UNITED STATES OF AMERICA
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2005.
or
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _______ TO _______.
Commission file number: 333-29001-01
ENERGY CORPORATION OF AMERICA
(Exact name of registrant as specified in its charter)
WEST VIRGINIA 84-1235822
(State or other jurisdiction of incorporation or organization)
(IRS Employer Identification No.)
4643 SOUTH ULSTER STREET, SUITE 1100
DENVER, COLORADO 80237
(Address of principal executive offices and zip code)
(303) 694-2667
(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 (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [_]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes [_] No [X]
The number of shares of the Registrant's common stock, par value $1.00 per
share, outstanding at May 10, 2005 was 598,777 shares.
ENERGY CORPORATION OF AMERICA
TABLE OF CONTENTS
PAGES
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets as of
March 31, 2005 and June 30, 2004. . . . . . . . . . . . . . . . . . .3
Unaudited Condensed Consolidated Statements of Operations
For the three and nine months ended March 31, 2005 and 2004. . . . . 5
Unaudited Condensed Consolidated Statements of Cash Flows
For the nine months ended March 31, 2005 and 2004. . . . . . . . . . 6
Unaudited Condensed Consolidated Statements of Comprehensive Income
For the three and nine months ended March 31, 2005 and 2004. . . . . 7
Notes to Unaudited Condensed Consolidated Financial Statements. . . . .8
Item 2. Management's Discussion and Analysis of Results of Operations
and Financial Condition. . . . . . . . . . . . . . . . . . .15
Item 3. Quantitative and Qualitative Disclosures About Market Risk. . 25
Item 4. Controls and Procedures. . . . . . . . . . . . . . . . . . . .27
PART II OTHER INFORMATION
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . 28
Item 2. Changes in Securities . . . . . . . . . . . . . . . . . . . . 28
Item 3. Defaults Upon Senior Securities . . . . . . . . . . . . . . . 28
Item 4. Submission of Matters to a Vote of Security Holders . . . . . 28
Item 5. Other Information . . . . . . . . . . . . . . . . . . . . . . 28
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . . . . 29
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30
- 2 -
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ENERGY CORPORATION OF AMERICA
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(AMOUNTS IN THOUSANDS)
- ---------------------------------------------------------------------------------
MARCH 31, JUNE 30,
2005 2004
----------- ----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 3,717 $ 5,821
Accounts receivable:
Oil and gas sales 9,266 8,632
Gas aggregation and pipeline 12,004 9,079
Other 4,519 4,000
----------- ----------
Accounts receivable 25,789 21,711
Less allowance for doubtful accounts (898) (1,022)
----------- ----------
Accounts receivable, net of allowance 24,891 20,689
Deferred income tax asset 612 2,087
Deferred taxes - other comprehensive loss 4,694 2,889
Notes receivable, related party 49 59
Derivatives 313 -
Prepaid and other current assets 2,024 4,141
----------- ----------
Total current assets 36,300 35,686
Property, plant and equipment, net of accumulated
depreciation and depletion of $154,301 and $143,846 257,826 246,391
OTHER ASSETS:
Deferred financing costs, net of accumulated
amortization of $7,628 and $6,833 1,943 2,015
Notes receivable, related party 369 113
Derivatives 345 -
Other 5,890 6,007
----------- ----------
Total other assets 8,547 8,135
----------- ----------
TOTAL $ 302,673 $ 290,212
=========== ==========
The accompanying notes are an integral part of the unaudited condensed
consolidated financial statements.
- 3 -
ENERGY CORPORATION OF AMERICA
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(AMOUNTS IN THOUSANDS)
- ------------------------------------------------------------------------------------
MARCH 31, JUNE 30,
2005 2004
----------- ----------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses $ 9,216 $ 14,823
Current portion of long-term debt 155 1,145
Funds held for future distribution 17,528 16,701
Income taxes payable 2,349 128
Accrued taxes, other than income 9,780 9,289
Derivatives 8,648 7,303
Other current liabilities 1,173 3,562
----------- ----------
Total current liabilities 48,849 52,951
LONG-TERM OBLIGATIONS:
Long-term debt 176,484 162,894
Deferred trust revenue 2,228 2,511
Deferred income tax liability 17,230 19,552
Derivatives 1,807 -
Other long-term obligations 8,115 8,447
----------- ----------
Total liabilities 254,713 246,355
Minority Interest 1,329 1,495
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Common stock, par value $1.00; 2,000,000 shares
authorized; 730,039 shares issued 730 730
Class A non-voting common stock, no par value; 100,000
shares authorized; 69,615 and 68,237 shares issued 8,260 8,027
Additional paid-in capital 5,503 5,503
Retained earnings 54,541 48,200
Treasury stock and notes receivable arising from the
issuance of common stock (15,580) (14,954)
Deferred compensation on restricted stock (1,581) (1,887)
Accumulated other comprehensive loss (5,242) (3,257)
----------- ----------
Total stockholders' equity 46,631 42,362
----------- ----------
TOTAL $ 302,673 $ 290,212
=========== ==========
The accompanying notes are an integral part of the unaudited condensed consolidated
financial statements.
- 4 -
ENERGY CORPORATION OF AMERICA
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(AMOUNTS IN THOUSANDS)
- ---------------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED NINE MONTHS ENDED
MARCH 31, MARCH 31,
------------------------ -----------------------
2005 2004 2005 2004
---------- ------------ ---------- -----------
REVENUES:
Oil and gas sales $ 18,505 $ 14,735 $ 48,408 $ 43,255
Gas aggregation and pipeline sales 19,886 16,126 54,826 46,202
Well operations and service revenues 1,196 1,243 3,859 3,912
Other - 100 467 148
---------- ------------ ---------- -----------
Total revenues 39,587 32,204 107,560 93,517
---------- ------------ ---------- -----------
COST AND EXPENSES:
Field operating expenses 3,076 2,817 8,692 8,527
Gas aggregation and pipeline cost of sales 18,394 14,645 50,525 42,641
General and administrative 3,911 3,930 11,262 11,419
Taxes, other than income 1,284 1,132 3,530 2,966
Depletion and depreciation of oil and gas properties 3,288 3,269 9,255 10,186
Depreciation of pipelines, other property and equipment 1,086 1,055 3,167 3,104
Exploration and impairment 1,282 1,021 3,716 3,642
Gain on sale of assets (86) (175) (3,002) (283)
---------- ------------ ---------- -----------
Total costs and expenses 32,235 27,694 87,145 82,202
---------- ------------ ---------- -----------
Income from operations 7,352 4,510 20,415 11,315
OTHER (INCOME) EXPENSE:
Interest expense 3,239 3,766 9,627 11,354
Interest income and other 156 (24) 1,512 (1,099)
---------- ------------ ---------- -----------
Income before income taxes and minority interest 3,957 768 9,276 1,060
Income tax expense (benefit) 1,019 (3,850) 2,031 (3,692)
---------- ------------ ---------- -----------
Income before minority interest 2,938 4,618 7,245 4,752
Minority interest 53 13 172 118
---------- ------------ ---------- -----------
NET INCOME $ 2,991 $ 4,631 $ 7,417 $ 4,870
========== ============ ========== ===========
The accompanying notes are an integral part of the unaudited condensed consolidated financial statements.
