<PAGE>
========================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
--------------
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1999
Commission file number 001-14256
--------------
BELCO OIL & GAS CORP.
(Exact name of registrant as specified in its charter)
Nevada
(State or other jurisdiction
of incorporation or organization)
767 Fifth Avenue, 46th Floor 10153
New York, New York
(Address of principal executive offices)
13-3869719
(I.R.S. employer identification no.)
10153
(Zip code)
(212) 644-2200
(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 _
As of September 30, 1999, there were 31,673,000 shares of the Registrant's
Common Stock, par value $.01 per share, outstanding.
<PAGE>
FINANCIAL STATEMENTS
BELCO OIL & GAS CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share data)
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
(Unaudited)
------------- ------------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents. . . . . . . . . . $ 4,971 $ 2,435
Accounts receivable, oil and gas . . . . . . 22,027 28,464
Assets from commodity price risk management
activities . . . . . . . . . . . . . . . . . 4,216 18,643
Other current assets . . . . . . . . . . . . 7,605 1,005
---------- ---------
Total current assets . . . . . . . . . . . . 38,819 50,547
PROPERTY AND EQUIPMENT:
Oil and gas properties at cost based on
full cost accounting--
Proved oil and gas properties. . . . . . . . 975,152 931,218
Unproved oil and gas properties. . . . . . . 81,606 74,935
Less--Accumulated depreciation, depletion
and amortization. . . . . . . . . . . . . . (605,813) (566,613)
Net oil and gas properties . . . . . . . . . 450,945 439,540
Building and other equipment . . . . . . . . 8,941 8,633
Less--Accumulated depreciation. . . . . . . (2,344) (1,281)
Net building and other equipment . . . . . . 6,597 7,352
OTHER ASSETS . . . . . . . . . . . . . . . . 5,580 8,097
-------- --------
Total assets . . . . . . . . . . . . . . . . $501,941 $505,536
======== ========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable . . . . . . . . . . . . . . $ 14,662 $ 18,372
Liabilities from commodity price risk
management activities . . . . . . . . . . . 25,288 5,393
Accrued interest . . . . . . . . . . . . . . 6,675 6,897
Other accrued liabilities. . . . . . . . . . 6,268 5,064
-------- --------
Total current liabilities. . . . . . . . . . 52,893 35,726
======== ========
LONG-TERM DEBT . . . . . . . . . . . . . . . 302,013 294,990
DEFERRED INCOME TAXES. . . . . . . . . . . . 21,296 31,833
LIABILITIES FROM COMMODITY PRICE RISK
MANAGEMENT ACTIVITIES . . . . . . . . . . . 13,410 4,696
STOCKHOLDERS' EQUITY:
6-1/2% Convertible Preferred stock, $.01
par value; 10,000,000 shares authorized;
4,239,100 and 4,312,000 issued and
outstanding at September 30, 1999 and
December 31, 1998, respectively . . . . 42 43
Common stock ($.01 par value, 120,000,000
shares authorized; 31,673,000 and
31,609,900 shares issued and outstand-
ing at September 30, 1999 and December
31, 1998, respectively) . . . . . . . . 317 316
Additional paid-in capital . . . . . . . . . 300,457 301,416
Retained earnings (deficit). . . . . . . . . (186,138) (161,627)
Unearned compensation. . . . . . . . . . . . (1,574) (1,082)
Notes receivable for equity interest . . . . (775) (775)
------- -------
Total stockholders' equity . . . . . . . . . 112,329 138,291
------- -------
Total liabilities and stockholders' equity . $501,941 $505,536
======== ========
</TABLE>
<PAGE>
BELCO OIL & GAS CORP.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
1999 1998 1999 1998
---- ---- ---- ----
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas sales. . . . . . . . . $ 39,520 $ 29,179 $ 96,340 $ 97,438
Commodity price risk management
activities
- - cash settlements (a) . . . . . . (2,339) 3,261 7,754 4,004
- - non-cash mark-to-market. . . . . (22,210) 2,038 (45,225) 3,465
Interest and other. . . . . . . 275 212 675 637
------ ------ ------ -------
Total revenues . . . . . . . . . . 15,246 34,690 59,544 105,544
------ ------ ------ -------
COSTS AND EXPENSES:
Oil and gas operating expenses . . 9,567 9,238 29,148 28,433
