is incurred. When the liability is initially recorded, the
carrying amount of the related long-lived asset is increased. The
liability is discounted from the year the related asset is expected to
deplete. Over time, accretion of the liability is recognized each
period, and the capitalized cost is depleted on a unit-of-production basis over
the useful life of the related asset. Upon settlement of the liability, an
entity either settles the obligation for its recorded amount or incurs a gain or
loss upon settlement which is included in the full cost pool. This standard
requires us to record a liability for the fair value of our dismantlement and
abandonment costs, excluding salvage values. Based on our experience and
analysis of the oil and gas services industry, we have not factored a market
risk premium into our asset retirement obligation. SFAS No. 143 was
adopted by us effective January 1, 2003. The following provides a
roll-forward of our asset retirement obligation:
(in
thousands)
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
Asset
Retirement Obligation recorded as of January 1
|
|
$
|
34,460
|
|
|
$
|
19,356
|
|
Accretion
expense for the nine months ended September 30
|
|
|
1,170
|
|
|
|
666
|
|
Liabilities
incurred for new wells and facilities construction
|
|
|
321
|
|
|
|
553
|
|
Reductions
due to sold, or plugged and abandoned wells
|
|
|
---
|
|
|
|
(203
|
)
|
Increase
(decrease) due to currency exchange rate fluctuations
|
|
|
65
|
|
|
|
(22
|
)
|
Asset
Retirement Obligation as of September 30
|
|
$
|
36,016
|
|
|
$
|
20,350
|
|
At
September 30, 2007 and December 31, 2006, approximately $0.9 million and $0.8
million of our asset retirement obligation is classified as a current liability
in “Accounts payable and accrued liabilities” on the accompanying balance
sheets.
New
Accounting Pronouncements
Effective
January 1, 2007, Swift Energy adopted FASB Interpretation (FIN) No. 48,
"Accounting for Uncertainty in Income Taxes – an Interpretation of FASB
Statement No. 109" ("FIN 48"). This interpretation provides guidance
for recognizing and measuring uncertain tax positions, as defined in SFAS No.
109, “Accounting for Income Taxes.” See additional discussion of FIN
48 in the Income Taxes section of the footnotes. As a result of
adopting FIN 48, we reported a $1.0 million decrease to our January 1, 2007
retained earnings balance and a corresponding increase to our deferred tax
liability.
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS
No. 157 addresses how companies should approach measuring fair value when
required by GAAP; it does not create or modify any current GAAP requirements to
apply fair value accounting. SFAS No. 157 provides a single definition for fair
value that is to be applied consistently for all accounting applications, and
also generally describes and prioritizes, according to reliability, the methods
and inputs used in valuations. SFAS No. 157 prescribes various disclosures about
financial statement categories and amounts which are measured at fair value, if
such disclosures are not already specified elsewhere in GAAP. The new
measurement and disclosure requirements of SFAS No. 157 are effective for us in
the first quarter 2008. We have not yet determined what impact, if any, this
statement will have on our financial position or results of
operations.
12
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
(3) Share-Based
Compensation
We have
various types of share-based compensation plans. Refer to Note 6 of
our consolidated financial statements in our Annual Report on Form 10-K for the
fiscal year ended December 31, 2006, for additional information related to
these share-based compensation plans.
Effective
January 1, 2006, Swift Energy adopted Statement of Financial Accounting
Standards (SFAS) No. 123 (R), “Share-Based Payment” (SFAS No. 123R)
utilizing the modified prospective approach. Prior to the adoption of SFAS No.
123R, we accounted for stock option grants in accordance with Accounting
Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to
Employees” (the intrinsic value method), and accordingly, recognized no
compensation expense for employee stock option grants.
Under the
modified prospective approach, SFAS No. 123R applies to new awards and to awards
that were outstanding on January 1, 2006 as well as those that are
subsequently modified, repurchased or cancelled. Under the modified prospective
approach, compensation cost recognized for both nine month periods ended
September 30, 2007 and 2006 includes compensation cost for all share-based
awards granted prior to, but not yet vested as of January 1, 2006, based on
the grant-date fair value estimated in accordance with the original provisions
of SFAS No. 123, and compensation cost for all share-based awards granted
subsequent to January 1, 2006, based on the grant-date fair value estimated
in accordance with the provisions of SFAS No. 123R. Prior periods were not
restated to reflect the impact of adopting the new standard.
Upon
adoption of SFAS 123R, we recorded an immaterial cumulative effect of a change
in accounting principle as a result of our change in policy from recognizing
forfeitures as they occur to one recognizing expense based on our expectation of
the amount of awards that will vest over the requisite service period for our
restricted stock awards. This amount was recorded in “General and
administrative, net” in the accompanying condensed consolidated statements
of operations.
We
receive a tax deduction for certain stock option exercises during the period the
options are exercised, generally for the excess of the price at which the stock
is sold over the exercise price of the options. We receive an
additional tax deduction when restricted stock vests at a higher value than the
value used to recognize compensation expense at the date of grant. Prior to
adoption of SFAS No. 123R, we reported all tax benefits resulting from the award
of equity instruments as operating cash flows in our condensed consolidated
statements of cash flows. In accordance with SFAS No. 123R, we are required to
report excess tax benefits from the award of equity instruments as financing
cash flows. These benefits were $1.0 and $1.5 million for the nine
months ended September 30, 2007 and 2006, respectively. The benefit
for 2007 has not been recognized in the financial statements as these benefits
have not been realized since we are in a tax net operating loss position for the
first nine months of 2007.
Net cash
proceeds from the exercise of stock options were $1.9 million and $3.6
million for the nine months ended September 30, 2007 and 2006. The actual income
tax benefit realized from stock option exercises was $1.2 million and $2.0
million for the same periods.
Stock
compensation expense for both stock options and restricted stock issued to both
employees and non-employees is recorded in “General and administrative, net” in
the accompanying condensed consolidated statements of income, and was $2.5
million and $1.8 million for the quarters ended September 30, 2007 and 2006,
respectively. Stock compensation expense for the nine months ended
September 30, 2007 and 2006 was $7.4 million and $5.1 million,
respectively. We view all awards of stock compensation as a single
award with an expected life equal to the average expected life of component
awards and amortize the award on a straight-line basis over the life of the
award.
13
NOTES TO CONDENSED
CONSOLIDATED FINANCIAL
STATEMENTS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
Stock
Options
We use
the Black-Scholes-Merton option pricing model to estimate the fair value of
stock option awards with the following weighted-average assumptions for the
indicated periods:
|
|
Three
Months Ended
|
|
|
Nine
months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend
yield
|
|
|
0
|
%
|
|
|
0
|
%
|
|
|
0
|
%
|
|
|
0
|
%
|
Expected
volatility
|
|
|
37.5
|
%
|
|
|
39.1
|
%
|
|
|
38.5
|
%
|
|
|
39.5
|
%
|
Risk-free
interest rate
|
|
|
4.0
|
%
|
|
|
4.8
|
%
|
|
|
4.8
|
%
|
|
|
4.9
|
%
|
Expected
life of options (in years)
|
|
|
4.3
|
|
|
|
2.6
|
|
|
|
6.2
|
|
|
|
5.6
|
|
Weighted-average
grant-date fair value
|
|
$
|
14.83
|
|
|
$
|
12.20
|
|
|
$
|
20.05
|
|
|
$
|
19.31
|
|
The
expected term has been calculated using the Securities and Exchange Commission
Staff’s shortcut approach from Staff Accounting Bulletin No. 107. We
have analyzed historical volatility, and based on an analysis of all relevant
factors; use a three-year period to estimate expected volatility of our stock
option grants.
At
September 30, 2007, there was $3.8 million of unrecognized compensation
cost related to stock options which is expected to be recognized over a
weighted-average period of 1.3 years. The following table represents
stock option activity for the nine months ended September 30, 2007:
|
|
Shares
|
|
|
Wtd.
Avg. Exer. Price
|
|
|
|
|
|
|
|
|
Options
outstanding, beginning of period
|
|
|
1,549,140
|
|
|
$
|
24.59
|
|
Options
granted
|
|
|
193,057
|
|
|
$
|
43.51
|
|
Options
canceled
|
|
|
(15,591
|
)
|
|
$
|
35.02
|
|
Options
exercised
|
|
|
(172,409
|
)
|
|
$
|
15.52
|
|
Options
outstanding, end of period
|
|
|
1,554,197
|
|
|
$
|
27.84
|
|
Options
exercisable, end of period
|
|
|
836,679
|
|
|
$
|
24.72
|
|
The
aggregate intrinsic value and weighted average remaining contract life of
options outstanding and exercisable at September 30, 2007 was $22.2 million and
5.4 years and $13.9 million and 4.0 years, respectively. Total
intrinsic value of options exercised during the nine months ended September 30,
2007 was $4.6 million.
Restricted
Stock
The
plans, as described in Note 6 of our consolidated financial statements in our
Annual Report on Form 10-K for the fiscal year ended December 31, 2006,
allow for the issuance of restricted stock awards that may not be sold or
otherwise transferred until certain restrictions have lapsed. The unrecognized
compensation cost related to these awards is expected to be expensed over the
period the restrictions lapse (generally one to five years).
The
compensation expense for these awards was determined based on the market price
of our stock at the date of grant applied to the total number of shares that
were anticipated to fully vest. As of September 30, 2007, we had unrecognized
compensation expense of approximately $18.9 million associated with these
awards which are expected to be recognized over a weighted-average period of 1.8
years. The total fair value of shares vested during the first nine
months ended September 30, 2007 was $7.9 million.
14
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
The
following table represents restricted stock activity for the nine months ended
September 30, 2007:
|
|
Shares
|
|
|
Wtd.
Avg.
Grant
Price
|
|
|
|
|
|
|
|
|
Restricted
shares outstanding, beginning of period
|
|
|
503,184
|
|
|
$
|
40.04
|
|
Restricted
shares granted
|
|
|
319,730
|
|
|
$
|
43.15
|
|
Restricted
shares canceled
|
|
|
(33,584
|
)
|
|
$
|
42.29
|
|
Restricted
shares vested
|
|
|
(183,334
|
)
|
|
$
|
40.03
|
|
Restricted
shares outstanding, end of period
|
|
|
605,996
|
|
|
$
|
41.56
|
|
(4) Earnings
Per Share
Basic
earnings per share (“Basic EPS”) have been computed using the weighted average
number of common shares outstanding during the respective periods. Diluted
earnings per share (“Diluted EPS”) for all periods also assumes, as of the
beginning of the period, exercise of stock options and restricted stock grants
to employees using the treasury stock method. Certain of our stock options, that
could potentially dilute Basic EPS in the future, were anti-dilutive for periods
ended September 30, 2007 and 2006, and are discussed below.