- 5 -
ENERGY CORPORATION OF AMERICA
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(AMOUNTS IN THOUSANDS)
- --------------------------------------------------------------------------------------
NINE MONTHS ENDED
MARCH 31,
-----------------------
2005 2004
---------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 7,417 $ 4,870
Adjustments to reconcile net income to
net cash provided (used) by operating activities:
Depletion, depreciation and amortization 12,422 13,290
Gain on sale of assets (3,002) (283)
(Gain) loss on redemption of senior bonds 249 (513)
Deferred income taxes (846) (4,161)
Exploration and impairment 3,511 3,590
Other, net 93 637
---------- -----------
19,844 17,430
Changes in assets and liabilities:
Accounts receivable (4,203) 5,072
Income taxes payable 2,222 525
Prepaid and other assets (1,409) (324)
Accounts payable and accrued expenses (5,228) (4,657)
Funds held for future distribution 827 (2,044)
Other (2,899) 282
---------- -----------
Net cash provided by operating activities 9,154 16,284
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (25,827) (11,051)
Proceeds from sale of assets 3,984 990
Notes receivable and other (304) 34
---------- -----------
Net cash used by investing activities (22,147) (10,027)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 132,651 36,380
Principal payments on long-term debt (120,051) (43,528)
Purchase of treasury stock and other financing activities (712) (657)
Proceeds from issuance of stock - 257
Dividends paid (999) (928)
---------- -----------
Net cash provided (used) by financing activities 10,889 (8,476)
---------- -----------
Net decrease in cash and cash equivalents (2,104) (2,219)
Cash and cash equivalents, beginning of period 5,821 4,831
---------- -----------
Cash and cash equivalents, end of period $ 3,717 $ 2,612
========== ===========
The accompanying notes are an integral part of the unaudited condensed consolidated
financial statements.
- 6 -
ENERGY CORPORATION OF AMERICA
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(AMOUNTS IN THOUSANDS)
- -----------------------------------------------------------------------------------------------------------------------
THREE MONTHS ENDED NINE MONTHS ENDED
MARCH 31, MARCH 31,
------------------------ -----------------------
2005 2004 2005 2004
---------- ------------ ----------- ----------
Net income $ 2,991 $ 4,631 $ 7,417 $ 4,870
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustment:
Current period change (166) 63 750 956
Oil and gas derivatives:
Current period transactions (6,267) (927) (5,261) (1,250)
Reclassification to earnings (116) (50) 2,539 121
Interest rate hedging:
Current period transactions 121 - (13) -
Reclassification to earnings - - - -
---------- ------------ ----------- ----------
Other comprehensive loss, net of tax (6,428) (914) (1,985) (173)
---------- ------------ ----------- ----------
Comprehensive income (loss) $ (3,437) $ 3,717 $ 5,432 $ 4,697
========== ============ =========== ==========
The accompanying notes are an integral part of the condensed consolidated financial statements.
- 7 -
ENERGY CORPORATION OF AMERICA
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2005
1. Nature of Organization
Energy Corporation of America (the "Company") is a privately held
energy company engaged in the exploration, development, production,
gathering and aggregation of natural gas and oil, primarily in the
Appalachian Basin and Gulf Coast regions in the United States and in New
Zealand. The Company conducts business primarily through its principal
wholly owned subsidiaries and is one of the largest oil and gas operators
in the Appalachian Basin. As used herein the "Company" refers to the
Company alone or together with one or more of its subsidiaries.
2. Accounting Policies
Reference is hereby made to the Company's Annual Report on Form 10-K
for the fiscal year ended June 30, 2004, which contains a summary of major
accounting policies followed in preparation of its consolidated financial
statements. Those policies were also followed in preparing the quarterly
report included herein.
Management of the Company believes that all adjustments, consisting of
only normal recurring accruals, necessary for a fair presentation of the
results of such interim periods have been made. The results of operations
for the period ended March 31, 2005 are not necessarily indicative of the
results to be expected for the full year.
Certain amounts in the financial statements of prior periods have been
reclassified to conform to the current period presentation.
Recent Accounting Pronouncements - On December 16, 2004, the Financial
Accounting Standards Board ("FASB") published Statement of Financial
Accounting Standards No. 123 (Revised 2004), Share Based Payment ("SFAS
123R"). SFAS 123R requires that compensation cost related to share-based
payment transactions be recognized in the financial statements. Share-based
payment transactions within the scope of SFAS 123R include stock options,
restricted stock plans, performance-based awards, stock appreciation
rights, and employee share purchase plans. The provisions of SFAS 123R are
effective as of the first fiscal year beginning after June 15, 2005.
Accordingly, the Company will implement the revised standard in the first
quarter of fiscal year 2006. Currently, the Company accounts for its
share-based payment transactions under the provisions of APB 25, which does
not necessarily require the recognition of compensation cost in the
financial statements. Management is assessing the implications of this
revised standard and the effect of the adoption of SFAS 123R will have on
our financial position, results of operations, or cash flow.
- 8 -
Supplemental Disclosures of Cash Flow Information - Supplemental cash
flow information for the nine months ended March 31 is as follows (in
thousands):
NINE MONTHS ENDED
MARCH 31,
---------------------
2005 2004
--------- ----------
Cash paid for:
Interest $ 6,884 $ 8,039
Income taxes 528 -
Income taxes refunded - -
3. Note Repurchases
The Company purchased $34.0 million of its 9 1/2% Senior Subordinated
Notes ("Notes") during the nine months ended March 31, 2005 pursuant to an
Asset Sale Offer as defined in the Indenture for the Notes. The Company
purchased $6.04 million of its Notes during the nine months ended March 31,
2004 in privately negotiated transactions.
4. Industry Segments
The Company's reportable business segments have been identified based
on the differences in products and service provided. Revenues for the
exploration and production segment are derived from the production and sale
of natural gas and crude oil. Revenues for the gas aggregation and pipeline
segment arise from the marketing of both Company and third party produced
natural gas volumes and the related transportation. Management utilizes
earnings before interest, taxes, depreciation, depletion, amortization and
exploration and impairment costs ("EBITDAX") to evaluate the operations of
each segment.