Depreciation, depletion and amor-
tization. . . . . . . . . . . . . 13,247 13,666 40,259 42,461
General and administrative . . . . 1,178 1,222 3,651 3,620
Interest expenses. . . . . . . . . 5,838 5,057 16,188 14,734
Impairment of oil and gas proper-
ties . . . . . . . . . . . . . . -- -- -- 154,000
Impairment of equity securities. . -- 240 -- 14,340
----- ----- ------ -------
Total costs and expenses . . . . . 29,830 29,423 89,246 257,588
------ ------ ------ -------
INCOME (LOSS) BEFORE INCOME TAXES. (14,584) 5,267 (29,702) (152,044)
INCOME TAX PROVISIONS (BENEFIT). . (5,104) 1,828 (10,396) (52,244)
------- ----- -------- --------
NET INCOME (LOSS). . . . . . . . . (9,480) 3,439 (19,306) (99,800)
PREFERRED STOCK DIVIDENDS. . . . . (1,727) (1,775) (5,205) (3,630)
------- ------- ------- -------
EARNINGS (LOSS) ON COMMON STOCK. . $(11,207) $ 1,664 $(24,511)$(103,430)
========= ======= ========= =========
EARNINGS (LOSS) PER SHARE OF
COMMON STOCK, BASIC AND FULLY
DILUTED . . . . . . . . . . . . . $(0.35) $0.05 $ (0.78) $(3.27)
======= ===== ======== =======
AVERAGE NUMBER OF COMMON SHARES
USED IN COMPUTATION, BASIC AND
FULLY DILUTED . . . . . . . . . . 31,600 31,613 31,600 31,602
====== ====== ====== ======
</TABLE>
- -----------------------------
(a) Includes cash premiums received.
<PAGE>
BELCO OIL & GAS CORP.
CONDENSED CONSOLIDATED CHANGES IN STOCKHOLDERS' EQUITY
(in thousands)
(Unaudited)
<TABLE>
<CAPTION>
Preferred Stock Common Stock Notes
Outstanding Outstanding Additional Unearned Retained Receivable Compre-
---------------- ---------------- Paid-In Compensa- Earnings for Equity hensive
Shares Amount Shares Amount Capital tion (Deficit) Interest Total Income
------ ------ ------ ------ ---------- --------- --------- ---------- ----- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE,
December 31,
1998 4,312 $ 43 31,609 $ 316 $301,416 $(1,082) $(161,627) $ (775) $138,291 $ --
----- ------ ------ ----- -------- -------- ---------- -------- -------- -------
Repurchase
Preferred
Stock (73) (1) -- -- (1,089) -- -- -- (1,090) --
Repurchase
Common Stock -- -- (96) (1) (648) -- -- -- (649) --
Restricted
stock
issued/
earned -- -- 160 2 778 (492) -- -- 288 --
Net Loss -- -- -- -- -- -- (19,306) -- (19,306) (19,306)
Preferred
dividend
paid -- -- -- -- -- -- (5,205) -- (5,205) --
----- ----- ----- ----- ------ ------ --------- ----- ------- ------
BALANCE,
September
30, 1999 4,239 $ 42 31,673 $ 317 $300,457 $(1,574) $(186,138) $ (775) $112,329 --
----- ----- ------ ----- -------- -------- ---------- -------- -------- ------
Comprehen-
sive Income $(19,306)
</TABLE>
<PAGE>
BELCO OIL & GAS CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
-----------------
1999 1998
---- ----
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss . . . . . . . . . . . . . . . . . . . . . . $(19,306) $(99,800)
Adjustments to reconcile net income (loss) to net
operating cash inflows
Depreciation, depletion and amortization. . . . . 40,259 42,461
Impairment of oil and gas properties. . . . . . . -- 154,000
Deferred tax benefit. . . . . . . . . . . . . . . (10,396) (52,244)
Impairment of marketable equity securities. . . . -- 14,340
Commodity price risk management activities. . . . 10,904 (5,445)
Other . . . . . . . . . . . . . . . . . . . . . . 150 704
Changes in operating assets and liabilities --
Accounts receivable, oil and gas. . . . . . . . . 6,300 16,703
Assets from commodity price risk management
activities. . . . . . . . . . . . . . . . . . . 14,427 --
Other current assets. . . . . . . . . . . . . . . (5,242) (195)
Accounts payable and accrued liabilities. . . . . (2,727) (3,719)
Liabilities from commodity price risk management
activities. . . . . . . . . . . . . . . . . . . 19,895 (479)
-------- --------
Net operating cash inflows. . . . . . . . . . . 54,264 66,326
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures. . . . . (34,688) (58,752)
Purchases of oil and gas properties . . . . . . . (17,141) (39,756)
Proceeds from sale of oil and gas properties. . . 2 3,872
Changes in accounts payable and accrued liabil-