The
following is a reconciliation of the numerators and denominators used in the
calculation of Basic and Diluted EPS for the periods ended September 30, 2007
and 2006:
(in
thousands, except per share data)
|
|
Three
Months Ended September 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Net
Income
|
|
|
Shares
|
|
|
Per
Share Amount
|
|
|
Net
Income
|
|
|
Shares
|
|
|
Per
Share Amount
|
|
Basic
EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income and Share Amounts
|
|
$
|
42,282
|
|
|
|
30,051
|
|
|
$
|
1.41
|
|
|
$
|
50,812
|
|
|
|
29,252
|
|
|
$
|
1.74
|
|
Dilutive
Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted
Stock
|
|
|
---
|
|
|
|
158
|
|
|
|
|
|
|
|
---
|
|
|
|
131
|
|
|
|
|
|
Stock
Options
|
|
|
---
|
|
|
|
477
|
|
|
|
|
|
|
|
---
|
|
|
|
801
|
|
|
|
|
|
Diluted
EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income and Assumed Share Conversions
|
|
$
|
42,282
|
|
|
|
30,686
|
|
|
$
|
1.38
|
|
|
$
|
50,812
|
|
|
|
30,184
|
|
|
$
|
1.68
|
|
(in
thousands, except per share data)
|
|
Nine
Months Ended September 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Net
Income
|
|
|
Shares
|
|
|
Per
Share Amount
|
|
|
Net
Income
|
|
|
Shares
|
|
|
Per
Share Amount
|
|
Basic
EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income and Share Amounts
|
|
$
|
101,380
|
|
|
|
29,937
|
|
|
$
|
3.39
|
|
|
$
|
126,295
|
|
|
|
29,161
|
|
|
$
|
4.33
|
|
Dilutive
Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted
Stock
|
|
|
---
|
|
|
|
161
|
|
|
|
|
|
|
|
---
|
|
|
|
125
|
|
|
|
|
|
Stock
Options
|
|
|
---
|
|
|
|
484
|
|
|
|
|
|
|
|
---
|
|
|
|
777
|
|
|
|
|
|
Diluted
EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Income and Assumed Share Conversions
|
|
$
|
101,380
|
|
|
|
30,582
|
|
|
$
|
3.32
|
|
|
$
|
126,295
|
|
|
|
30,063
|
|
|
$
|
4.20
|
|
Options
to purchase approximately 1.6 million shares at an average exercise price of
$27.84 were outstanding at September 30, 2007, while options to purchase 2.0
million shares at an average exercise price of $23.25 were outstanding at
September 30, 2006. Approximately 1.1 million and 1.2 million options
to purchase shares were not included in the computation of Diluted EPS for the
three months ended September 30, 2007 and 2006, respectively, and 1.1 million
and 1.2 million options to purchase shares were not included in the computation
of Diluted EPS for the nine months ended September 30, 2007 and 2006,
respectively, because these options were anti-dilutive, in that the sum of the
option price, unrecognized compensation expense and excess tax benefits
recognized as proceeds in the treasury stock method was greater than the average
closing market price for the common shares during those periods. Employee
restricted stock grants of 448,366 shares and 359,695 shares were not included
in the computation of Diluted EPS for the three months ended September 30, 2007
and 2006, respectively, and 444,906 shares and 366,072 shares were not included
in the computation of Diluted EPS for the nine months ended September 30, 2007
and 2006, respectively, because these restricted stock grants were anti-dilutive
in that the sum of the unrecognized compensation expense and excess tax benefits
recognized as proceeds under the treasury stock method was greater than the
average closing market price for the common shares during that
period.
15
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
(5) Long-Term
Debt
Our
long-term debt, including the current portion, as of September 30, 2007 and
December 31, 2006, was as follows:
(in
thousands)
|
|
September
30,
2007
|
|
|
December
31,
2006
|
|
Bank
Borrowings
|
|
$
|
---
|
|
|
$
|
31,400
|
|
7-5/8%
senior notes due 2011
|
|
|
150,000
|
|
|
|
150,000
|
|
9-3/8%
senior subordinated notes due 2012
|
|
|
---
|
|
|
|
200,000
|
|
7-1/8%
senior notes due 2017
|
|
|
250,000
|
|
|
|
---
|
|
Long-Term
Debt
|
|
$
|
400,000
|
|
|
$
|
381,400
|
|
At
September 30, 2007, the aggregate maturities on our long-term debt are $150.0
million for 2011 and $250.0 million for 2017.
Bank
Borrowings
At
September 30, 2007, we had no borrowings under our $500.0 million credit
facility with a syndicate of ten banks that had a borrowing base of $350.0
million and expires in October 2011. The interest rate is either (a)
the lead bank’s prime rate (7.75% at September 30, 2007) or (b) the adjusted
London Interbank Offered Rate (“LIBOR”) plus the applicable margin depending on
the level of outstanding debt. The applicable margin is based on the ratio of
the outstanding balance to the last calculated borrowing base. In October 2006,
we increased, renewed, and extended this credit facility, increasing the
facility to $500.0 million from $400.0 million, increasing the commitment amount
under the borrowing base to $250.0 million from $150.0 million, and extending
its expiration to October 3, 2011 from October 1, 2008. In April 2007
we increased the borrowing base to $350.0 million; and effective November 2007,
we further increased it to $400.0 million. In September 2007, we
increased the commitment amount under the borrowing base to $350.0 million from
$250.0 million.
The terms
of our credit facility include, among other restrictions, a limitation on the
level of cash dividends (not to exceed $15.0 million in any fiscal year), a
remaining aggregate limitation on purchases of our stock of $50.0 million,
requirements as to maintenance of certain minimum financial ratios (principally
pertaining to adjusted working capital ratios and EBITDAX), and limitations on
incurring other debt or repurchasing our 7-5/8% senior notes due 2011. Since
inception, no cash dividends have been declared on our common stock. We are
currently in compliance with the provisions of this agreement. The credit
facility is secured by our domestic oil and gas properties. We have
also pledged 65% of the stock in our two New Zealand subsidiaries as collateral
for this credit facility. Under the terms of the 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. The borrowing base
amount is re-determined at least every six months and the next scheduled
borrowing base review is in May 2008.
Interest
expense on the credit facility, including commitment fees and amortization of
debt issuance costs, totaled $0.4 million and $0.2 million for the three months
ended September 30, 2007 and 2006, respectively, and $3.0 million and $0.6
million for the nine months ended September 30, 2007 and 2006,
respectively. The amount of commitment fees included in interest
expense, net was $0.2 million and $0.1 million for three month periods ended
September 30, 2007 and 2006, respectively, and $0.4 million for both the nine
month periods ended September 30, 2007 and 2006, respectively.
Senior
Notes Due 2017
These
notes consist of $250.0 million of 7-1/8% senior notes due 2017, which were
issued on June 1, 2007 at 100% of the principal amount and will mature on June
1, 2017. The notes are senior unsecured obligations that rank equally
with all of our existing and future senior unsecured indebtedness, are
effectively subordinated to all our existing and future secured indebtedness to
the extent of the value of the collateral securing such indebtedness, including
borrowing under our bank credit facility, and will rank senior to any future
subordinated indebtedness of Swift Energy. Interest on these notes is
payable semi-annually on June 1 and December 1, and commencing on December 1,
2007. On or after June 1, 2012, we may redeem some or all of these
notes, with certain restrictions, at a redemption price, plus accrued and unpaid
interest, of 103.563% of principal, declining in
twelve-month intervals to 100% in 2015 and
16
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
thereafter. In
addition, prior to June 1, 2010, we may redeem up to 35% of the principal amount
of the notes with the net proceeds of qualified offerings of our equity at a
redemption price of 107.125% of the principal amount of the notes, plus accrued
and unpaid interest. We incurred approximately $4.2 million of debt
issuance costs related to these notes, which is included in “Debt issuance
costs” on the accompanying balance sheets and will be amortized to interest
expense, net over the life of the notes using the effective interest
method. In the event of certain changes in control of Swift Energy,
each holder of notes will have the right to require us to repurchase all or any
part of the notes at a purchase price in cash equal to 101% of the principal
amount, plus accrued and unpaid interest to the date of purchase. The
terms of these notes include, among other restrictions, a limitation on how much
of our own common stock we may repurchase. We are currently in
compliance with the provisions of the indenture governing these senior
notes.
Interest
expense on the 7-1/8% senior notes due 2017, including amortization of debt
issuance costs, totaled $4.5 million and $6.0 million for three and nine month
periods ended September 30, 2007.
Senior
Notes Due 2011
These
notes consist of $150.0 million of 7-5/8% senior notes due 2011, which were
issued on June 23, 2004 at 100% of the principal amount and will mature on July
15, 2011. The notes are senior unsecured obligations that rank
equally with all of our existing and future senior unsecured indebtedness, are
effectively subordinated to all our existing and future secured indebtedness to
the extent of the value of the collateral securing such indebtedness, including
borrowing under our bank credit facility, and rank senior to all of our existing
and future subordinated indebtedness. Interest on these notes is
payable semi-annually on January 15 and July 15, and commenced on January 15,
2005. On or after July 15, 2008, we may redeem some or all of the
notes, with certain restrictions, at a redemption price, plus accrued and unpaid
interest, of 103.813% of principal, declining to 100% in 2010 and
thereafter. In addition, prior to July 15, 2007, we could have
redeemed up to 35% of the notes with the net proceeds of qualified offerings of
our equity at a redemption price of 107.625% of the principal amount of the
notes, plus accrued and unpaid interest. We incurred approximately
$3.9 million of debt issuance costs related to these notes, which is included in
“Debt issuance costs” on the accompanying balance sheets and will be amortized
to interest expense, net over the life of the notes using the effective interest
method. Upon certain changes in control of Swift Energy, each holder
of notes will have the right to require us to repurchase all or any part of the
notes at a purchase price in cash equal to 101% of the principal amount, plus
accrued and unpaid interest to the date of purchase. The terms of
these notes include, among other restrictions, a limitation on how much of our
own common stock we may repurchase. We are currently in compliance
with the provisions of the indenture governing these senior notes.
Interest
expense on the 7-5/8% senior notes due 2011, including amortization of debt
issuance costs totaled $3.0 million for each of the three month periods ended
September 30, 2007 and 2006, and $9.0 million and $8.9 million for the nine
month periods ended September 30, 2007 and 2006, respectively.
Senior
Subordinated Notes Due 2012
These
notes consisted of $200.0 million of 9-3/8% senior subordinated notes due May
2012, which were issued on April 16, 2002 and were scheduled to mature on May 1,
2012. Interest on these notes was payable semiannually on May 1 and November
1. As of June 18, 2007, we redeemed all $200.0 million of these
notes. In the second quarter of 2007, we recorded a charge of $12.8
million related to the redemption of these notes, which is recorded in “Debt
retirement costs” on the accompanying condensed consolidated statement of
income. The costs were comprised of approximately $9.4 million of
premium paid to redeem the notes, and $3.4 million to write-off unamortized debt
issuance costs.
Interest
expense on the 9-3/8% senior subordinated notes due 2012, including amortization
of debt issuance costs totaled $4.8 million for the three month period ended
September 30, 2006, and $8.9 million and $14.4 million for the nine month
periods ended September 30, 2007 and 2006, respectively.
We have
capitalized interest on our unproved properties in the amount of $2.2 million
for each of the three month periods ended September 30, 2007 and 2006, and $7.2
million and $6.6 million for the nine month periods ended September 30, 2007 and
2006, respectively.