- 9 -
Summarized financial information for the Company's reportable segments
for operations is as follows for the three months ended March 31, 2005 and
2004 (in thousands):
Exploration & Gas Aggregation
Production & Pipeline Other Consolidated
-------------- ---------------- --------- -------------
For the three months ended March 31, 2005
------------------------------------------
Revenue from unaffiliated customers $ 19,701 $ 19,886 $ - $ 39,587
Depreciation, depletion, amortization 3,716 153 505 4,374
Exploration and impairment costs 1,282 - - 1,282
Interest expense, net 5,567 (2,244) (100) 3,223
EBITDAX 12,283 712 (90) 12,905
Total assets 177,904 107,819 16,950 302,673
Capital expenditures 6,946 229 1,036 8,211
=====================================================================================================
For the three months ended March 31, 2004
------------------------------------------
Revenue from unaffiliated customers $ 15,978 $ 16,126 $ 100 $ 32,204
Depreciation, depletion, amortization 3,637 156 531 4,324
Exploration and impairment costs 1,021 - - 1,021
Interest expense, net 5,351 (1,897) 247 3,701
EBITDAX 7,652 972 1,267 9,891
Total assets 174,437 94,970 13,430 282,837
Capital expenditures 3,321 28 (43) 3,306
=====================================================================================================
- 10 -
Reconciliation of EBITDAX is as follows for the three months ended
March 31, 2005 and 2004 (in thousands):
Three Months Ended
March 31, March 31,
2005 2004
---------- -----------
Net income $ 2,991 $ 4,631
Add:
Interest expense 3,239 3,766
Depletion and depreciation of oil and gas properties 3,288 3,269
Depreciation of pipelines, other property and equipment 1,086 1,055
Exploration and impairment 1,282 1,021
Income tax expense (benefit) 1,019 (3,850)
---------- -----------
EBITDAX $ 12,905 $ 9,892
========== ===========
Summarized financial information for the Company's reportable segments for
operations is as follows for the nine months ended March 31, 2005 and 2004 (in
thousands):
Exploration & Gas Aggregation
Production & Pipeline Other Consolidated
-------------- ----------------- -------- -------------
For the nine months ended March 31, 2005
-----------------------------------------
Revenue from unaffiliated customers $ 52,267 $ 54,826 $ 467 $ 107,560
Depreciation, depletion, amortization 10,500 459 1,463 12,422
Exploration and impairment costs 3,716 - - 3,716
Interest expense, net 16,581 (6,342) (685) 9,554
EBITDAX 34,843 2,096 (1,726) 35,213
Total assets 177,905 107,819 16,949 302,673
Capital expenditures 23,650 426 1,751 25,827
=====================================================================================================
For the nine months ended March 31, 2004
-----------------------------------------
Revenue from unaffiliated customers $ 47,167 $ 46,202 $ 148 $ 93,517
Depreciation, depletion, amortization 11,214 475 1,601 13,290
Exploration and impairment costs 3,626 16 - 3,642
Interest expense, net 16,676 (5,494) (29) 11,153
EBITDAX 27,047 2,027 390 29,464
Total assets 174,437 94,970 13,430 282,837
Capital expenditures 10,919 38 94 11,051
=====================================================================================================
- 11 -
Reconciliation of EBITDAX is as follows for the nine months ended
March 31, 2005 and 2004 (in thousands):
Nine Months Ended
March 31, March 31,
2005 2004
---------- -----------
Net income $ 7,417 $ 4,870
Add:
Interest expense 9,627 11,354
Depletion and depreciation of oil and gas properties 9,255 10,186
Depreciation of pipelines, other property and equipment 3,167 3,104
Exploration and impairment 3,716 3,642
Income tax expense (benefit) 2,031 (3,692)
---------- -----------
EBITDAX $ 35,213 $ 29,464
========== ===========
Revenues are priced and accounted for consistently for both
unaffiliated and intersegment sales. The 'Other' column includes items
related to non-reportable segments, including drilling rig, corporate and
elimination items. Included in the total assets of the exploration and
production segment are net long-lived assets located in New Zealand of
$10.7 million and $6.9 million as of March 31, 2005 and 2004 with $0.1
million in revenues recorded for the three and nine months ended March 31,
2005 as compared to no significant revenue recorded for the three months
ended March 31, 2004 and $0.3 million recorded for the nine months ended
March 31, 2004.
5. Derivative Instruments
The Company periodically hedges a portion of its gas production through
futures, swaps, floors and collar agreements. The purpose of the hedges is
to provide a measure of stability in the volatile environment of oil and
gas prices and to manage its exposure to commodity price risk under
existing sales commitments. All of the Company's swap, floor and collar
agreements in place are designated as cash flow hedges.
For swaps in place at March 31, 2005, the Company had recorded a $4.7
million other comprehensive loss, $3.1 million short-term deferred tax
asset, $6.3 million short-term derivative liability, and $1.5 million
long-term derivative liability. The estimated net amount of the existing
losses within other comprehensive income that are expected to be
reclassified into earnings within the next twelve months is approximately
$3.8 million. The Company has partially hedged its exposure to the
variability in future cash flows through December 2007.
For floors in place at March 31, 2005, the Company had recorded a $0.8
million other comprehensive loss, $0.5 million short-term deferred tax
asset, and $0.2 million short-term derivative asset. The estimated net
amount of existing losses within other comprehensive income that are
expected to be reclassified into earnings within the next twelve months is
approximately $0.8
- 12 -
million. The Company has partially hedged its exposure to the
variability in future cash flows through March 2006.
For collars in place at March 31, 2005, the Company had recorded a
$1.6 million other comprehensive loss, $1.0 million short-term deferred tax
asset, $2.3 million short-term derivative liability, and $0.3 million
long-term derivative liability. No amount of the existing losses within
other comprehensive income is expected to be reclassified into earnings
within the next twelve months. The Company has partially hedged its
exposure to the variability in future cash flows through December 2007.
In August 2004, the Company entered into four interest rate cap
agreements with Wells Fargo Foothill, Inc. ("Foothill"), in an effort to
reduce the potential impact of increases in interest rates on floating-rate
long-term debt. The agreements range from two to three years covering
$40,000,000 in long-term debt and cap the one month London Interbank
Offered Rate ("LIBOR") at 3.5%. At March 31, 2005, the Company has recorded
a $13,000 other comprehensive loss, $8,400 short-term deferred tax asset,
$149,000 short-term derivative asset, and $345,000 long-term derivative
asset. The estimated net amount of existing losses within other
comprehensive income that are expected to be reclassified into earnings
within the next twelve months is approximately $3,800. The Company has
partially hedged its exposure to the variability in future cash flows
through July 2007.
6. Commitments and Contingencies
The Company is involved in legal actions and claims arising in the
ordinary course of business. While the outcome of these lawsuits against
the Company cannot be predicted with certainty, management does not expect
these matters to have a material adverse effect on the Company's operations
or financial position.
Pursuant to an Agreement dated December 28, 1998, the Company is
required to purchase all shares owned by Kenneth W. Brill upon notice by
Mr. Brill's estate or promptly after the passage of two years from Mr.
Brill's death if the estate does not sooner tender the shares. The Company
entered into a repurchase agreement on January 21, 2004 with the KWB Trust
to define the purchase price and establish the conditions for the
repurchase of stock owned by the Kenneth W. Brill estate. The agreement
outlines the repurchase of 49,110 shares of stock by the Company or through
third parties, at an anticipated value of approximately $3.7 million over
the next five years, and provides for payments in twenty quarterly
installments on the majority of the shares to be repurchased. The
repurchase of shares is subject to certain restrictions in the Company's
credit agreements. On March 31, 2005, the Company's remaining repurchase
obligation under the Agreement is approximately $2.5 million of which $1.3
million was classified as a liability and the remaining $1.2 million is
included in stockholders' equity as third parties have agreed to purchase
such amount.
During June 2004, the Company sold its membership interest in
Breitburn Energy Company, LLC and established a $1.8 million reserve
against items for which the Company was required to indemnify the buyer for
a period of 180 days after closing pursuant to the agreement. This
requirement was fulfilled during the quarter ended December 31, 2004 with
no such claims from the buyer and was recorded as gain on sale of assets.