ities for oil and gas expenditures. . . . . . . -- (14,495)
Change in advances to oil and gas operators . . . -- (4)
Equity investment in Big Bear Exploration Ltd.. . -- (10,268)
Proceeds from sale of marketable equity secur-
ities . . . . . . . . . . . . . . . . . . . . . -- 18,395
Purchase of marketable equity securities. . . . . -- (1,851)
Other property additions. . . . . . . . . . . . . (308) --
Changes in other assets . . . . . . . . . . . . . (149) (562)
------- --------
Net investing cash outflows. . . . . . . . . . (52,284) (103,421)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from preferred stock offering, net . . . -- 105,495
Repurchases of common stock . . . . . . . . . . . (649) --
Repurchases of preferred stock. . . . . . . . . . (1,090) --
Long-term borrowings. . . . . . . . . . . . . . . 25,500 --
Long-term debt repayments . . . . . . . . . . . . (18,000) (61,550)
Preferred dividends paid. . . . . . . . . . . . . (5,205) (3,630)
------- --------
Net financing cash inflows. . . . . . . . . . . 556 40,315
------- --------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS . . 2,536 3,220
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD . . 2,435 12,260
------ --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . $ 4,971 $15,480
======== ========
</TABLE>
<PAGE>
BELCO OIL & GAS CORP.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Accounting Policies
The financial statements included herein have been prepared by Belco Oil & Gas
Corp., (the "Company") without audit, pursuant to the rules and regulations of
the Securities and Exchange Commission and reflect all adjustments which are, in
the opinion of management, necessary to present a fair statement of the results
for the interim periods, on a basis consistent with the annual audited financial
statements. All such adjustments are of a normal recurring nature. The results
of operations for the interim period are not necessarily indicative of the
results to be expected for an entire year. Certain information, accounting
policies, and footnote disclosures normally included in financial statements
prepared in accordance with generally accepted accounting principles have been
omitted pursuant to such rules and regulations, although the Company believes
that the disclosures are adequate to make the information presented not
misleading. These financial statements should be read in conjunction with the
Company's Form 10-K for the calendar year 1998 which includes financial
statements and notes thereto.
Note 2 - Commodity Price Risk Management Activities
The Company periodically enters into commodity price risk management
transactions such as swaps and options in order to manage its exposure to oil
and gas price volatility. Gains and losses related to qualifying hedges of the
Company's oil and gas production are deferred and recognized as revenues as the
associated production occurs. Reference is made to the December 31, 1998
financial statements of Belco Oil & Gas Corp., included in the Form 10-K for the
calendar year 1998, for a more thorough discussion of the Company's commodity
price risk management activities.
The Company uses the mark-to-market method of accounting for instruments that do
not qualify for hedge accounting. Under mark-to-market accounting, those
contracts which do not qualify for hedge accounting are reflected at market
value at the end of the period with resulting unrealized gains and losses
recorded as assets and liabilities in the consolidated balance sheet. Under such
method, changes in the market value of outstanding financial instruments are
recognized as unrealized gain or loss in the period of change.
For the nine months ended September 30, 1999, the Company had net commodity
price risk management losses of $37.5 million consisting of $7.8 million in cash
settlements and $45.2 million in mark-to-market net losses. This compares to a
$7.5 million net gain consisting of $4.0 million in cash settlements and $3.5
million in mark-to-market net gains, reported in the first nine months of 1998
related to its price risk management activities.