17
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
(6) Foreign
Activities
As of
September 30, 2007, our gross capitalized oil and gas property costs in New
Zealand totaled approximately $354.3 million. Approximately $339.0
million has been included in the “Proved properties” portion of our oil and gas
properties, while $15.3 million is included as “Unproved properties.” Our
functional currency in New Zealand is the U.S. dollar. Net assets of
our New Zealand operations total $255.3 million at September 30,
2007.
(7) Acquisitions
and Dispositions
In
October 2006, we acquired interests in five South Louisiana fields. The property
interests are located in: Bayou Sale, Horseshoe Bayou and Jeanerette fields (all
located in St. Mary Parish), High Island field in Cameron Parish and Bayou
Penchant field in Terrebonne Parish. We paid approximately $167.9
million in cash for these interests. After taking into account internal
acquisition costs of $4.0 million, our total cost was $171.9 million. We
allocated $154.6 million of the acquisition price to “Proved Properties,” $28.8
million to “Unproved Properties,” and recorded a liability for $11.5 million to
“Asset retirement obligation” on our accompanying consolidated balance sheet.
These acquisitions were accounted for by the purchase method of accounting. We
made these acquisitions to increase our exploration and development
opportunities in South Louisiana. The revenues and expenses from these
properties have been included in our accompanying consolidated statements of
income from the date of acquisition forward.
In
December 2006, we acquired additional interests in our Lake Washington field. We
paid approximately $20.0 million in cash for these interests. After taking into
account internal acquisition costs of $0.4 million, our total cost was $20.4
million. We allocated $18.7 million of the acquisition price to “Proved
Properties,” $2.5 million to “Unproved Properties,” and recorded a liability for
$0.8 million to “Asset Retirement Obligation” on our accompanying consolidated
balance sheet. This acquisition was accounted for by the purchase method of
accounting. We made this acquisition to increase our exploration and development
opportunities in South Louisiana. The revenues and expenses from this
acquisition have been included in our accompanying consolidated statements of
income from the date of acquisition forward.
(8) Subsequent
Events
In
October 2007, we acquired interests in three South Texas fields in the Maverick
Basin from Escondido Resources, LP. The total price for these
interests was approximately $249.5 million. The property interests
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. We have recorded $24.5 million in “Other current assets” at
September 30, 2007 related to the deposit for this acquisition.
(9) Condensed
Consolidating Financial Information
In
December 2005, we amended the indenture for our 9-3/8% Senior Subordinated Notes
due 2012 and our 7-5/8% Senior Notes due 2011 to reflect our new holding company
organizational structure (as discussed in Note 2). Pursuant to the amendment,
both Swift Energy Company and Swift Energy Operating, LLC (a wholly owned
indirect subsidiary of Swift Energy Company) became co-obligors of these senior
notes and senior subordinated debt. Prior to amendment, Swift Energy
Company was the sole obligor. Due to the redemption of the 9-3/8%
senior subordinated notes in June 2007, Swift Energy Company and Swift Energy
Operating, LLC remain co-obligors only under the indenture for our 7-1/8% senior
notes as of June 1, 2007. The co-obligations are full and
unconditional and are joint and several. The following is condensed
consolidating financial information for Swift Energy Company, Swift Energy
Operating, LLC, and significant subsidiaries:
18
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
Condensed
Consolidating Balance Sheets
(in
thousands)
|
|
September
30, 2007
|
|
|
|
Swift
Energy Co. (Parent and
Co-obligor)
|
|
|
Swift
Energy Operating, LLC
(Co-obligor)
|
|
|
Other
Subsidiaries
|
|
|
Eliminations
|
|
|
Swift
Energy Co. Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
assets
|
|
$
|
---
|
|
|
$
|
96,039
|
|
|
$
|
22,857
|
|
|
$
|
---
|
|
|
$
|
118,896
|
|
Property
and equipment
|
|
|
---
|
|
|
|
1,405,457
|
|
|
|
232,291
|
|
|
|
---
|
|
|
|
1,637,748
|
|
Investment
in subsidiaries (equity method)
|
|
|
911,136
|
|
|
|
---
|
|
|
|
702,442
|
|
|
|
(1,613,578
|
)
|
|
|
---
|
|
Other
assets
|
|
|
---
|
|
|
|
39,642
|
|
|
|
758
|
|
|
|
(30,475
|
)
|
|
|
9,925
|
|
Total
assets
|
|
$
|
911,136
|
|
|
$
|
1,541,138
|
|
|
$
|
958,348
|
|
|
$
|
(1,644,053
|
)
|
|
$
|
1,766,569
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
---
|
|
|
$
|
132,538
|
|
|
$
|
6,247
|
|
|
$
|
---
|
|
|
$
|
138,785
|
|
Long-term
liabilities
|
|
|
---
|
|
|
|
706,158
|
|
|
|
40,965
|
|
|
|
(30,475
|
)
|
|
|
716,648
|
|
Stockholders’
equity
|
|
|
911,136
|
|
|
|
702,442
|
|
|
|
911,136
|
|
|
|
(1,613,578
|
)
|
|
|
911,136
|
|
Total
liabilities and stockholders’ equity
|
|
$
|
911,136
|
|
|
$
|
1,541,138
|
|
|
$
|
958,348
|
|
|
$
|
(1,644,053
|
)
|
|
$
|
1,766,569
|
|
(in
thousands)
|
|
December
31, 2006
|
|
|
|
Swift
Energy Co. (Parent and
Co-obligor)
|
|
|
Swift
Energy Operating, LLC
(Co-obligor)
|
|
|
Other
Subsidiaries
|
|
|
Eliminations
|
|
|
Swift
Energy Co. Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
assets
|
|
$
|
---
|
|
|
$
|
75,270
|
|
|
$
|
17,303
|
|
|
$
|
---
|
|
|
$
|
92,573
|
|
Property
and equipment
|
|
|
---
|
|
|
|
1,239,722
|
|
|
|
243,590
|
|
|
|
---
|
|
|
|
1,483,312
|
|
Investment
in subsidiaries (equity method)
|
|
|
797,917
|
|
|
|
---
|
|
|
|
590,720
|
|
|
|
(1,388,637
|
)
|
|
|
---
|
|
Other
assets
|
|
|
---
|
|
|
|
42,519
|
|
|
|
705
|
|
|
|
(33,427
|
)
|
|
|
9,797
|
|
Total
assets
|
|
$
|
797,917
|
|
|
$
|
1,357,511
|
|
|
$
|
852,318
|
|
|
$
|
(1,422,064
|
)
|
|
$
|
1,585,682
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
---
|
|
|
$
|
137,016
|
|
|
$
|
8,959
|
|
|
$
|
---
|
|
|
$
|
145,975
|
|
Long-term
liabilities
|
|
|
---
|
|
|
|
629,775
|
|
|
|
45,442
|
|
|
|
(33,427
|
)
|
|
|
641,789
|
|
Stockholders’
equity
|
|
|
797,917
|
|
|
|
590,720
|
|
|
|
797,917
|
|
|
|
(1,388,637
|
)
|
|
|
797,917
|
|
Total
liabilities and stockholders’ equity
|
|
$
|
797,917
|
|
|
$
|
1,357,511
|
|
|
$
|
852,318
|
|
|
$
|
(1,422,064
|
)
|
|
$
|
1,585,682
|
|
Condensed
Consolidating Statements of Income
(in
thousands)
|
|
Three
Months Ended September 30, 2007
|
|
|
|
Swift
Energy Co. (Parent and
Co-obligor)
|
|
|
Swift
Energy Operating, LLC
(Co-obligor)
|
|
|
Other
Subsidiaries
|
|
|
Eliminations
|
|
|
Swift
Energy Co. Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
---
|
|
|
$
|
171,273
|
|
|
$
|
9,947
|
|
|
$
|
---
|
|
|
$
|
181,220
|
|
Expenses
|
|
|
---
|
|
|
|
100,195
|
|
|
|
11,408
|
|
|
|
---
|
|
|
|
111,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) before the following:
|
|
|
---
|
|
|
|
71,078
|
|
|
|
(1,461
|
)
|
|
|
---
|
|
|
|
69,617
|
|
Equity
in net earnings of subsidiaries
|
|
|
42,282
|
|
|
|
---
|
|
|
|
42,915
|
|
|
|
(85,197
|
)
|
|
|
---
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
42,282
|
|
|
|
71,078
|
|
|
|
41,454
|
|
|
|
(85,197
|
)
|
|
|
69,617
|
|
Income
tax provision (benefit)
|
|
|
---
|
|
|
|
28,163
|
|
|
|
(828
|
)
|
|
|
---
|
|
|
|
27,335
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
42,282
|
|
|
$
|
42,915
|
|
|
$
|
42,282
|
|
|
$
|
(85,197
|
)
|
|
$
|
42,282
|
|
19
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
(in
thousands)
|
|
Nine
Months Ended September 30, 2007
|
|
|
|
Swift
Energy Co. (Parent and
Co-obligor)
|
|
|
Swift
Energy Operating, LLC
(Co-obligor)
|
|
|
Other
Subsidiaries
|
|
|
Eliminations
|
|
|
Swift
Energy Co. Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
---
|
|
|
$
|
457,658
|
|
|
$
|
32,824
|
|
|
$
|
---
|
|
|
$
|
490,482
|
|
Expenses
|
|
|
---
|
|
|
|
296,105
|
|
|
|
33,186
|
|
|
|
---
|
|
|
|
329,291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) before the following:
|
|
|
---
|
|
|
|
161,553
|
|
|
|
(362
|
)
|
|
|
---
|
|
|
|
161,191
|
|
Equity
in net earnings of subsidiaries
|
|
|
101,380
|
|
|
|
---
|
|
|
|
99,883
|
|
|
|
(201,263
|
)
|
|
|
---
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
101,380
|
|
|
|
161,553
|
|
|
|
99,521
|
|
|
|
(201,263
|
)
|
|
|
161,191
|
|
Income
tax provision (benefit)
|
|
|
---
|
|
|
|
61,670
|
|
|
|
(1,859
|
)
|
|
|
---
|
|
|
|
59,811
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
101,380
|
|
|
$
|
99,883
|
|
|
$
|
101,380
|
|
|
$
|
(201,263
|
)
|
|
$
|
101,380
|
|
(in
thousands)
|
|
Three
Months Ended September 30, 2006
|
|
|
|
Swift
Energy Co. (Parent and
Co-obligor)
|
|
|
Swift
Energy Operating, LLC
(Co-obligor)
|
|
|
Other
Subsidiaries
|
|
|
Eliminations
|
|
|
Swift
Energy Co. Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
---
|
|
|
$
|
153,279
|
|
|
$
|
20,179
|
|
|
$
|
---
|
|
|
$
|
173,459
|
|
Expenses
|
|
|
---
|
|
|
|
77,409
|
|
|
|
13,841
|
|
|
|
---
|
|
|
|
91,250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) before the following:
|
|
|
---
|
|
|
|
75,871
|
|
|
|
6,338
|
|
|
|
---
|
|
|
|
82,209
|
|
Equity
in net earnings of subsidiaries