- 13 -
7. Related Party Transaction
Pursuant to an Agreement dated December 31, 2004, the Company advanced
$0.3 million to a certain officer bearing 5% interest. The principal amount
is due in full, unless paid sooner, on December 31, 2008 and is secured by
a stock pledge agreement.
8. Income Taxes
The Company is currently under examination by the U.S. Internal
Revenue Service of its federal income tax returns for the tax years ending
June 30, 2002 and 2003. At December 31, 2004, the Company recorded a $2.3
million current income taxes payable and corresponding reduction to
deferred tax liability resulting from a deferral in the timing of certain
deductions arising from abandoned properties. In addition, in March 2005,
the State of West Virginia Department of Revenue notified the Company that
its tax returns for the open tax years had been selected for audit.
Management of the Company continues to believe that it has adequately
provided for any potential tax liability that may be ultimately assessed by
the IRS or West Virginia DOR.
9. Debt
The Company has an unsecured revolving line of credit totaling $3.0
million with a financial institution with an interest rate of prime plus
0.25%. Based upon the original terms of the agreement, the line was to
reduce by $1.0 million in November 2004 and was to expire on June 30, 2005.
The unsecured revolving line of credit was renegotiated during the quarter
ended December 31, 2004 to extend the terms of the agreement. Under the new
agreement the Company has an unsecured line of credit totaling $3.0
million, which reduces by $1.0 million in June 2005 and expires on April 1,
2007.
10. Employee Benefit Plans
Effective January 1, 2005, the Company amended its 401(k) plan to
provide for matching based on each participant's length of service with the
Company. The matching percentages are as follows:
Matching
LENGTH OF SERVICE Percentage
----------------- -----------
0 - 10 years ___________________________ 35%
10 - 15 years ___________________________ 45%
15 - 20 years ___________________________ 55%
20 or more years ___________________________ 65%
The amended matching percentages are in effect until further amended
by the ECA Board of Directors.
11. Anticipated Transaction
On April 4, 2005 the Company filed registration statement with the
Securities and Exchange Commission ("SEC") relating to an initial public
offering of Trust units proposed to be issued by a new royalty trust which
will be known as the Appalachian Gas Royalty Trust ("Trust"). The Trust
- 14 -
units of the Trust will be listed on the New York Stock Exchange under
the symbol "ANG". The royalty interest created by the Company will entitle
the Trust to receive 90% of the net proceeds from the sale of future
production of natural gas attributable to the Company's interest in 312
existing producing wells and 50% of the net proceeds from the sale of
future production of natural gas attributable to the Company's interest in
180 additional wells that the Company is obligated to drill by March 31,
2009. The term of the Trust will extend for a period of 20 years commencing
as of January 1, 2005. Upon termination of the Trust, the royalty interest
held by the Trust will revert to the Company.
The Company will receive the net proceeds from the sale of the Trust
units, currently estimated to be approximately $142 million (after
deduction of underwriting commissions and expenses of the offering), in
exchange for the contributions of the royalty interest to the Trust. The
completion of the offering is subject to a number of conditions, including
clearance of the registration statement by the SEC, and will depend upon
market conditions at the time of the offering of the units as well as
sufficient investor demand for the Trust units. As a result, there can be
no assurance that this transaction will be completed or, if completed, that
the Company will realize the full amount of the net proceeds currently
estimated.
A registration statement relating to the Trust units has been filed
with the SEC but has not yet become effective. The Trust units may not be
sold nor may offers to buy be accepted prior to the time the registration
statement become effective.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
----------------------------------------------------------------------
AND FINANCIAL CONDITION
-----------------------
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
- --------------------------------------------------------------------------------
This discussion and analysis of financial condition and results of
operations, and other sections of this Form 10-Q, contain forward-looking
statements that are based on management's beliefs, assumptions, current
expectations, estimates, intentions and projections about the oil and gas
industry, the economy and about the Company itself. Words such as
"anticipates," "believes," "estimates," "expects," "forecasts," "intends," "is
likely," "plans," "predicts," "projects," variations of such words and similar
expressions are intended to identify such forward-looking statements under the
Private Securities Litigation Reform Act of 1995. The Company cautions that
these statements are not guarantees of future performance and involve certain
risks, uncertainties and assumptions that are difficult to predict with regard
to timing, extent, likelihood and degree of occurrence. Therefore, actual
results and outcomes may materially differ from what may be expressed or
forecasted in such forward-looking statements. Furthermore, the Company
undertakes no obligation to update, amend or clarify forward-looking statements,
whether as a result of new information, future events or otherwise.
Important factors that could cause actual results to differ materially from
the forward-looking statements include, but are not limited to, weather
conditions, changes in production volumes, worldwide demand and commodity prices
for petroleum natural resources, the timing and extent of the Company's success
in discovering, acquiring, developing and producing oil and natural gas
reserves, risks incident to the drilling and operation of oil and natural gas
wells, future production and development costs, foreign currency exchange rates,
the effect of existing and future laws, governmental regulations and the
political and economic climate of the United States and New Zealand, the effect
of hedging activities, and conditions in the capital markets.
- 15 -
The following should be read in conjunction with the Company's Financial
Statements and Notes (including the segment information) at Part I, Item 1.
COMPARISON OF RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2005
- --------------------------------------------------------------------------------
AND 2004
- ---------
The Company recorded net income of $3.0 million for the quarter ended March
31, 2005 compared to $4.6 million for the quarter ended March 31, 2004. The
decrease in net income of $1.6 million is primarily attributable to the net of a
$7.4 million increase in revenues, a $4.5 million increase in costs and
expenses, a $0.5 million decrease in interest expense, a $0.2 million decrease
in interest income and other, and a $4.9 million increase in income tax expense.