Note 3 - Impairment of Oil and Gas Properties
The capitalization costs of proved oil and gas properties are subject to a
"ceiling test", which limits such costs to the estimated present value net of
related tax effects, discounted at a 10 percent interest rate, of future net
cash flows from proved reserves, based on current economic and operating
conditions (PV10). If capitalized costs exceed this limit, the excess is charged
to depreciation, depletion and amortization. Application of these rules during
periods of relatively low oil and gas prices, even if of short-term duration,
may result in write-downs.
<PAGE>
Note 4 - Capital Stock
Net Income (Loss) Per Common Share
A reconciliation of the components of basic and diluted net income (loss) per
common share for the three and nine months ended September 30, 1999 and 1998 is
presented in the table below (in thousands, except per share amounts):
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
1999 1998 1999 1998
---- ---- ---- ----
<S> <C> <C> <C> <C>
Basic net income (loss) per share:
Net loss ($9,480) $3,439 ($19,306) ($99,800)
Less: Preferred Stock dividends (1,727) (1,775) (5,205) (3,630)
-------- ------- ------- --------
Loss attributable to common
shareholders ($11,207) $1,664 ($24,511) ($103,430)
======== ====== ======= ========
Weighted average shares of
common stock outstanding (1) 31,600 31,613 31,600 31,602
======= ====== ====== =======
Basic net income (loss) per
share ($0.35) $0.05 ($0.78) ($3.27)
======= ====== ======= =======
Diluted net income (loss) per share:
Weighted average shares of common
stock outstanding (1) 31,600 31,613 31,600 31,602
Effect of dilutive securities:
Restricted stock (2) -- -- -- --
Preferred stock, warrants and
stock options (2) -- -- -- --
------- ------ ------ ------
Weighted Average shares of common
stock outstanding including
dilutive securities 31,600 31,613 31,600 31,602
======= ====== ====== =======
Diluted net loss per share ($0.35) $0.05 ($0.78) ($3.27)
======= ====== ======= =======
</TABLE>
- -------------
(1) Includes shares issued and outstanding minus non-vested restricted stock.
(2) Amounts are not included in the computation of diluted net loss per share
because to do so would have been antidilutive.
<PAGE>
Note 5 - Comprehensive Income
Comprehensive income includes net income and reserve for unrealized losses on
marketable equity securities held.
The components of comprehensive income for the nine months ended September 30,
1999 and 1998 are as follows (in thousands):
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
------------------
1999 1998
---- ----
<S> <C> <C>
Net income (loss) ($19,306) ($99,800)
Less: Reclassification adjustment for
losses included in net income -- 2,000
--------- ---------
Total Comprehensive Income (Loss) ($19,306) ($97,800)
========= =========
</TABLE>
There were no comprehensive income items for the three months ended September
30, 1999 and 1998.
<PAGE>
PART I - FINANCIAL INFORMATION
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW
Belco Oil & Gas Corp. and its subsidiaries (the "Company") is an independent
energy company engaged in the exploration for and the acquisition, exploitation,
development and production of natural gas and oil in the United States primarily
in the Rocky Mountains, the Permian Basin, the Mid-Continent region and the
Austin Chalk Trend. Since its inception in April 1992, the Company has grown its
reserve base largely through a balanced program of exploration and development
drilling and through acquisitions. The Company concentrates its activities
primarily in four core areas in which it has accumulated detailed geologic
knowledge and has developed significant management and technical expertise.
Additionally, the Company structures its participation in natural gas and oil
exploration and development activities to minimize initial costs and risks,
while permitting substantial follow-on investment.
The Company's operations are currently focused in the Rocky Mountains, primarily
in the Green River (which includes the Moxa Arch Trend), Wind River and Big Horn
Basins of Wyoming, the Permian Basin in west Texas, the Mid-Continent region in
Oklahoma and north Texas, and the Austin Chalk Trend, primarily in Texas. These
areas accounted for approximately 99% of the Company's proved reserves at
December 31, 1998. Based on 1998 production, the Company's reserve life index is
9.7 years.