|
|
|
50,812
|
|
|
|
---
|
|
|
|
46,342
|
|
|
|
(97,154
|
)
|
|
|
---
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
50,812
|
|
|
|
75,871
|
|
|
|
52,681
|
|
|
|
(97,154
|
)
|
|
|
82,209
|
|
Income
tax provision (benefit)
|
|
|
---
|
|
|
|
29,528
|
|
|
|
1,869
|
|
|
|
---
|
|
|
|
31,398
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
50,812
|
|
|
$
|
46,342
|
|
|
$
|
50,812
|
|
|
$
|
(97,154
|
)
|
|
$
|
50,812
|
|
(in
thousands)
|
|
Nine
months Ended September 30, 2006
|
|
|
|
Swift
Energy Co. (Parent and
Co-obligor)
|
|
|
Swift
Energy Operating, LLC
(Co-obligor)
|
|
|
Other
Subsidiaries
|
|
|
Eliminations
|
|
|
Swift
Energy Co. Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
---
|
|
|
$
|
406,080
|
|
|
$
|
50,725
|
|
|
$
|
---
|
|
|
$
|
456,805
|
|
Expenses
|
|
|
---
|
|
|
|
218,391
|
|
|
|
38,241
|
|
|
|
---
|
|
|
|
256,631
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) before the following:
|
|
|
---
|
|
|
|
187,690
|
|
|
|
12,484
|
|
|
|
---
|
|
|
|
200,174
|
|
Equity
in net earnings of subsidiaries
|
|
|
126,295
|
|
|
|
---
|
|
|
|
116,811
|
|
|
|
(243,105
|
)
|
|
|
---
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
126,295
|
|
|
|
187,690
|
|
|
|
129,295
|
|
|
|
(243,105
|
)
|
|
|
200,174
|
|
Income
tax provision (benefit)
|
|
|
---
|
|
|
|
70,879
|
|
|
|
3,000
|
|
|
|
---
|
|
|
|
73,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
126,295
|
|
|
$
|
116,811
|
|
|
$
|
126,295
|
|
|
$
|
(243,105
|
)
|
|
$
|
126,295
|
|
Condensed
Consolidating Statements of Cash Flows
(in
thousands)
|
|
Nine
Months Ended September 30, 2007
|
|
|
|
Swift
Energy Co. (Parent and
Co-obligor)
|
|
|
Swift
Energy Operating, LLC
(Co-obligor)
|
|
|
Other
Subsidiaries
|
|
|
Eliminations
|
|
|
Swift
Energy Co. Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flow from operations
|
|
$
|
---
|
|
|
$
|
322,220
|
|
|
$
|
18,099
|
|
|
$
|
---
|
|
|
$
|
340,319
|
|
Cash
flow from investing activities
|
|
|
---
|
|
|
|
(323,147
|
)
|
|
|
(9,095
|
)
|
|
|
(2,952
|
)
|
|
|
(335,194
|
)
|
Cash
flow from financing activities
|
|
|
---
|
|
|
|
5,528
|
|
|
|
(2,952
|
)
|
|
|
2,952
|
|
|
|
5,528
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
increase in cash
|
|
$
|
---
|
|
|
$
|
4,601
|
|
|
$
|
6,052
|
|
|
$
|
---
|
|
|
$
|
10,653
|
|
Cash,
beginning of period
|
|
|
---
|
|
|
|
50
|
|
|
|
1,008
|
|
|
|
---
|
|
|
|
1,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash,
end of period
|
|
$
|
---
|
|
|
$
|
4,651
|
|
|
$
|
7,060
|
|
|
$
|
---
|
|
|
$
|
11,711
|
|
20
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
(in
thousands)
|
|
Nine
Months Ended September 30, 2006
|
|
|
|
Swift
Energy Co. (Parent and
Co-obligor)
|
|
|
Swift
Energy Operating, LLC
(Co-obligor)
|
|
|
Other
Subsidiaries
|
|
|
Eliminations
|
|
|
Swift
Energy Co. Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flow from operations
|
|
$
|
---
|
|
|
$
|
281,570
|
|
|
$
|
29,113
|
|
|
$
|
---
|
|
|
$
|
310,683
|
|
Cash
flow from investing activities
|
|
|
---
|
|
|
|
(237,602
|
)
|
|
|
(46,844
|
)
|
|
|
10,105
|
|
|
|
(274,342
|
)
|
Cash
flow from financing activities
|
|
|
---
|
|
|
|
5,772
|
|
|
|
10,105
|
|
|
|
(10,105
|
)
|
|
|
5,772
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
increase in cash
|
|
$
|
---
|
|
|
$
|
49,740
|
|
|
$
|
(7,627
|
)
|
|
$
|
---
|
|
|
$
|
42,113
|
|
Cash,
beginning of period
|
|
|
---
|
|
|
|
44,911
|
|
|
|
8,094
|
|
|
|
---
|
|
|
|
53,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash,
end of period
|
|
$
|
---
|
|
|
$
|
94,651
|
|
|
$
|
467
|
|
|
$
|
---
|
|
|
$
|
95,118
|
|
(10) Segment
Information
Swift
Energy has two reportable segments, one domestic and one foreign, both of which
are in the business of oil and natural gas exploration and
production. The accounting policies of the segments are the same as
those described in the summary of significant accounting policies. We
evaluate our performance based on pre-tax profit or loss from oil and gas
operations before price-risk management and other, net, general and
administrative, net, debt retirement costs, and interest expense,
net. Our reportable segments are managed separately based on their
geographic locations. Financial information by operating segment is presented
below:
(in
thousands)
|
|
Three
Months Ended September 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Domestic
|
|
|
New
Zealand
|
|
|
Total
|
|
|
Domestic
|
|
|
New
Zealand
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas sales
|
|
$
|
170,001
|
|
|
$
|
9,524
|
|
|
$
|
179,525
|
|
|
$
|
153,754
|
|
|
$
|
19,615
|
|
|
$
|
173,369
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
48,431
|
|
|
|
5,137
|
|
|
|
53,568
|
|
|
|
37,619
|
|
|
|
8,249
|
|
|
|
45,868
|
|
Accretion
of asset retirement obligation
|
|
|
341
|
|
|
|
47
|
|
|
|
388
|
|
|
|
134
|
|
|
|
38
|
|
|
|
172
|
|
Lease
operating costs
|
|
|
17,896
|
|
|
|
3,634
|
|
|
|
21,530
|
|
|
|
9,620
|
|
|
|
3,306
|
|
|
|
12,926
|
|
Severance
and other taxes
|
|
|
19,531
|
|
|
|
621
|
|
|
|
20,152
|
|
|
|
17,252
|
|
|
|
1,238
|
|
|
|
18,490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from oil and gas operations
|
|
$
|
83,802
|
|
|
$
|
85
|
|
|
$
|
83,887
|
|
|
$
|
89,129
|
|
|
$
|
6,784
|
|
|
$
|
95,913
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price-risk
management and other, net
|
|
|
|
|
|
|
|
|
|
|
1,695
|
|
|
|
|
|
|
|
|
|
|
|
90
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General
and administrative, net
|
|
|
|
|
|
|
|
|
|
|
10,265
|
|
|
|
|
|
|
|
|
|
|
|
8,018
|
|
Interest
expense, net
|
|
|
|
|
|
|
|
|
|
|
5,700
|
|
|
|
|
|
|
|
|
|
|
|
5,776
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Income Taxes
|
|
|
|
|
|
|
|
|
|
$
|
69,617
|
|
|
|
|
|
|
|
|
|
|
$
|
82,209
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL
STATEMENTS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
(in
thousands)
|
|
Nine
Months Ended September 30,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
Domestic
|
|
|
New
Zealand
|
|
|
Total
|
|
|
Domestic
|
|
|
New
Zealand
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and gas sales
|
|
$
|
456,534
|
|
|
$
|
31,694
|
|
|
$
|
488,228
|
|
|
$
|
403,129
|
|
|
$
|
50,187
|
|
|
$
|
453,316
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
134,007
|
|
|
|
16,887
|
|
|
|
150,894
|
|
|
|
97,614
|
|
|
|
22,537
|
|
|
|
120,151
|
|
Accretion
of asset retirement obligation
|
|
|
1,031
|
|
|
|
139
|
|
|
|
1,170
|
|
|
|
555
|
|
|
|
111
|
|
|
|
666
|
|
Lease
operating costs
|
|
|
49,788
|
|
|
|
10,172
|
|
|
|
59,960
|
|
|
|
36,342
|
|
|
|
9,502
|
|
|
|
45,844
|
|
Severance
and other taxes
|
|
|
53,372
|
|
|
|
2,093
|
|
|
|
55,465
|
|
|
|
45,958
|
|
|
|
3,253
|
|
|
|
49,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
from oil and gas operations
|
|
$
|
218,336
|
|
|
$
|
2,403
|
|
|
$
|
220,739
|
|
|
$
|
222,660
|
|
|
$
|
14,784
|
|
|
$
|
237,444
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Price-risk
management and other, net
|
|
|
|
|
|
|
|
|
|
|
2,254
|
|
|
|
|
|
|
|
|
|
|
|
3,489
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General
and administrative, net
|
|
|
|
|
|
|
|
|
|
|
29,295
|
|
|
|
|
|
|
|
|
|
|
|
23,323
|
|
Interest
expense, net
|
|
|
|
|
|
|
|
|
|
|
19,742
|
|
|
|
|
|
|
|
|
|
|
|
17,436
|
|
Debt
retirement cost
|
|
|
|
|
|
|
|
|
|
|
12,765
|
|
|
|
|
|
|
|
|
|
|
|
---
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
Before Income Taxes
|
|
|
|
|
|
|
|
|
|
$
|
161,191
|
|
|
|
|
|
|
|
|
|
|
$
|
200,174
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$
|
1,511,303
|
|
|
$
|
255,266
|
|
|
$
|
1,766,569
|
|
|
$
|
1,170,096
|
|
|
$
|
266,407
|
|
|
$
|
1,436,503
|
|
22
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF
FINANCIAL CONDITION AND RSULTS OF
OPERATIONS
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
ITEM
2.
You
should read the following discussion and analysis in conjunction with our
financial information and our condensed consolidated financial statements and
notes thereto included in this report and our Annual Report on Form 10-K for the
year ended December 31, 2006. The following information contains
forward-looking statements. For a discussion of limitations inherent
in forward-looking statements, see “Forward-Looking Statements” on page 31 of
this report.
Overview
Swift
Energy’s third quarter included both strong domestic production and increased
crude oil and NGL prices. Given the current commodity price
environment, our production weighting of 68% crude oil and NGLs continues to aid
our overall price realizations. Including our October 2007 South Texas
acquisition, we estimate full year 2007 production growth of 3% to 4% over 2006
levels. We had previously reduced this amount to 1% to 3% due to
timing delays with projects and market constraints domestically, and production
declines in New Zealand. Similarly, including the South Texas
acquisition, we now estimate reserves growth will be between 7% and 12% for the
year, without any adjustments for the strategic review outcome of our New
Zealand assets. Facility, pressure maintenance and pipeline expansions scheduled
for completion in 2008 will help alleviate the production constraints in our
South Louisiana region.