- 16 -
Production, gas aggregation and pipeline volumes, revenue and average sales
prices for the quarters ended March 31 and their related variances are as
follows:
THREE MONTHS ENDED
MARCH 31 VARIANCE
--------------------- -----------------
2005 2004 AMOUNT PERCENT
--------- ---------- ------- --------
Natural Gas
Production (Mmcf) 2,620 2,689 (69) (2.6%)
Average sales price received ($/Mcf) 6.48 6.02 0.46 7.6%
--------- ---------- ------- --------
Sales ($ in thousands) 16,972 16,193 779 4.8%
Oil
Production (Mbbl) 28 23 5 21.7%
Average sales price received ($/Bbl) 45.21 31.22 14.00 44.8%
--------- ---------- ------- --------
Sales ($ in thousands) 1,266 718 548 76.3%
Hedging gain (loss) 192 (2,252) 2,444 (108.5%)
Other 75 76 (1) (1.3%)
--------- ---------- ------- --------
Total oil and gas sales ($ in thousands) 18,505 14,735 3,770 25.6%
========= ========== ======= ========
Aggregation Revenue
Volume (Million Mmbtu) 2,214 2,228 (14) (0.6%)
Average sales price received ($/Mmbtu) 6.69 5.35 1.35 25.2%
--------- ---------- ------- --------
Sales ($ in thousands) 14,819 11,909 2,910 24.4%
Pipeline Revenue
Volume (Million Mmbtu) 2,177 1,362 815 59.8%
Average sales price received ($/Mmbtu) 2.33 3.10 (0.77) (24.8%)
--------- ---------- ------- --------
Sales ($ in thousands) 5,067 4,217 850 20.2%
Total aggregation and pipeline sales ($ in thousands) 19,886 16,126 3,760 23.3%
========= ========== ======= ========
Aggregation Gas Cost
Volume (Million Mmbtu) 2,214 2,228 (14) (0.6%)
Average price paid ($/Mmbtu) 6.45 5.02 1.43 28.5%
--------- ---------- ------- --------
Cost ($ in thousands) 14,271 11,179 3,092 27.7%
Pipeline Gas Cost
Volume (Million Mmbtu) 1,049 1,088 (39) (3.6%)
Average price paid ($/Mmbtu) 3.93 3.19 0.74 23.4%
--------- ---------- ------- --------
Cost ($ in thousands) 4,123 3,466 657 19.0%
Total aggregation and pipeline cost ($ in thousands) 18,394 14,645 3,749 25.6%
========= ========== ======= ========
REVENUES. Total revenues increased $7.4 million between the periods. The
--------
increase was due to a $3.8 million increase in oil and gas sales and a $3.8
million increase in gas aggregation and pipeline sales. Well operations and
service revenues remained relatively constant.
- 17 -
Revenues from oil and gas sales increased a net of $3.8 million from $14.7
million for the quarter ended March 31, 2004 to $18.5 million for the quarter
ended March 31, 2005. Natural gas sales increased $0.8 million. The net increase
in natural gas sales is attributable to an increase in gas prices, offset by a
slight decrease in gas production. Oil sales increased by $0.5 million due an
increase in oil prices and production. The price increases correspond with the
rise in the related natural gas and oil indexes. The decrease in natural gas
production is primarily due to wells sold in California. Gas sales were
increased by recognized gains on related hedging transactions and other revenue,
which totaled $0.3 million for the quarter ended March 31, 2005 compared to a
loss of $2.2 million for the quarter ended March 31, 2004.
Revenues from gas aggregation and pipeline sales increased $3.8 million
from $16.1 million during the period ended March 31, 2004 to $19.9 million in
the period ended March 31, 2005. Gas aggregation revenue increased $2.9 million
primarily because of an increase in average sales prices and corresponds to the
rise in related gas indexes for this period compared to the prior period.
Offsetting this increase in sales prices was a slight decrease in gas volumes
due to curtailments and natural production declines. Pipeline revenue, which has
a sales and gathering component, increased $0.9 million primarily because of an
increase in the average sales price related to the non-gathering volumes and an
increase in revenue related to the gathering component for this period compared
to the prior period. The increase in revenues and volumes related to the
gathering component is primarily the result of the acquisition of a 100-mile
long natural gas gathering system located in northeastern West Virginia
finalized during the first quarter of the current fiscal year. The increase in
the average sales price related to the non-gathering volumes corresponds to the
increase in related gas indexes for the period as compared to the prior period.
COSTS AND EXPENSES. The Company's costs and expenses increased $4.5 million
------------------
between the periods primarily as a net result of a $0.3 million increase in
field and lease operating expense, a $3.7 million increase in gas aggregation
and pipeline costs, a $0.2 million increase in taxes other than income, a $0.1
million increase in depreciation, depletion, and amortization cost, a $0.3
million increase in exploration and impairment costs, and a $0.1 million
decrease in gain on sale of property as further described below.
Field and lease operating expense increased $0.3 million from $2.8 million
during the period ended March 31, 2004 to $3.1 million in the period ended March
31, 2005. This increase is primarily the result of additional wells in the Gulf
Coast region and road repair and maintenance in the Appalachian Basin.
Gas aggregation and pipeline costs increased $3.7 million from $14.6
million during the period ended March 31, 2004 to $18.4 million in the period
ended March 31, 2005. Gas aggregation costs increased $3.1 million for the
period. The increase in costs is primarily attributable to the increase in the
average purchase price that corresponds to the rise in the related natural gas
indexes and was partially offset by a slight decrease in volume for this period
compared to the prior period. Pipeline costs, which has a gathering and
transportation component, increased $0.7 million. The increase in costs is
primarily attributable to an increase in the average purchase price, which
corresponds to the rise in the related natural gas indexes and by a slight
increase in gas volumes purchased.
Taxes other than income increased $0.2 million during the period to $1.3
million. This increase is primarily the result of an increase in wellhead oil
and gas sales during the period compared to the prior period. Production taxes
are based on wellhead oil and gas sales, which were higher this period compared
to the prior period.
Exploration and impairment costs increased $0.3 million and is primarily
the result of an increase in cost associated with unsuccessful exploratory wells
during the period compared to the prior period.
- 18 -
Gain on sale of assets decreased $0.1 million primarily due to the
recognition of a $0.2 million gain during the period ended March 31, 2004 for
the sale of Wyoming properties as compared to a $0.1 million gain recorded for
the period ended March 31, 2005 from the sale of land and used vehicles.
INTEREST EXPENSE. Interest expense decreased $0.5 million when comparing
------------------
the periods primarily due to the purchase of a portion of the Company's senior
notes resulting in a decrease in the average interest rate paid on outstanding
debt.
INCOME TAX. Income tax expense increased $4.9 million to an income tax
-----------
expense of $1.0 million as compared to an income tax benefit for the prior
period of $3.9 million. The increase is primarily due to the increase in income
before income taxes of $3.2 million and the decrease in income tax benefit from
the adjustment of the tax contingency balance of $3.6 million for items that are
closed or no longer applicable.
COMPARISON OF RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED MARCH 31, 2005 AND
- --------------------------------------------------------------------------------
2004
- ----
The Company recorded net income of $7.4 million for the nine months ended
March 31, 2005 compared to net income of $4.9 million for the nine months ended
March 31, 2004. The increase in net income of $2.5 million is primarily
attributable to the net of a $14.0 million increase in revenues, $4.9 million
increase in costs and expenses, $1.7 million decrease in interest expense, $2.6
million decrease in interest income and other, and a $5.7 million increase in
income tax expense.