The Company's revenue, profitability and future rate of growth are substantially
dependent upon prevailing prices for natural gas, oil and condensate. These
prices are dependent upon numerous factors beyond the Company's control, such as
economic, political and regulatory developments and competition from other
sources of energy. Energy markets have historically been very volatile, and
there can be no assurance that oil and natural gas prices will not be subject to
wide fluctuations in the future. A substantial or extended decline in oil and
natural gas prices could have a material adverse effect on the Company's
financial position, results of operations and access to capital, as well as the
quantities of natural gas and oil reserves that the Company may economically
produce. Natural gas produced is sold under contracts that primarily reflect
spot market conditions for their particular area. The Company markets its oil
with other working interest owners on spot price contracts and typically
receives a small premium to the price posted for such oil. Currently,
approximately 65% of the Company's production volumes relate to the sale of
natural gas (based on six Mcf of gas being considered equivalent to one barrel
of oil).
The Company utilizes commodity swaps and options and other commodity price risk
management transactions related to a portion of its oil and natural gas
production to achieve a more predictable cash flow, and to reduce its exposure
to price fluctuations. The Company accounts for these transactions as hedging
activities or uses mark-to-market accounting for those contracts that do not
qualify for hedge accounting. As of September 30, 1999, the Company has various
natural gas and oil price risk management contracts in place with respect to
substantial portions of its estimated remaining production for calendar year
1999 and with respect to lesser portions of its estimated production for 2000
and 2001. The Company expects from time to time to either add or reduce the
amount of price risk management contracts that it has in place in keeping with
its price risk management strategy.
<PAGE>
The following table sets forth certain operations data of the Company for the
periods presented:
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
----------------- -----------------
Variances Variances
-------------------- ----------------------
1999 1998 AMOUNT % 1999 1998 AMOUNT %
---- ---- ------ ----- ---- ---- ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Oil and Gas Sales
(Unhedged) (in thousands) $39,520 $29,179 $10,341 35% $96,340 $97,438 $1,098 (1%)
Commodity Price Risk
Management (in thousands)
- cash ($2,339) $3,261 ($5,600) -- $7,754 $ 4,004 $3,750 94%
- non-cash ($22,210) $2,038 ($24,248) -- ($45,225) $3,465 ($48,690) --
Weighted Average
Sales Prices (Unhedged):
Oil (per Bbl) $20.16 $12.87 $7.29 57% $15.75 $13.69 $2.06 15%
Gas (per Mcf) $2.34 $1.74 $0.60 34% $ 1.90 $1.91 ($0.01) --
Net Production Data:
Oil (Mbbl) 829 1,058 (229) (22%) 2,596 3,238 (642) (20%)
Gas (MMcf) 9,745 8,920 825 9% 29,153 27,838 1,315 5%
Gas equivalent(MMcfe) 14,719 15,270 (551) (4%) 44,732 47,266 (2,534) (5%)
Data per Mcfe:
Oil and gas sales revenues
(Unhedged) $2.68 $1.91 $0.77 40% $2.15 $2.06 $0.09 4%
Commodity Price Risk
Management Activities-
cash only (0.16) 0.21 (0.37) -- 0.17 0.08 0.09 113%
Oil and gas operating
expenses (0.65) (0.61) (0.04) (7%) (0.65) (0.60) (0.05) (8%)
General and administrative (0.08) (0.08) -- -- (0.08) (0.08) -- --
Depreciation, depletion
and amortization (0.90) (0.90) -- -- (0.90) (0.90) -- --
------ ----- ----- ---- ----- ------ ---- ----
Pre-tax operating
profit(1) $0.89 $0.53 $0.36 68% $0.69 $0.56 $0.13 23%
===== ====== ====== ==== ===== ===== ===== ===
</TABLE>
- -----------------
(1) Excluding non-cash mark-to-market, ceiling test provision, impairment of
equity securities and interest income and expenses.
<PAGE>
RESULTS OF OPERATIONS
Three Months Ended September 30, 1999 Compared to September 30, 1998
Revenues
During the third quarter of 1999, oil and gas sales revenues (unhedged)
increased to $39.5 million from $29.2 million, or 35%, when compared to the
prior year comparable period due principally to higher oil and gas prices and
increased gas production. Average price realizations for oil improved by 57% to
$20.16 per barrel compared to $12.87 per barrel in the prior year comparable
period. Natural gas prices increased by 34% to $2.34 compared to $1.74 in the
third quarter of 1998. Average price realizations recited exclude price risk
management activities. Oil production declined by 22% during the third quarter
of 1999 while natural gas production increased 9% when compared to the prior
year comparable period. Natural gas production represented approximately 66% of
total Company production on an Mcfe basis, up from the 58% reported in the third
quarter of 1998.