During
the second quarter of 2007, we began a review of strategic alternatives for our
New Zealand operating unit, Swift Energy New Zealand, Ltd., often referred to as
“SENZ.” Such alternatives include an outright sale or merger of some
or all of the properties and facilities, entry into joint ventures or reshaping
of our long-term operational strategy there. We retained Scotia
Waterous (USA) Inc. as an advisor to the potential sale of some or all of our
New Zealand assets owned and operated by SENZ. The strategic review
is expected to be completed by year end.
In
October 2007, we acquired interests in three South Texas fields in the Maverick
Basin from Escondido Resources, LP. The total price for these
interests was approximately $249.5 million. The property interests
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. We plan to add more producing acreage in this area as
well, and maintain a two rig drilling program in this area into
2008.
In the
third quarter of 2007 as compared to the same period in 2006, our revenues
increased 4% to $181.2 million but total costs increased 22% during the same
period to $111.6 million, resulting in net income of $42.3 million, a 17%
decrease. Our revenue increase is attributable to higher oil and NGL
prices and higher domestic natural gas production, offset by decreased
production in New Zealand. Our overall production decreased 3% to
18.2 Bcfe for the third quarter of 2007 as compared to third quarter 2006
production, including domestic production of 16.2 Bcfe, a 7% increase, and 1.9
Bcfe produced in New Zealand, a 45% decrease. For the nine
months ended September 30, 2007, net income decreased 20% to $101.4 million,
revenues increased 7% to $490.5 million, and production increased 3% to a record
53.4 Bcfe, all as compared to the same period in 2006. The oil and
gas sector, including Swift Energy Company, continued to see third party vendor
costs increase during the third quarter.
Cash flow
provided by operating activities increased 6% to $134.3 million for the third
quarter of 2007, again compared to the cash flow provided by operating
activities in the third quarter of 2006.
To allow
for further production increases in our South Louisiana region, construction
continues on a new barge mounted production facility. This facility will add
10,000 barrels per day of oil processing capacity in Lake Washington, and will
be completed in the first half of 2008. Planning for an expansion of
pipeline capacity in Bay de Chene began during the second quarter of
2007. This expansion is also expected to be completed in
2008.
23
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
We will
continue to utilize our proprietary merged 3D seismic data set in and around our
asset base. This data set is allowing our high impact exploration
inventory to grow in conjunction with an improving developmental drilling
program. We currently have a total of 11 rigs operating, including
five barge rigs in our South Louisiana region, with two in the Lake Washington
area, one rig in both the Bay de Chene and Cote Blanche Island Fields, as well a
non-operated rig in the Bayou Sale/Horseshoe Bayou area. We also have
six land rigs currently operating, three rigs in the AWP Olmos area, two rigs
operating in South Bearhead Creek, and one rig in the recently acquired Sun TSH
area and a second rig is expected to return to this South Texas area in the near
future. No drilling activity occurred in our New Zealand region
during the first nine months of 2007 and due to the on-going strategic review,
no new drilling activity is planned for the remainder of the year.
Results
of Operations – Three Months Ended September 30, 2007 and 2006
Revenues. Our revenues in the
third quarter of 2007 increased by 4% compared to revenues in the same period in
2006, due primarily to an increase in oil prices and higher domestic natural gas
production, partially offset by decreased production in New
Zealand. In the third quarter of 2007, oil production made up 61% of
total production, natural gas made up 32%, and NGL represented 7%. In
the third quarter of 2006, oil production made up 64% of total production,
natural gas made up 29%, and NGL represented 7%.
Our third
quarter 2007 weighted average prices increased 7% to $9.89 per Mcfe from $9.24
in the third quarter of 2006, with oil prices increasing 9% to $76.17 per barrel
from $69.62, natural gas prices increasing 5% to $5.11 per Mcf from $4.87, and
NGL prices rising 26% to $45.59 per barrel from $36.18.
The
following table provides additional information regarding the changes in the
sources of our oil and gas sales and volumes for the periods ended September 30,
2007 and 2006:
|
|
Three
Months Ended September 30,
|
|
Regions
|
|
Oil
and Gas
Sales
(In Millions)
|
|
|
Net
Oil and Gas Sales
Volumes
(Bcfe)
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
South
Texas
|
|
$
|
12.7
|
|
|
$
|
15.0
|
|
|
|
1.8
|
|
|
|
2.2
|
|
Toledo
Bend
|
|
|
13.6
|
|
|
|
10.1
|
|
|
|
1.5
|
|
|
|
1.3
|
|
South
Louisiana
|
|
|
142.4
|
|
|
|
127.9
|
|
|
|
12.8
|
|
|
|
11.6
|
|
Other
|
|
|
1.3
|
|
|
|
0.8
|
|
|
|
0.1
|
|
|
|
0.1
|
|
Total
Domestic
|
|
$
|
170.0
|
|
|
$
|
153.8
|
|
|
|
16.2
|
|
|
|
15.2
|
|
New
Zealand
|
|
|
9.5
|
|
|
|
19.6
|
|
|
|
1.9
|
|
|
|
3.5
|
|
Total
|
|
$
|
179.5
|
|
|
$
|
173.4
|
|
|
|
18.2
|
|
|
|
18.8
|
|
The
following table provides additional information regarding our quarterly oil and
gas sales:
|
|
Sales
Volume
|
|
|
Average
Sales Price
|
|
|
|
Oil
(MBbl)
|
|
|
NGL
(MBbl)
|
|
|
Gas
(Bcf)
|
|
|
Combined
(Bcfe)
|
|
|
Oil
(Bbl)
|
|
|
NGL
(Bbl)
|
|
|
Gas
(Mcf)
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended September 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic
|
|
|
1,783
|
|
|
|
189
|
|
|
|
4.4
|
|
|
|
16.2
|
|
|
$
|
76.20
|
|
|
$
|
48.89
|
|
|
$
|
5.68
|
|
New
Zealand
|
|
|
48
|
|
|
|
41
|
|
|
|
1.4
|
|
|
|
1.9
|
|
|
$
|
74.92
|
|
|
$
|
30.17
|
|
|
$
|
3.32
|
|
Total
|
|
|
1,831
|
|
|
|
230
|
|
|
|
5.8
|
|
|
|
18.2
|
|
|
$
|
76.17
|
|
|
$
|
45.59
|
|
|
$
|
5.11
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended September 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic
|
|
|
1,824
|
|
|
|
159
|
|
|
|
3.3
|
|
|
|
15.2
|
|
|
$
|
69.54
|
|
|
$
|
42.37
|
|
|
$
|
6.07
|
|
New
Zealand
|
|
|
168
|
|
|
|
61
|
|
|
|
2.2
|
|
|
|
3.5
|
|
|
$
|
70.49
|
|
|
$
|
20.09
|
|
|
$
|
3.04
|
|
Total
|
|
|
1,992
|
|
|
|
220
|
|
|
|
5.5
|
|
|
|
18.8
|
|
|
$
|
69.62
|
|
|
$
|
36.18
|
|
|
$
|
4.87
|
|
24
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
In the
third quarter of 2007, our $6.2 million increase in oil, NGL, and natural gas
sales resulted from:
·
|
Volume
variances that had a $9.3 million unfavorable impact on sales, with $11.2
million of decreases coming from the 161,000 Bbl decrease in oil sales
volumes, partially offset by $0.4 million of increases attributable to the
10,000 Bbl increase in NGL sales volumes, and $1.5 million of increases
due to the 0.3 Bcf increase in gas sales volumes; and
|
·
|
Price
variances that had a $15.5 million favorable impact on sales, with $12.0
million of increases attributable to the 9% increase in average oil prices
received, $1.4 million of increases attributable to the 5% increase in
average gas prices received, and $2.1 million of increases attributable to
the 26% increase in average NGL prices
received.
|
Costs and
Expenses. Our expenses in the third quarter of 2007 increased
$20.4 million, or 22%, compared to expenses in the same period of 2006. The
increase was mainly due to a $7.7 million increase in DD&A as our production
and the depletable oil and gas property base increased, an $8.6 million increase
in lease operating expenses due to increased production and higher processing
costs in the current quarter, and a reduction of cost in the third quarter of
2006 related to the settlement of insurance claims from hurricanes Katrina and
Rita.
Our third
quarter 2007 general and administrative expenses, net, increased $2.2 million,
or 28%, from the level of such expenses in the same 2006 period. This
increase was primarily due to costs associated with the New Zealand strategic
evaluation project along with ongoing support costs of our new computer system
implemented in 2007. For the third quarters of 2007 and 2006, our
capitalized general and administrative costs, including capitalized stock
compensation, totaled $7.6 million and $8.1 million,
respectively. Our net general and administrative expenses per Mcfe
produced were $0.57 per Mcfe in the third quarter 2007 and $0.43 per Mcfe in the
third quarter of 2006. The portion of supervision fees recorded as a
reduction to general and administrative expenses was $2.7 million for the third
quarter of 2007 and $2.2 million for the 2006 period.
DD&A
increased $7.7 million, or 17%, in the third quarter of 2007 from the level of
those expenses in the same period of 2006. Domestically, DD&A
increased $10.8 million in the third quarter of 2007 due to increases in the
depletable oil and gas property base, including future development costs and
higher production in the 2007 period. In New Zealand, DD&A
decreased by $3.1 million in the third quarter of 2007 due to lower production
during the 2007 period and due to decreases in the depletable oil and gas
property base, partially offset by lower reserves volumes. Our
DD&A rate per Mcfe of production was $2.95 and $2.45 in the third quarters
of 2007 and 2006, respectively.
We
recorded $0.4 million and $0.2 million of accretion to our asset retirement
obligation in the third quarters of 2007 and 2006.
Our lease
operating costs in the third quarter of 2007 increased $8.6 million, or 67%,
over the level of such expenses in the same 2006
period. Domestically, lease operating costs increased $8.3 million
due to higher production from our South Louisiana area, including costs from
properties acquired in the fourth quarter of 2006, and a change in the
recognition of natural gas and NGL processing costs in the 2007
period. The third quarter of 2006 was also impacted by a $2.8 million
reduction in costs related to the settlement of insurance claims from hurricanes
Katrina and Rita. Our lease operating costs in New Zealand increased
by $0.3 million due to increases in plant and well operating
costs. Our lease operating costs per Mcfe produced were $1.19 in the
third quarter of 2007 and $0.69 in the third quarter of 2006.
In the
third quarter of 2007, severance and other taxes increased $1.7 million, or 9%,
over levels in the third quarter of 2006. The increase was due
primarily to increased domestic production volumes and commodity
pricing. Severance and other taxes, as a percentage of oil and gas
sales, were approximately 11.2% and 10.7% in the third quarters of 2007 and
2006, respectively.
25
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
Our total
interest cost in the third quarter of 2007 was $7.9 million, of which $2.2
million was capitalized. Our total interest cost in the third quarter
of 2006 was $8.0 million, of which $2.2 million was capitalized. We capitalize a
portion of interest related to unproved properties. The decrease of
interest expense in the third quarter of 2007 was primarily attributable to
decreased interest costs on our notes as a result of our notes refinancing
during the second quarter of 2007, partially offset by an increase in borrowings
against our line of credit.