- 19 -
Production, gas aggregation and pipeline volumes, revenue and average sales
prices for the nine months ended March 31 and their related variances are as
follows:
NINE MONTHS ENDED
MARCH 31 VARIANCE
--------------------- -----------------
2005 2004 AMOUNT PERCENT
---------- --------- ------- --------
Natural Gas
Production (Mmcf) 7,600 8,239 (639) (7.8%)
Average sales price received ($/Mcf) 6.62 5.26 1.36 26.0%
---------- --------- ------- --------
Sales ($ in thousands) 50,344 43,332 7,012 16.2%
Oil
Production (Mbbl) 61 86 (25) (29.1%)
Average sales price received ($/Bbl) 43.93 28.71 15.23 53.0%
---------- --------- ------- --------
Sales ($ in thousands) 2,680 2,469 211 8.5%
Hedging (loss) (4,861) (2,807) (2,054) 73.2%
Other 245 261 (16) (6.1%)
---------- --------- ------- --------
Total oil and gas sales ($ in thousands) 48,408 43,255 5,153 11.9%
========== ========= ======= ========
Aggregation Revenue
Volume (Million Mmbtu) 6,035 6,721 (686) (10.2%)
Average sales price received ($/Mmbtu) 6.56 5.16 1.40 27.1%
---------- --------- ------- --------
Sales ($ in thousands) 39,565 34,679 4,886 14.1%
Pipeline Revenue
Volume (Million Mmbtu) 6,320 4,179 2,141 51.2%
Average sales price received ($/Mmbtu) 2.41 2.76 (0.34) (12.4%)
---------- --------- ------- --------
Sales ($ in thousands) 15,261 11,523 3,738 32.4%
Total aggregation and pipeline sales ($ in thousands) 54,826 46,202 8,624 18.7%
========== ========= ======= ========
Aggregation Gas Cost
Volume (Million Mmbtu) 6,035 6,722 (687) (10.2%)
Average price paid ($/Mmbtu) 6.30 4.96 1.33 26.9%
---------- --------- ------- --------
Cost ($ in thousands) 37,993 33,353 4,640 13.9%
Pipeline Gas Cost
Volume (Million Mmbtu) 3,170 3,369 (199) (5.9%)
Average price paid ($/Mmbtu) 3.95 2.76 1.20 43.4%
---------- --------- ------- --------
Cost ($ in thousands) 12,532 9,288 3,244 34.9%
Total aggregation and pipeline cost ($ in thousands) 50,525 42,641 7,884 18.5%
========== ========= ======= ========
REVENUES. Total revenues increased $14.0 million between the periods. The
--------
increase was due to a $5.2 million increase in oil and gas sales, $8.6 million
increase in gas aggregation and pipeline sales and a $0.3 million increase in
other revenues. Well operations and service revenues remained relatively
constant.
- 20 -
Revenues from oil and gas sales increased a net of $5.2 million from $43.3
million for nine months ended March 31, 2004 to $48.4 million for the nine
months ended March 31, 2005. Natural gas sales increased $7.0 million and oil
sales increased $0.2 million. The net increase in natural gas sales is the
result of an increase in average gas prices and was partially offset by a
decline in production. The price increase corresponds with the rise in related
natural gas indexes. The production decline is primarily due to the sale of
several California properties and certain pipeline curtailments in the
Appalachian Basin. Gas sales were reduced by recognized losses on related
hedging transactions, which totaled a loss of $4.8 million for the nine months
ended March 31, 2005 compared to a loss of $2.8 million for the nine months
ended March 31, 2004.
Revenues from gas aggregation and pipeline sales increased $8.6 million
from $46.2 million for the nine months ended March 31, 2004 to $54.8 million for
the nine months ended March 31, 2005. Gas aggregation revenue increased $4.9
million because of an increase in average sales prices, offset by a decrease in
gas volumes due to curtailments and natural production declines. The increase in
average sales price corresponds to the rise in related natural gas price indexes
for this period compared to the prior period. Pipeline revenue, which has a
sales and gathering component, increased $3.7 million from $11.5 million to
$15.2 million primarily because of an increase in the average sales price
related to the non-gathering volumes and an increase in revenue related to the
gathering component for this period compared to the prior period. The increase
in revenues and volumes related to the gathering component primarily is the
result of the acquisition of a 100-mile long natural gas gathering system
located in northeastern West Virginia finalized during the first quarter of the
current fiscal year. The increase in the average sales price related to
non-gathering volumes corresponds to the increase in related natural gas indexes
for the period as compared to the prior period.
Other revenues increased $0.3 million between periods. This increase is
primarily the result of the Company receiving a partnership distribution from a
limited partnership in which the Company owns an interest.
COSTS AND EXPENSES. The Company's costs and expenses increased $4.9 million
------------------
between the periods primarily as a net result of a $0.2 million increase in
field and lease operating expenses, a $7.9 million increase in gas aggregation
and pipeline costs, $0.2 million decrease in general and administrative costs,
$0.6 million increase in taxes other than income, a $0.9 million decrease in
depreciation, depletion, and amortization cost, a $0.1 million increase in
exploration and impairment costs, and a $2.7 million increase in gain on sale of
assets.
Gas aggregation and pipeline costs increased $7.9 million. Gas aggregation
costs increased $4.6 million and is primarily the result of an increase in the
average price of gas that corresponds to the rise in the related natural gas
indexes, offset by a decline in gas volumes for this period compared to the
prior period. Pipeline costs increased $3.2 million and is primarily the result
of an increase in the average purchase price that corresponds to the rise in the
related natural gas indexes, with no significant changes in volumes.
Taxes other than income increased $0.6 million primarily due to an increase
in wellhead sales in the period compared to the prior period. Production taxes
are based on wellhead oil and gas sales, which where higher during the period
compared to the prior period.
Depletion and depreciation of oil and gas properties decreased $0.9 million
due primarily to a decrease in production.
Gain on sale of assets increased $2.7 million primarily due to the
recognition of an $1.8 million gain in the current period, related to the
reversal of a reserve established at June 30, 2004, against items
- 21 -
for which the Company was required to indemnify the buyer of the Company's
membership interest in Breitburn Energy Company, LLC ("BEC") for a period of 180
days after closing of the agreement. The Company also realized a gain on the
sale of undeveloped acreage and certain field equipment in the Appalachian Basin
during the current period.
INTEREST EXPENSE. Interest expense decreased $1.7 million when comparing
-----------------
the periods primarily due to the purchase of a portion of the Company's senior
notes resulting in a decrease in the average interest rate paid on outstanding
debt.
INTEREST INCOME AND OTHER. Other income decreased $2.6 million when
----------------------------
comparing the periods and is primarily attributable to a decrease in recognized
gains on the purchase of senior bonds, recording a settlement of a contingent
liability and additional profit sharing costs recorded in the current period.
INCOME TAX. Income tax expense increased $5.7 million to an income tax
-----------
expense of $2.0 million as compared to an income tax benefit for the prior
period of $3.7 million. The increase is primarily due to the increase in income
before income taxes of $8.3 million and the decrease in income tax benefit from
the adjustment of the tax contingency balance of $2.4 million for items that are
closed or no longer applicable.
LIQUIDITY AND CAPITAL RESOURCES
- ----------------------------------
The Company's financial condition and liquidity have improved since June
30, 2004. Stockholders' equity has increased from $42.4 million at June 30,
2004 to $46.6 million at March 31, 2005. The Company's cash decreased from $5.8
million at June 30, 2004 to $3.7 million at March 31, 2005. The decrease in
cash during the nine months of approximately $2.1 million resulted from various
operating, investing and financing activities of the Company. The activities
were primarily comprised of: the borrowing of $50 million under the Company's
$50 million term loan of the Amended and Restated Credit Agreement (the
"Restated Credit Agreement"); the reduction of $3.4 million under the Company's
$50 million revolving credit facility of the Restated Credit Agreement; payments
of $34 million for the purchase of a portion of the Company's outstanding Notes;
the issuance of notes of $0.3 million; the investment of approximately $25.8
million; proceeds from the sale of assets of approximately $4.0 million;
payments of approximately $1.7 million for the acquisition of treasury stock and
dividends; and approximately $9.2 million of cash provided by operations during
the quarter.