As a result of the continued upward price movement in oil prices through the
third quarter of 1999, commodity price risk management activities resulted in
non-cash net losses of $22.2 million due to mandatory mark-to-market accounting
requirements. This non-cash loss was in addition to approximately $2.3 million
in cash settlements paid during the quarter.
Costs and Expenses
Production and operating expenses increased to $9.6 million for the third
quarter of 1999 when compared to the $9.2 million reported for the third quarter
of 1998. The increase is primarily related to reduced cost efficiencies that
result from lower oil production. Operating costs were $0.65 per Mcfe for the
third quarter of 1999 when compared to $0.61 per Mcfe in the third quarter of
1998.
Depreciation, depletion and amortization ("DD&A"), for the quarter ended
September 30, 1999 was $13.3 million, a $0.4 million decline when compared to
the $13.7 million recorded in the prior year comparable period. The decline is
related to lower volumes produced. The current DD&A rate per Mcfe is $0.90,
unchanged from the comparable prior year quarter.
General and administrative expense ("G&A") declined by $44,000 in the third
quarter of 1999 to $1.18 million primarily due to cost containment efforts in
response to low commodity prices when compared to the $1.22 million incurred in
the third quarter of 1998. The rate per Mcfe for G&A costs is unchanged quarter
over quarter at $0.08 per Mcfe.
Income (Loss) Before Income Taxes
The Company's reported loss before income tax benefits for the third quarter of
1999 was $14.6 million. This compares to a pre-tax income of $5.3 million
reported in the third quarter of 1998. The current period loss is the result of
recording the non-cash mark-to-market commodity price risk position at September
30, 1999.
Income Taxes
Income tax benefits were recorded for the 1999 third quarter in the amount of
$5.1 million as a result of the reported pre-tax loss. The third quarter 1998
income tax expense recorded was $1.8 million.
<PAGE>
Nine Months Ended September 30, 1999 Compared to September 30, 1998
Revenues
For the first nine months of 1999, oil and gas sales revenues (unhedged)
declined $1.1 million, or just over 1% to $96.3 million when compared to the
prior year comparable period primarily as the result of lower oil production.
Natural gas production increased 5% over the prior year first nine months.
Average Mcfe price realizations exclusive of price risk management activities
were flat compared to last year's first nine months. Natural gas production
represented approximately 65% of total Company production on an Mcfe basis
compared to the 59% reported for the first nine months of 1998. Average oil
price realizations exclusive of price risk management activities increased 15%
compared to last year's first nine months. Oil production declined by 20% over
the prior year comparable period due to normal decline from seasoned properties
and lower commodity prices that limited capital expenditures and maintenance on
oil production related activities in general during the first half of the year.
Commodity price risk management activities during the first nine months of 1999
resulted in a net loss of $37.5 million compared to a net gain of $7.5 million
recognized in the prior year comparable period. The loss for the first nine
months of 1999 consisted of $7.8 million in actual cash settlements received
primarily related to oil hedges and $45.2 million in non-cash mark-to-market
provision on the entire commodity price risk management portfolio. The positive
cash flow was more than offset by the mandatory mark-to-market non-cash loss
calculated on the portfolio of commodity price risk management contracts using
September 30, 1999 prices. In the prior year comparable period, $4.0 million of
cash settlements were realized while the mark-to-market component was
represented by a $3.5 million non-cash gain. The impact of all such activities
on an Mcfe basis amounted to net cash inflows of $0.17 and $0.08 for the nine
months ending September 30, 1999 and 1998, respectively.
Costs and Expenses
Production and operating expenses during the first nine months of 1999 increased
3% to $29.1 million compared to $28.4 million reported in the prior year
comparable period. The increase is related to slightly higher field level
expenses. Operating costs were $0.65 per Mcfe for the first nine months of 1999
when compared to $0.60 per Mcfe in the first nine months of 1998.
DD&A for the nine months ended September 30, 1999 declined $2.2 million to $40.3
million when compared to the $42.5 million recorded in the prior year comparable
period due to lower oil production. The first nine months DD&A rate per Mcfe is
unchanged at $0.90 when compared to the prior year comparable period. For the
nine month period ending September 30, 1998, the Company recorded a $154 million
($100 million after-tax) non-cash ceiling test provision as required by full
cost accounting rules. This provision was the result of applying substantially
lower commodity prices to estimated recoverable reserves as of September 30,
1998.