Our
overall effective tax rate was 39.3% and 38.2% in the third quarters of 2007 and
2006. The increase from the third quarter of 2006 rate is primarily
attributable to the $2.6 million increase in the valuation allowance of our
capital loss carryforward asset which was recorded in the third quarter of
2007. Additionally, the effective income tax rate for both periods was
higher than the U.S. statutory rate due to state income taxes, partially offset
by reductions attributable to the currency effect on the New Zealand
operations.
Net Income. For the third
quarter of 2007, our net income of $42.3 million was 17% lower, and Basic EPS of
$1.41 was 19% lower, than our third quarter of 2006 net income of $50.8 million
and Basic EPS of $1.74. Our Diluted EPS in the third quarter of 2007 of $1.38
was 18% lower than our third quarter of 2006 Diluted EPS of $1.68. These lower
amounts are due to an increase in costs that exceeded the increase in oil and
gas revenues during the third quarter of 2007.
Results
of Operations – Nine months Ended September 30, 2007 and 2006
Revenues. Our revenues in the
first nine months of 2007 increased by 7% compared to revenues in the same
period in 2006, due primarily to an increase in production from our South
Louisiana region, which includes the properties acquired during the fourth
quarter of 2006, partially offset by lower production in New
Zealand. These gains were increased by higher NGL prices and higher
New Zealand natural gas prices. In the first nine months of 2007, oil
production made up 63% of total production, natural gas made up 30%, and NGL
represented 7%. In the first nine months of 2006, oil production made
up 61% of total production, natural gas made up 33%, and NGL represented
6%. The percentage of our total production from oil increased as
production in the South Louisiana region, which is predominantly oil, increased
over 2006 levels.
Our first
nine months of 2007 weighted average prices increased 4% to $9.14 per Mcfe from
$8.78 in the first nine months of 2006, with oil prices decreasing slightly to
$66.89 per barrel from $66.92, natural gas prices increasing 9% to $5.48 per Mcf
from $5.02, and NGL prices rising 26% to $41.29 per barrel from
$32.69.
The
following table provides additional information regarding the changes in the
sources of our oil and gas sales and volumes for the nine months ended September
30, 2007 and 2006:
|
|
Nine
Months Ended September 30,
|
|
Regions
|
|
Oil
and Gas
Sales
(In Millions)
|
|
|
Net
Oil and Gas Sales
Volumes
(Bcfe)
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
South
Texas
|
|
$
|
39.5
|
|
|
$
|
48.6
|
|
|
|
5.4
|
|
|
|
6.6
|
|
Toledo
Bend
|
|
|
32.7
|
|
|
|
27.4
|
|
|
|
3.8
|
|
|
|
3.4
|
|
South
Louisiana
|
|
|
380.7
|
|
|
|
323.7
|
|
|
|
37.4
|
|
|
|
30.6
|
|
Other
|
|
|
3.6
|
|
|
|
3.4
|
|
|
|
0.4
|
|
|
|
0.5
|
|
Total
Domestic
|
|
$
|
456.5
|
|
|
$
|
403.1
|
|
|
|
47.0
|
|
|
|
41.1
|
|
New
Zealand
|
|
|
31.7
|
|
|
|
50.2
|
|
|
|
6.4
|
|
|
|
10.5
|
|
Total
|
|
$
|
488.2
|
|
|
$
|
453.3
|
|
|
|
53.4
|
|
|
|
51.6
|
|
26
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
The
following table provides additional information regarding our oil & gas
sales for the nine months ended September 30, 2007 and 2006:
|
|
Sales
Volume
|
|
|
Average
Sales Price
|
|
|
|
Oil
(MBbl)
|
|
|
NGL
(MBbl)
|
|
|
Gas
(Bcf)
|
|
|
Combined
(Bcfe)
|
|
|
Oil
(Bbl)
|
|
|
NGL
(Bbl)
|
|
|
Gas
(Mcf)
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic
|
|
|
5,428
|
|
|
|
457
|
|
|
|
11.7
|
|
|
|
47.0
|
|
|
$
|
66.76
|
|
|
$
|
44.90
|
|
|
$
|
6.32
|
|
New
Zealand
|
|
|
172
|
|
|
|
136
|
|
|
|
4.6
|
|
|
|
6.5
|
|
|
$
|
71.06
|
|
|
$
|
29.16
|
|
|
$
|
3.35
|
|
Total
|
|
|
5,600
|
|
|
|
593
|
|
|
|
16.3
|
|
|
|
53.4
|
|
|
$
|
66.89
|
|
|
$
|
41.29
|
|
|
$
|
5.48
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic
|
|
|
4,866
|
|
|
|
319
|
|
|
|
10.0
|
|
|
|
41.1
|
|
|
$
|
66.75
|
|
|
$
|
41.29
|
|
|
$
|
6.53
|
|
New
Zealand
|
|
|
373
|
|
|
|
191
|
|
|
|
7.1
|
|
|
|
10.5
|
|
|
$
|
69.13
|
|
|
$
|
18.29
|
|
|
$
|
2.92
|
|
Total
|
|
|
5,239
|
|
|
|
510
|
|
|
|
17.1
|
|
|
|
51.6
|
|
|
$
|
66.92
|
|
|
$
|
32.69
|
|
|
$
|
5.02
|
|
In the
first nine months of 2007, our $34.9 million increase in oil, NGL, and natural
gas sales resulted from:
·
|
Volume
variances that had a $22.6 million favorable impact on sales, with $24.2
million of increases coming from the 361,000 Bbl increase in oil sales
volumes, and $2.7 million of increases attributable to the 83,000 Bbl
increase in NGL sales volumes, partially offset by $4.3 million of
decreases due to the 0.9 Bcf decrease in gas sales volumes;
and
|
|
|
·
|
Price
variances that had a $12.3 million favorable impact on sales, of which
$7.4 million of increases attributable to the 9% increase in average gas
prices received, and by $5.1 million of increases attributable to the 26%
increase in average NGL prices received, offset slightly by $0.2 million
of decreases attributable to the less than 1% decrease in average oil
prices received.
|
Costs and
Expenses. Our expenses in the first nine months of 2007
increased $72.7 million, or 28%, compared to expenses in the same period of
2006. The increase was mainly due to a $30.7 million increase in DD&A as our
production and depletable oil and gas property base increased, a $14.1 million
increase in lease operating expenses due to higher production and processing
costs, $12.8 million of debt retirement costs related to the redemption of our
9-3/8% Notes due 2012, and a $6.3 million increase in severance and other taxes
due to increased domestic production volumes in the first nine months of
2007.
Our first
nine months of 2007 general and administrative expenses, net, increased $6.0
million, or 26%, from the level of such expenses in the same 2006
period. This increase was primarily due to an expansion of our
workforce and an increase in stock compensation expense, along with costs
associated with the New Zealand strategic evaluation project and ongoing support
costs of our new computer system implemented in 2007. For the first
nine months of 2007 and 2006, our capitalized general and administrative costs,
including capitalized stock compensation, totaled $23.0 million and $20.7
million, respectively. Our capitalized general and administrative
expenses increased due to the expansion of our workforce and the capitalization
of stock compensation related to the geological and geophysical
workforce. Our net general and administrative expenses per Mcfe
produced were $0.55 per Mcfe in the first nine months of 2007 and $0.45 per Mcfe
in the first nine months of 2006. The portion of supervision fees
recorded as a reduction to general and administrative expenses was $8.0 million
for the first nine months of 2007 and $6.4 million for the 2006
period.
DD&A
increased $30.7 million, or 26%, in the first nine months of 2007 from the level
of those expenses in the same period of 2006. Domestically, DD&A
increased $36.4 million in the first nine months of 2007 due to increases in the
depletable oil and gas property base, including future development
costs and higher production in the 2007
period. In New Zealand, DD&A decreased by $5.7 million
in the
27
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
first
nine months of 2007 due to lower production and decreases in the depletable oil
and gas property base, partially offset by lower reserves volumes. Our DD&A
rate per Mcfe of production was $2.82 and $2.33 in the first nine months of 2007
and 2006, respectively.
We
recorded $1.2 million and $0.7 million of accretions to our asset retirement
obligation in the first nine months of 2007 and 2006.
Our lease
operating costs in the first nine months of 2007 increased $14.1 million, or
31%, over the level of such expenses in the same 2006
period. Domestically, lease operating costs increased $13 due to
higher production from our South Louisiana area, including costs from properties
acquired in the fourth quarter of 2006, and a change in the recognition of
natural gas and NGLprocessing costs in the 2007 period; while 2006 amounts
included a $2.8 million reduction in costs related to the settlement of
insurance claims from hurricanes Katrina and Rita. Our lease
operating costs in New Zealand increased by $0.7 million due to increases in
plant and well operating costs. Our lease operating costs per Mcfe
produced were $1.12 in the first nine months of 2007 and $0.89 in the first nine
months of 2006.
In the
first nine months of 2007, severance and other taxes increased $6.3 million, or
13%, over levels in the first nine months of 2006. The increase was
due primarily to higher production in South Louisiana. 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 taxes to
sales also increases. Severance and other taxes, as a percentage of
oil and gas sales, were approximately 11.4% and 10.9% in the first nine months
of 2007 and 2006, respectively.
Our total
interest cost in the first nine months of 2007 was $26.9 million, of which $7.2
million was capitalized. Our total interest cost in the first nine
months of 2006 was $24.0 million, of which $6.6 million was capitalized. We
capitalize a portion of interest related to unproved properties. The
increase of interest expense in the first nine months of 2007 was primarily
attributable to increased borrowings against our line of credit and was also
impacted by our note refinancing as we recorded, in June 2007, a partial month
of interest on our retired $200 million notes and a full month of interest on
our new $250 million notes. These increased costs were offset
partially by higher capitalized costs and lower interest expense on our new $250
million notes during the third quarter of 2007. The increase in
borrowings during the first nine months of 2007 was primarily due to our fourth
quarter 2006 property acquisitions.
In the
second quarter of 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 37.1% and 36.9% in the first nine months of 2007
and 2006, respectively. The effective income tax rate for both
periods was higher than the U.S. statutory rate primarily due to state income
taxes, and was partially offset by reductions attributable to the currency
effect on the New Zealand operations. The nine month period of 2007
was also impacted by a $2.6M increase in the valuation allowance of our capital
loss carryforward asset, offset somewhat by a decrease in the New Zealand
statutory tax rate.
Net Income. For the first nine
months of 2007, our net income of $101.4 million was 20% lower, and Basic EPS of
$3.39 was 22% lower, than our first nine months of 2006 net income of $126.3
million and Basic EPS of $4.33. Our Diluted EPS in the first nine
months of 2007 of $3.32 was 21% lower than our first nine months of 2006 Diluted
EPS of $4.20. These lower amounts are due to an increase in costs
that exceeded the increase in oil and gas revenues during the first nine months
of 2007 and were also impacted by the $12.8 million in expenses related to our
notes refinancing during the second quarter of 2007.