As previously reported, on July 10, 2002, the Company entered into a $50
million revolving Credit Agreement with Foothill Capital Corporation, now Wells
Fargo Foothill, Inc. ("Foothill"). The Company and Foothill have entered into a
Restated Credit Agreement dated June 10, 2004. The Restated Credit Agreement
provides for the $50 million revolving credit facility to be extended and for
the Company to be provided with additional credit in the form of a single
advance term loan in the amount of $50 million. The term loan contains
requirements for principal payments of $1 million each at July 10, 2005, 2006
and 2007, with the remaining balance due on July 10, 2008. Depending on the
Company's level of borrowing under the Restated Credit Agreement, the applicable
interest rates for base rate loans are based on Wells Fargo's prime rate plus
0.25% to 0.75%. The Company has the ability under the Restated Credit Agreement
to designate certain loans as LIBOR Rate Loans at interest rates based upon the
rate at which dollar deposits are offered to major banks in the London interbank
market plus 2.25% to 2.75%. The Restated Credit Agreement expires on July 10,
2008.
- 22 -
The obligations under the Restated Credit Agreement are secured by certain
of the existing proved producing oil and gas assets of the Company. The Restated
Credit Agreement, among other things, restricts the ability of the Company and
its subsidiaries to incur new debt, grant additional security interests in its
collateral, engage in certain merger or reorganization activities, or dispose of
certain assets.
The Company has an unsecured revolving line of credit totaling $3.0 million
with a financial institution with an interest rate of prime plus 0.25%. Based
upon the original terms of the agreement, the line was to reduce by $1.0 million
in November 2004 and was to expire on June 30, 2005. The unsecured revolving
line of credit was renegotiated during the quarter ended March 31, 2005 to
extend the terms of the agreement. Under the new agreement the Company has an
unsecured line of credit totaling $3.0 million, which reduces by $1.0 million in
June 2005 and expires on April 1, 2007.
At March 31, 2005, the Company's principal source of liquidity consisted of
$3.7 million of cash, $1.8 million available under an unsecured credit facility
currently in place, plus amounts available under the revolving loan of the
Restated Credit Agreement. At March 31, 2005, $1.0 million was outstanding and
$0.2 million was committed through letters of credit under the credit facility,
$32.8 million was outstanding on the revolving loan and $50 million was
outstanding on the term loan under the Restated Credit Agreement.
As of May 10, 2005, there is $50 million in outstanding borrowings under
the term loan and $26.6 million in outstanding borrowings under the revolving
loan. Additional borrowings must comply with the terms of the Indenture and the
Restated Credit Agreement.
As previously reported, the Company had been in litigation with certain
Holders (the "Noteholders") of its Notes. The dispute involved the calculation
of "Net Proceeds" of an "Asset Sale" as defined in the Indenture. A settlement
agreement dated February 24, 2004, was negotiated with the Noteholders to
resolve the dispute. In settlement of the dispute the Company agreed to
repurchase $38 million in Notes. The repurchase was effected by the Company
making Asset Sale Offers (as defined in the Indenture) totaling $38 million.
The Company made an initial Asset Sale Offer of $4 million, which was completed
on March 25, 2004. The Company consummated another Asset Sale Offer of $34
million which was completed on July 29, 2004. The United States District
Court for the Southern District of West Virginia has entered a Dismissal Order
dismissing the litigation with prejudice. Upon the Company meeting all of the
terms and conditions of the Settlement Agreement it funded the $50 million term
loan under the Restated Credit Agreement.
- 23 -
Management utilizes earnings before interest, taxes, depreciation,
depletion, amortization and exploration and impairment cost ("EBITDAX") to
evaluate the operation of each business segment. Reconciliation of the non-GAAP
financial measure is as follows (in thousands):
Twelve Months Ended
June 30, June 30, June 30,
2004 2003 2002
---------- ---------- ----------
Net income (loss) $ 4,295 $ 9,844 $ (26,180)
Add:
Interest expense 15,069 16,383 19,671
Depletion and depreciation of oil and gas properties 13,300 12,140 12,362
Depreciation of pipelines, other property and equipment 4,190 4,294 2,933
Exploration and impairment 10,796 11,729 27,694
Income tax expense (4,722) 6,073 (16,822)
Less:
Change in accounting principle, net of tax - (73) -
Gain on redemption of senior bonds 513 23,672 -
---------- ---------- ----------
EBITDAX $ 42,415 $ 36,864 $ 19,658
========== ========== ==========
The Company's net cash requirements will fluctuate based on timing and the
extent of the interplay of capital expenditures, cash generated by operations,
cash generated by the sale of assets and interest expense. Management
anticipates that EBITDAX from oil and gas operations for fiscal year 2005 will
approximate $48 million. The Company's ability to achieve EBITDAX of $48 million
from oil and gas operations for fiscal year 2005 is highly dependant on product
price and continued drilling success. There can be no assurance given that the
Company will be able to achieve these goals. Management believes that cash
generated from oil and gas operations, together with the liquidity provided by
existing cash balances and permitted borrowings, will be sufficient to satisfy
commitments for capital expenditures of $40.7 million, debt service obligations,
working capital needs and other cash requirements for the current fiscal year.
In order to reduce future cash interest payments, as well as future amounts
due at maturity or upon redemption, the Company may, from time to time, purchase
its outstanding Notes in open market purchases and/or privately negotiated
transactions. The Company will evaluate any such transactions in light of then
existing market conditions, taking into account its liquidity, uses of capital
and prospects for future access to capital. The amounts involved in any such
transaction, individually or in the aggregate, may be material.
The Company believes that its existing capital resources and its expected
fiscal year 2005 results of operations and cash flows from operating activities
will be sufficient for the Company to remain in compliance with the requirements
of its Notes and the Restated Credit Agreement. However, since future results
of operations, cash flow from operating activities, debt service capability,
levels and availability of capital resources and continuing liquidity are
dependent on future weather patterns, oil and gas commodity prices and
production volume levels, future exploration and development drilling success
and
- 24 -
successful acquisition transactions, no assurance can be given that the Company
will remain in compliance with the requirements of its Notes and the Restated
Credit Agreement.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- -------------------------------------------------------------------
COMMODITY RISK
- ---------------
The Company's operations consist primarily of exploring for, producing,
aggregating and selling natural gas and oil. Contracts to deliver gas at
pre-established prices mitigate the risk to the Company of falling prices but at
the same time limit the Company's ability to benefit from the effects of rising
prices. The Company occasionally uses derivative instruments to hedge commodity
price risk. The Company hedges a portion of its projected natural gas
production through a variety of financial and physical arrangements intended to
support natural gas prices at targeted levels and to manage its exposure to
price fluctuations. The Company may use futures contracts, swaps, options and
fixed price physical contracts to hedge commodity prices. Realized gains and
losses from the Company's price risk management activities are recognized in oil
and gas sales when the associated production occurs. Unrecognized gains and
losses are included as a component of other comprehensive income.