G&A costs increased by 1% in the first nine months of 1999 to $3.7 million when
compared to the $3.6 million incurred in the first nine months of 1998. The rate
per Mcfe for both periods was $0.08.
Interest expense is incurred on $150 million of 8-7/8% Senior Subordinated Notes
due 2007 issued in September 1997, $109 million of 10-1/2% Senior Subordinated
Notes due 2006, and bank debt incurred to fund various Company activities.
Interest expense for the nine months ended September 30, 1999 increased by $1.5
million, a 10% increase over the prior year comparable period due to additional
borrowings outstanding under our Revolving Credit Agreement.
<PAGE>
Income (Loss) Before Income Taxes
The Company's reported loss before income tax benefits for the first nine months
of 1999 was $29.7 million. This compares to a pre-tax loss of $152.0 million
reported for the first nine months of 1998. The 1999 nine month loss is the
result of recognizing mark-to-market losses as required by current accounting
rules. The 1998 nine month loss resulted from the non-cash ceiling test
impairment of $154 million ($100 million after-tax) and $14.3 million equity
securities related impairment. Excluding the effect of the mark-to-market and
impairment provisions income before income taxes was $15.5 million and $12.8
million for 1999 and 1998, respectively.
Income Taxes
Income tax benefits were recorded for the first nine months of 1999 in the
amount of $10.4 million as a result of the reported pre-tax loss. The benefit
for income taxes for the comparable nine month period of 1998 was $52.2 million.
LIQUIDITY AND CAPITAL RESOURCES
General
In September 1997, the Company entered into a five-year $150 million Credit
Agreement dated September 23, 1997 (the "Credit Facility") with The Chase
Manhattan Bank, N.A., as administrative agent (the "Agent"), and other lending
institutions (the "Banks"). The Credit Facility provides for an aggregate
principal amount of revolving loans of up to the lesser of $150 million or the
Borrowing Base (as defined) in effect from time to time, and includes a
sub-facility from the Agent for letters of credit. The Borrowing Base at
September 30, 1999 was $150 million with $37.0 million advanced to the Company
on that date. The Borrowing Base is redetermined by the Agent and the Banks
semi-annually based upon their usual and customary oil and gas lending criteria
as such exist from time to time. The Borrowing Base was reaffirmed on July 20,
1999. In addition, the Company may request two additional redeterminations and
the Banks may request one additional redetermination per year. Indebtedness of
the Company under the Credit Facility is secured by a pledge of the capital
stock of each of the Company's material subsidiaries.
Indebtedness under the Credit Facility bears interest at a floating rate based
(at the Company's option) upon (i) the ABR with respect to ABR Loans or (ii) the
Eurodollar Rate (as defined) for one, two, three or nine months (or nine or
twelve months if available to the Banks) with respect to Eurodollar Loans (as
defined), plus the Applicable Margin. The ABR is the greater of (i) the Prime
Rate (as defined), (ii) the Base CD Rate (as defined) plus 1% or (iii) the
Federal Funds Effective Rate (as defined) plus 0.50%. The Applicable Margin for
Eurodollar Loans varies from 0.50% to 0.875% depending on the Borrowing Base
usage. Borrowing Base usage is determined by a ratio of (i) outstanding Loans
(as defined) and letters of credit to (ii) the then effective Borrowing Base.
Interest on ABR Loans is payable quarterly in arrears and interest on Eurodollar
Loans is payable on the last day of the interest period therefore and, if longer
than three months, at three month intervals.
The Company is required to pay to the Banks a commitment fee based on the
committed undrawn amount of the lesser of the aggregate commitments or the then
effective Borrowing Base during a quarterly period equal to a percent that
varies from 0.20% to 0.30% depending on the Borrowing Base usage.