Share-Based
Compensation
Effective January 1,
2006, we adopted SFAS
No. 123R, “Share-Based
Payment” utilizing the
28
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
modified
prospective approach. Prior to the adoption of SFAS No. 123R, we accounted for
stock option grants in accordance with APB No. 25, “Accounting for
Stock Issued to Employees” (the intrinsic value method), and accordingly,
recognized no compensation expense for employee stock option grants. The
adoption of SFAS No. 123R increased our compensation expense related to employee
stock option grants over pre-implementation period levels.
Under the
modified prospective approach, SFAS No. 123R applies to new awards and to awards
that were outstanding on January 1, 2006 as well as those that are
subsequently modified, repurchased or cancelled. Under the modified prospective
approach, compensation cost recognized in both the three months ended September
30, 2007 and 2006 includes compensation cost for all share-based awards granted
prior to, but not yet vested as of January 1, 2006, based on the grant-date
fair value estimated in accordance with the original provisions of SFAS No. 123,
and compensation cost for all share-based awards granted subsequent to
January 1, 2006, based on the grant-date fair value estimated in accordance
with the provisions of SFAS No. 123R. Prior periods were not restated to reflect
the impact of adopting the new standard.
Upon
adoption of SFAS 123R, we recorded an immaterial cumulative effect of a change
in accounting principle as a result of our change in policy from recognizing
forfeitures as they occur to recognizing expense based on our expectation of the
amount of awards that will vest over the requisite service period for our
restricted stock awards. This amount was recorded in “General and
Administrative, net” in the accompanying condensed consolidated statements
of operations.
We
continue to use the Black-Scholes-Merton option pricing model to estimate the
fair value of stock-option awards with the following weighted-average
assumptions for the indicated periods:
|
|
Three
Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend
yield
|
|
|
0
|
%
|
|
|
0
|
%
|
|
|
0
|
%
|
|
|
0
|
%
|
Expected
volatility
|
|
|
37.5
|
%
|
|
|
39.1
|
%
|
|
|
38.5
|
%
|
|
|
39.5
|
%
|
Risk-free
interest rate
|
|
|
4.0
|
%
|
|
|
4.8
|
%
|
|
|
4.8
|
%
|
|
|
4.9
|
%
|
Expected
life of options (in years)
|
|
|
4.3
|
|
|
|
2.6
|
|
|
|
6.2
|
|
|
|
5.6
|
|
Weighted-average
grant-date fair value
|
|
$
|
14.83
|
|
|
$
|
12.20
|
|
|
$
|
20.05
|
|
|
$
|
19.31
|
|
The
expected term has been calculated using the Securities and Exchange Commission
Staff’s shortcut approach from Staff Accounting Bulletin No. 107. We
have analyzed historical volatility and based on analysis of all relevant
factors use a three-year period to estimate expected volatility of our stock
option grants. We view all awards of stock compensation as a single award with
an expected life equal to the average expected life of component awards and
amortize the award on a straight-line basis over the life of the
award.
At
September 30, 2007, there was $3.8 million of unrecognized compensation cost
related to stock options, which are expected to be recognized over a
weighted-average period of 1.3 years, and unrecognized compensation expense of
$18.9 million related to restricted stock awards which are expected to be
recognized over a weighted-average period of 1.8 years. The compensation expense
for restricted stock awards was determined based on the market price of our
stock at the date of grant applied to the total numbers of shares that were
anticipated to fully vest.
Contractual
Commitments and Obligations
We had no
material changes in our contractual commitments and obligations from December
31, 2006 amounts referenced under “Contractual Commitments and Obligations” in
Management’s Discussion and Analysis” in our Annual Report on form 10-K for the
period ending December 31, 2006.
29
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
Internal
Control over Financial Reporting
We began
an implementation of a new computer system in early 2006; and effective April 1,
2007, we went operational with core elements of the new system. When fully
functional, this system will fully integrate our accounting processes from
production of oil and gas to receipt of cash and from procurement of products
and services to payment for such costs. It also further automates our financial
reporting processes. The system being replaced utilizes multiple
systems that covered the production of oil and gas, procurement of products and
services, and the financial reporting process. With this new computer
system, we anticipate a positive impact on our internal control over financial
reporting, and the Company has updated its internal control over financial
reporting as necessary to accommodate these changes.
With this
change, management testing of the effectiveness of the new system’s impact on
the Company’s internal control environment is ongoing, and most likely will not
be complete until late 2007. Until the system is fully tested,
management continues to perform other parallel procedures and analyses related
to the financial closing and accrual processes to ensure the integrity of our
financial statements.
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 in 2007 from levels
seen in late 2006 and it is currently significantly higher when compared to
longer-term historical prices. Factors such as worldwide supply disruptions,
worldwide economic conditions, weather conditions, fluctuating currency exchange
rates, and political conditions in major oil producing regions, especially the
Middle East and Africa, can cause wide fluctuations in the price of oil.
Domestic natural gas prices continue to remain higher when compared to
longer-term historical prices. North American weather conditions, the industrial
and consumer demand for natural gas, storage levels of natural gas, availability
of LNG from foreign sources, 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 in which we operate continuously change and
professional judgments regarding such tax laws can differ.
On
January 1, 2007, we adopted the recognition and disclosure provisions of FASB
Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an
interpretation of FASB Statement No. 109” (“FIN 48”). Under FIN 48, tax
positions are evaluated for recognition using a more-likely-than-not threshold,
and those tax positions requiring recognition are measured as the largest amount
of tax benefit that is greater than fifty percent likely of being realized upon
ultimate settlement with a taxing authority that has full knowledge of all
relevant information. As a result of adopting FIN 48, we reported a $1.0 million
decrease to our January 1, 2007 retained earnings balance and a corresponding
increase to our deferred tax liability. This is also the total balance of our
unrecognized tax benefits, which would fully impact our effective tax rate if
recognized. We do not expect to recognize significant increases or decreases in
unrecognized tax benefits during the year ended December 31, 2007.
Our
policy is to record interest and penalties relating to income taxes in income
tax expense. As of December 31, 2006 and September 30, 2007 no
interest or penalties relating to income taxes have been
recognized.
Our U.S.
Federal and State of Louisiana income tax returns from 1998 forward remain
subject to examination by tax authorities. Our Texas franchise tax returns for
2005 and prior years have been audited by the Texas State
Comptroller. There are no unresolved items related to those
audits. No other state returns are significant to our financial
position. Our New Zealand income tax returns from 2002 forward remain
subject to examination by the local tax authority.
30
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
In the
third quarter of 2007 we increased the valuation allowance for our capital loss
carryforward assets by $2.6 million. The increase in the valuation
allowance is due to changes in our property disposition plans and increased
income tax expense by $2.6 million in that period.
Liquidity
and Capital Resources
During
the first nine months of 2007, we relied upon our net cash provided by operating
activities of $340.3 million to fund capital expenditures of $335.9
million. During the first nine months of 2006, we relied upon our net
cash provided by operating activities of $310.7 million and proceeds from the
sale of property and equipment of $20.3 million to fund capital expenditures of
$295.5 million.
Subsequent
Events. In October 2007, we acquired interests in three South
Texas fields in the Maverick Basin from Escondido Resources, LP. The
total price for these interests was approximately $249.5 million. The
property interests 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. We have recorded $24.5 million in “Other current assets”
at September 30, 2007 related to the deposit for this acquisition.
Acquisitions. In October 2006,
we acquired interests in five South Louisiana fields from BP America Production
Company. The total price for these interests was approximately $168
million. The property interests are located primarily in: Bayou Sale,
Horseshoe Bayou and Jeanerette fields (all located in St. Mary Parish), High
Island field in Cameron Parish and Bayou Penchant field in Terrebonne Parish. In
addition, we have acquired virtually all of the remaining outstanding interest
in the South Bearhead Creek field, located in Beauregard Parish, Louisiana, for
$4.5 million in November 2006.
Net Cash Provided by Operating
Activities. For the first nine months of 2007, our net cash
provided by operating activities was $340.3 million, representing a 10% increase
as compared to $310.7 million generated during the same 2006 period. The $29.6
million increase in the first nine months of 2007 was primarily due to adding
back increased DD&A and debt retirement costs, and an increase in accounts
receivable in the 2006 period, somewhat offset by a lower net income and
deferred income taxes for the nine months ended at September 30,
2007.
Accounts Receivable. 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 both
September 30, 2007 and December 31, 2006, we had an allowance for doubtful
accounts of less than $0.1 million. The allowance for doubtful
accounts has been deducted from the total “Accounts receivable” balances on the
accompanying balance sheets.
Existing Bank Credit Facility.
We had no borrowings at September 30, 2007 and $31.4 million in
borrowings under our bank credit facility at December 31, 2006. On
June 1, 2007, the facility was paid down with proceeds from the issuance of
$250.0 million in senior notes issued on that date as described below along with
cash flow from operating activities during that period. Effective
November 2007, our bank credit facility consists of a $500.0 million revolving
line of credit with a $400.0 million borrowing base. The borrowing base is
re-determined at least every six months and the next scheduled review is in May
2008. Under the terms of our bank credit facility, we can increase
the commitment amount to the total amount of the borrowing base at our
discretion, subject to the terms of the credit agreement. In
September 2007, we increased the commitment amount from $250.0 million to $350.0
million. 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
31
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
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.
Repurchase of Senior Subordinated
Notes due 2012. On June 18, 2007, we redeemed all $200.0
million of our senior subordinated notes due 2012, and recorded debt retirement
costs of $12.8 million related to this redemption.
Issuance of Senior Notes due
2017. These notes consist of $250.0 million of 7-1/8%
senior notes due 2017, which were issued on June 1, 2007 at 100% of the
principal amount and will mature on June 1, 2017. We incurred
approximately $4.2 million of debt issuance costs related to these notes, which
is included in “Debt issuance costs” on the accompanying balance sheets and will
be amortized to interest expense, net over the life of the notes using the
effective interest method.
Debt
Maturities. Our credit facility, which did not have a balance
at September 30, 2007, extends until October 3, 2011. Our $150.0
million of 7-5/8% senior notes mature July 15, 2011, and our $250.0 million of
7-1/8% senior notes mature June 1, 2017.
Working
Capital. Our working capital improved from a deficit of $53.4
million at December 31, 2006, to a deficit of $19.9 million at September 30,
2007. The improvement was primarily due to our 2007 cash provided by operating
activities exceeding our cash used in investing activities along with the
issuance of our Notes due 2017 offset by the repurchase of our Notes due 2012 in
June 2007.
Capital
Expenditures. In the first nine months of 2007, we relied upon
our net cash provided by operating activities of $340.3 million to fund capital
expenditures of $335.9 million. Our total capital expenditures of
approximately $335.9 million in the first nine months of 2007 included Domestic
expenditures of $326.8 million and expenditures in New Zealand of $9.1
million.
We
completed 35 of 42 domestic wells in the first nine months of 2007, for a
success rate of 83%. A total of 21 wells were drilled in the Lake
Washington area, of which 17 were completed, and seven wells were drilled and
completed in the South Bearhead Creek area. Eight wells were also
drilled and completed in the AWP Olmos area, and three out of six wells were
drilled and completed in the Bay de Chene area. No drilling activity
occurred in our New Zealand region during the first nine months of 2007 and due
to the previously announced review of strategic alternatives in New Zealand, no
drilling activity is planned there for the remainder of the year.