Ineffectiveness is recorded in current earnings. The Company does not hold or
issue derivative instruments for trading purposes. The Company currently has
elected to enter into derivative hedge transactions on its estimated production
covering approximately 65% to 75% for the fiscal year ending June 30, 2005, 75%
to 90% for the fiscal year ending June 30, 2006, 35% to 40% for the fiscal year
ending June 30, 2007 and 10% to 20% for the fiscal year ending June 30, 2008.
As of March 31, 2005, the Company's open gas derivative instruments are as
follows:
- 25 -
Total Average
Market Volumes Contract / Strike Unrealized
Time period Index (MMBtu) Price Losses
- -----------------------------------------------------------------------------------------
Derivatives
Natural Gas Swaps
April 2005 - June 2005 NYMEX 810,000 $ 4.11 $ 2,783,027
April 2005 - June 2005 NYMEX 600,000 7.25 193,446
June 2005 - June 2005 NYMEX 300,000 7.55 61,114
July 2005 - December 2005 NYMEX 1,324,800 7.55 652,595
July 2005 - March 2006 NYMEX 900,000 6.25 1,742,124
January 2006 - December 2006 NYMEX 2,620,000 7.16 1,263,897
January 2007 - December 2007 NYMEX 2,628,000 6.60 1,123,221
----------- -----------
9,182,800 $ 7,819,424
=========== ===========
Floors
April 2005 - June 2005 NYMEX 1,200,000 $ 6.00 $ 382,176
July 2005 - March 2006 NYMEX 2,160,000 6.00 962,313
----------- -----------
3,360,000 $ 1,344,489
=========== ===========
Collars
July 2005 - March 2006 NYMEX 3,420,000 $ 5.50 - 8.70 $ 2,045,297
January 2006 - December 2006 NYMEX 1,825,000 5.75 - 9.92 256,298
January 2007 - December 2007 NYMEX 1,825,000 5.75 - 8.65 321,528
----------- -----------
7,070,000 $ 2,623,123
=========== ===========
Total Hedged Production 19,612,800 $11,787,036
=========== ===========
Notwithstanding the above, the Company's future cash flows from gas and oil
production are exposed to significant volatility as commodity prices change.
Assuming total oil and gas production, pricing, and the percentage of gas
production hedged under physical delivery contracts and derivative instruments
remain at March 2005 levels, a 10% change in the average unhedged prices
realized would change the Company's gas and oil revenues by approximately $0.1
million on a quarterly basis.
INTEREST RATE RISK
- --------------------
Interest rate risk is attributable to the Company's debt. The Company
utilizes United States dollar denominated borrowings to fund working capital and
investment needs. There is inherent rollover risk for borrowings as they mature
and are renewed at current market rates. The extent of this risk is not
predictable because of the variability of future interest rates and the
Company's future financing needs. In August 2004, the Company entered into four
interest rate cap agreements with Foothill, in an effort to reduce the potential
impact of increases in interest rates on floating-rate long-term debt. The
agreements range from two to three years covering $40,000,000 in long-term debt
and cap the one month London Interbank Offered Rate ("LIBOR") at 3.5%. Assuming
the variable interest debt remained at the March
- 26 -
31, 2005 level, a 10% change in rates would have a $0.3 million impact on
interest expense on an annual basis.
FOREIGN CURRENCY EXCHANGE RISK
- ---------------------------------
Some of the Company's transactions are denominated in New Zealand dollars.
For foreign operations with the local currency as the functional currency,
assets and liabilities are translated at the period end exchange rates, and
statements of income are translated at the average exchange rates during the
period. Gains and losses resulting from foreign currency translation are
included as a component of other comprehensive income.
ITEM 4. CONTROLS AND PROCEDURES
- --------------------------------
Under the supervision and with the participation of our management,
including our principal executive officer and principal financial officer, the
Company has evaluated the effectiveness of the design and operation of our
disclosure controls and procedures as of the end of the period covered by this
quarterly report and, based on their evaluation, our principal executive officer
and principal financial officer have concluded that these controls and
procedures are effective. There were no significant changes in our internal
controls or in other factors that could significantly affect these controls
subsequent to the date of their evaluation. Disclosure controls and procedures
are our controls and other procedures that are designed to ensure that
information required to be disclosed by us in the reports that we file or submit
under the Securities Exchange Act of 1934, as amended, is recorded, processed,
summarized and reported, within the time periods specified in the Securities and
Exchange Commission's rules and forms. Disclosure controls and procedures
include, without limitation, controls and procedures designed to ensure that
information required to be disclosed by us in the reports that we file under the
Securities Exchange Act is accumulated and communicated to our management,
including our principal executive officer and principal financial officer, as
appropriate to allow timely decisions regarding required disclosure.
- 27 -
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Company is involved in legal actions and claims arising in the ordinary
course of business. While the outcome of these lawsuits against the Company
cannot be predicted with certainty, management does not expect these matters to
have a material adverse effect on the Company's operations or financial
position.
ITEM 2. CHANGES IN SECURITIES
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
ITEM 5. OTHER INFORMATION
On April 4, 2005 the Company filed registration statement with the
Securities and Exchange Commission ("SEC") relating to an initial public
offering of Trust units proposed to be issued by a new royalty trust which will
be known as the Appalachian Gas Royalty Trust ("Trust"). The Trust units of the
Trust will be listed on the New York Stock Exchange under the symbol "ANG". The
royalty interest created by the Company will entitle the Trust to receive 90% of
the net proceeds from the sale of future production of natural gas attributable
to the Company's interest in 312 existing producing wells and 50% of the net
proceeds from the sale of future production of natural gas attributable to the
Company's interest in 180 additional wells that the Company is obligated to
drill by March 31, 2009. The term of the Trust will extend for a period of 20
years commencing as of January 1, 2005. Upon termination of the Trust, the
royalty interest held by the Trust will revert to the Company.
The Company will receive the net proceeds from the sale of the Trust units,
currently estimated to be approximately $142 million (after deduction of
underwriting commissions and expenses of the offering), in exchange for the
contributions of the royalty interest to the Trust. The completion of the
offering is subject to a number of conditions, including clearance of the
registration statement by the SEC, and will depend upon market conditions at the
time of the offering of the units as well as sufficient investor demand for the
Trust units. As a result, there can be no assurance that this transaction will
be completed or, if completed, that the Company will realize the full amount of
the net proceeds currently estimated.
A registration statement relating to the Trust units has been filed with
the SEC but has not yet become effective. The Trust units may not be sold nor
may offers to buy be accepted prior to the time the registration statement
become effective. This Report on Form 10-Q shall not constitute an offer to
sell the Trust units or the solicitation of an offer to buy the Trust units nor
shall there be any sale of the Trust units in any state in which such offer,
solicitation or sale would be unlawful prior to registration or qualification of
the Trust units under the securities laws of any such state.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits:
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
b) Reports on Form 8-K:
None
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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 under
signed thereunto, duly authorized, in the City of Denver, State of Colorado, on
the 11th day of May 2005.
ENERGY CORPORATION OF AMERICA
By: /s/John Mork
----------------------------------
John Mork
Chief Executive Officer and Director
By: /s/Michael S. Fletcher
----------------------------------
Michael S. Fletcher
Chief Financial Officer
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