We
adjusted our 2007 capital spending budget to a new range of $681 - $710 million,
which now includes approximately $250 million for our October 2007 acquisition
of South Texas properties, from the previous range of $375 - $400 million, which
did not include acquisitions. Approximately 99% of the budget,
excluding acquisitions, is targeted for domestic activities, predominantly in
our South Louisiana region, with about 1% planned for maintenance activities in
the New Zealand region. With our October 2007 South Texas acquisitions, we
estimate full year production growth of 3% to 4% over 2006 levels, which
includes domestic production growth of 13% to 14% over 2006
levels. Similarly, including the South Texas acquisition, we now
believe reserves growth will be between 7% and 12% for the year, making no
adjustments for the strategic review outcome of our New Zealand
assets. We believe that capital expenditures will exceed our cash
flow from operating activities, and we plan to fund these expenditures with our
credit facility.
For the
first nine months of 2007, we spent $335.9 million on capital expenditures
compared to $295.5 for the 2006 period. For the last three months of
2007, we expect to make capital expenditures of approximately $345 to $375
million, including the October 2007 acquisition of South Texas
properties. Capital expenditures for all of 2006 were $557.5
million.
During
the last three months of 2007, we anticipate drilling or participation in the
drilling of up to an
32
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
additional
nine wells in the South Louisiana region, an additional 20 wells, including
properties purchased from Escondido Resources, LP, in the South Texas area, and
up to four additional wells in the Toledo Bend region.
Our 2007
capital expenditures continue to be focused on developing and producing
long-lived reserves in South Louisiana, South Texas, and Toledo Bend regions,
along with property acquisitions and an expansion of our Lake Washington
facilities. We expect our 2007 total production to increase over 2006 levels,
primarily from our South Louisiana area, Toledo Bend area, and South Texas
acquisitions. We expect production in our New
Zealand region to decrease as a limited amount of new drilling is
currently budgeted to offset the natural production decline of these
regions.
New
Accounting Pronouncements
Effective
January 1, 2007, the Company adopted FASB Interpretation (FIN) No. 48,
"Accounting for Uncertainty in Income Taxes - an interpretation of FASB
Statement No. 109" ("FIN 48"). This interpretation provides
guidance for recognizing and measuring uncertain tax positions, as defined in
SFAS No. 109, “Accounting for Income Taxes.” See additional
discussion of FIN 48 in the Income Taxes section of the footnotes. As
a result of adopting FIN 48, we reported a $1.0 million decrease to our January
1, 2007 retained earnings balance and a corresponding increase to our deferred
tax liability.
In
September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No.
157 addresses how companies should approach measuring fair value when required
by GAAP; it does not create or modify any current GAAP requirements to apply
fair value accounting. SFAS No. 157 provides a single definition for fair value
that is to be applied consistently for all accounting applications, and also
generally describes and prioritizes, according to reliability, the methods and
inputs used in valuations. SFAS No. 157 prescribes various disclosures about
financial statement categories and amounts which are measured at fair value, if
such disclosures are not already specified elsewhere in GAAP. The new
measurement and disclosure requirements of SFAS No. 157 are effective for us in
the first quarter 2008. The Company has not yet determined what impact, if any,
this statement will have on its financial position or results of
operations.
33
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
-Continued
SWIFT ENERGY COMPANY AND
SUBSIDIARIES
Forward
Looking Statements
The
statements contained in this report that are not historical facts are
forward-looking statements as that term is defined in Section 21E of the
Securities and Exchange Act of 1934, as amended. Such forward-looking statements
may pertain to, among other things, financial results, capital expenditures,
drilling activity, development activities, cost savings, production efforts and
volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters
and competition. Such forward-looking statements generally are accompanied by
words such as “plan,” “future,” “estimate,” “expect,” “budget,” “predict,”
“anticipate,” “projected,” “should,” “believe” or other words that convey the
uncertainty of future events or outcomes. Such forward-looking information is
based upon management’s current plans, expectations, estimates and assumptions,
upon current market conditions, and upon engineering and geologic information
available at this time, and is subject to change and to a number of risks and
uncertainties, and therefore, actual results may differ materially. Among the
factors that could cause actual results to differ materially are the uncertainty
of finding, replacing, developing or acquiring reserves; fluctuations in crude
oil, natural gas and natural gas liquids prices or demand; adequate availability
of markets, facilities, skilled personnel, services and supplies; hurricanes or
tropical storms affecting operations; the uncertainty of drilling results;
potential failure or delays in achieving reserve or production levels from
existing and future oil and gas development projects due to operating hazards,
drilling risks and the inherent uncertainties in predicting oil and gas reserves
and oil and gas reservoir performance; requirements for capital; general
economic conditions; changes in geologic or engineering information; changes in
market conditions; competition and government regulations; as well as the risks
and uncertainties discussed herein, and set forth from time to time in our other
public reports, filings and public statements. Also, because of the volatility
in oil and gas prices and other factors, interim results are not necessarily
indicative of those for a full year.
34
Item
3. QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Commodity
Risk
Our major
market risk exposure is the volatile commodity pricing applicable to our oil and
natural gas production. Realized commodity prices received for such production
are primarily driven by the prevailing worldwide price for crude oil and spot
prices applicable to natural gas. The effects of such pricing volatility are
expected to continue.
Our
price-risk management policy permits the utilization of derivative instruments
(such as futures, forward contracts, swaps, and option contracts such as floors
and collars) to mitigate price risk associated with fluctuations in oil and
natural gas prices. Below is a description of the derivative instruments we have
utilized to hedge our exposure to price risk.
·
|
Price
Floors, Collars, and Swaps – At September 30, 2007, we did not have any
price floors, collars, or swaps in
place.
|
·
|
New
Zealand Gas Contracts – All of our
current gas production in New Zealand is sold under fixed-price contracts
denominated in New Zealand dollars. These contracts protect against price
volatility, and our revenue from these contracts will vary only due to
production fluctuations and foreign exchange
rates.
|
Customer
Credit Risk
We are
exposed to the risk of financial non-performance by customers. Our ability to
collect on sales to our customers is dependent on the liquidity of our customer
base. To manage customer credit risk, we monitor credit ratings of customers and
seek to minimize exposure to any one customer where other customers are readily
available. Due to availability of other purchasers, we do not believe that the
loss of any single oil or gas customer would have a material adverse effect on
our financial position or results of operations.
Foreign
Currency Risk
We are
exposed to the risk of fluctuations in foreign currencies, most notably the New
Zealand dollar. Fluctuations in rates between the New Zealand dollar
and U.S. dollar may impact our financial results from our New Zealand
subsidiaries since we have receivables, liabilities, natural gas and NGL sales
contracts, and New Zealand income tax obligations, all denominated in New
Zealand dollars. We use the U.S. dollar as our functional currency in
New Zealand and because of this; our results of operations, cash flows and
effective tax rate are impacted from fluctuations between the U.S. dollar and
the New Zealand dollar.
Interest
Rate Risk
Our
Senior Notes due 2011 and Senior Notes due 2017 have fixed interest rates;
consequently we are not exposed to cash flow risk from market interest rate
changes on these notes. However, there is a risk that market rates
will decline and the required interest payments on our Senior Notes and Senior
Subordinated Notes may exceed those payments based on the current market
rate. At September 30, 2007, we had no borrowings under our credit
facility, which is subject to floating rates and therefore susceptible to
interest rate fluctuations. The result of a 10% fluctuation in the
bank’s base rate would constitute 78 basis points and would not have a material
adverse effect on our 2007 cash flows based on this same level or a modest level
of borrowing.
35
Item
4. CONTROLS
AND PROCEDURES
Disclosure
Controls and Procedures
We
maintain disclosure controls and procedures designed to ensure that information
required to be disclosed in our filings under the Securities Exchange Act of
1934 is recorded, processed, summarized and reported within the time periods
specified in the Securities and Exchange Commission rules and
forms. Our chief executive officer and chief financial officer have
evaluated our disclosure controls and procedures as of the end of the period
covered by this report and have concluded that such disclosure controls and
procedures are effective in ensuring that material information required to be
disclosed in this report is accumulated and communicated to them and our
management to allow timely decisions regarding required disclosure.
Internal
Control Over Financial Reporting
There was
no change in our internal control over financial reporting during the third
quarter of 2007 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
36
SWIFT
ENERGY COMPANY
PART
II. - OTHER INFORMATION
Item
1. Legal
Proceedings.
No
material legal proceedings are pending other than ordinary, routine litigation
incidental to the Company’s business.
Item
1A. Risk
Factors.
There
have been no material changes in our risk factors from those disclosed in our
2006 Annual Report on Form 10-K.
Item
2. Unregistered
Sales of Equity Securities and Use of Proceeds.
The
following table summarizes repurchases of our common stock occurring during the
third quarter of 2007:
Period
|
|
Total
Number of Shares Purchased
|
|
Average
Price Paid Per Share
|
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans or
Programs
|
|
Approximate
Dollar Value of Shares that May Yet Be Purchased Under the Plans or
Programs (in thousands)
|
|
|
|
|
|
|
|
|
|
07/01/07
– 07/31/07 (1)
|
|
15,384
|
|
$42.47
|
|
---
|
|
$---
|
08/01/07
– 08/31/07 (1)
|
|
3,788
|
|
41.77
|
|
---
|
|
---
|
09/01/07
– 09/30/07 (1)
|
|
---
|
|
---
|
|
---
|
|
---
|
Total
|
|
19,172
|
|
$42.33
|
|
---
|
|
$---
|
(1) These
shares were withheld from employees to satisfy tax obligations arising upon the
vesting of restricted shares.
Item
3. Defaults
Upon Senior Securities.
None.
Item
4. Submission
of Matters to a Vote of Security Holders.
None.
Item
5. Other
Information.
None.
Item
6. Exhibits.
|
|
1.1
|
Underwriting
Agreement dated May 17, 2007 among Swift Energy Company, Swift Energy
Operating, LLC and J.P. Morgan Securities Inc. (incorporated by reference
as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed May 30, 2007,
File No. 1-08754).
|
|
|
|
10.1*
|
Asset
Purchase and Sale Agreement between Escondido Resources LP and Swift
Energy Operating, LLC dated as of September 4, 2007 but effective as of
July 1, 2007.
|
|
|
|
31.1*
|
Certification
of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
|
|
31.2*
|
Certification
of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
37
|
|
32*
|
Certification
of Chief Executive Officer and Chief Financial Officer pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
|
|
*
|
Filed Herewith
|
38
SIGNATURES
Pursuant
to the requirements of the Securities Exchange Act of 1934, the Registrant has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
|
|
SWIFT
ENERGY COMPANY
(Registrant)
|
|
|
|
Date: February
19, 2008
|
|
By:
|
/s/
Alton D. Heckaman, Jr.
|
|
|
|
Alton
D. Heckaman, Jr.
Executive
Vice President and
Chief
Financial Officer
|
|
|
|
|
Date: February
19, 2008
|
|
By:
|
/s/
David W. Wesson
|
|
|
|
David
W. Wesson
Controller
and Principal Accounting Officer
|
|
|
|
|
39