In September 1997, the Company issued $150 million of the 8-7/8% Senior
Subordinated Notes due 2007 (the "8-7/8% Notes"). Interest on the 8-7/8% Notes
accrues at the rate of 8-7/8% per annum and is payable semi-annually in arrears
on March 15 and September 15 of each year, commencing on March 15, 1998. The
8-7/8% Notes mature on September 15, 2007 unless previously redeemed. Except
under limited circumstances, the 8-7/8% Notes are not redeemable at the
Company's option prior to September 15, 2002. Thereafter, the 8-7/8% Notes will
be subject to redemption at the option of the Company, in whole or in part, at
specified redemption prices, plus accrued and unpaid interest, if any, thereon
to the applicable redemption date. In addition, upon a change of control (as
defined in the indenture pursuant to which the 8-7/8% Notes were issued) the
Company is required to offer to redeem the 8-7/8% Notes for cash at 101% of the
principal amount, plus accrued and unpaid interest, if any, thereon to the
applicable date of repurchase.
The 8-7/8% Notes are general unsecured obligations of the Company and are
subordinated in right of payment to all existing and future Senior Debt (as
defined in the 8-7/8% indenture) of the Company, which includes borrowings under
the Credit Facility described above. The 8-7/8% Notes rank pari passu in right
of payment with any existing or future senior subordinated debt of the Company
and rank senior in right of payment to all other subordinated indebtedness of
the Company.
In November 1997, the Company completed the acquisition of Coda Energy, Inc.
("Coda"). The Company paid an aggregate of $324 million including approximately
$192 million in cash ($150 million plus a $42 million adjustment for proceeds
from the disposition of Taurus Energy Corp. ("Taurus"), a subsidiary of Coda
(which occurred on the day prior to closing of the Coda acquisition)),
assumption of $110 million of Coda long-term debt outstanding and three year
warrants to purchase 1,666,667 shares of Common Stock of the Company at $27.50
per share issued to the holders of the outstanding common stock, preferred stock
and options to purchase common stock of Coda. Concurrently with the closing of
the acquisition of Coda, the Company contributed $23 million to Coda that Coda
utilized, together with the funds from the disposition of Taurus, to repay all
of the debt outstanding under Coda's revolving credit facility (approximately
$65 million in principal amount), plus accrued interest thereon, and such credit
facility was thereafter terminated. At closing, the Company funded the cash
portion of the consideration and the cash contribution to Coda through cash on
hand and borrowings of $84 million under its Credit Facility.
On February 25, 1998, the Company merged Coda into Belco and immediately
thereafter transferred all of Coda's assets and liabilities, except for Coda's
obligations under its 10-1/2% Senior Subordinated Notes due 2006 ("the 10-1/2%
Notes") to Belco Energy Corp., a Nevada corporation and a wholly owned
subsidiary of the Company. As of September 30, 1999, the Company also had $109
million principal amount outstanding under the 10-1/2% Notes. Interest on the
10-1/2% Notes accrues at the rate of 10-1/2% per annum and is payable
semi-annually in arrears on April 1 and October 1 of each year. Except under
limited circumstances, the 10-1/2% Notes are not redeemable at the Company's
option prior to April 1, 2001. Thereafter the 10-1/2% Notes will be subject to
redemption at specified prices, plus accrued and unpaid interest, if any,
thereon to the applicable redemption date. The 10-1/2% Notes are general
unsecured obligations of the Company and are subordinated in right of payment to
all existing and future Senior Debt (as defined) of the Company, including any
bank debt.
The Company entered into interest rate swap agreements converting two long-term
debt fixed rate obligations to floating rate obligations as follows:
<TABLE>
<CAPTION>
Current
Agreement Transaction Fixed Floating Floating Rate
Amount Date Rate Rate Expiration Date
--------- ----------- ------ -------- ---------------
<S> <C> <C> <C> <C> <C>
$100 million 12/97 8.875% 8.280% March 15, 2000 (a)
$110 million 12/97 10.500% 10.120% April 1, 2000 (a)
$50 million 1/98 8.875% 8.195% March 15, 2000 (a)
</TABLE>
- -----------------------
(a) Floating rate is redetermined at each six month period following the
expiration through September 15, 2007.
<PAGE>
The agreements obligate the Company to actually pay the indicated floating rate
rather than the original fixed rate. The floating rates are capped at 8-7/8%
through September 15, 2001 and at 10% from March 15, 2002 through September 15,
2007 on the 8- 7/8% Notes and capped at 10-1/2% through October 1, 1999 and
11.625% from April 1, 2000 through April 1, 2003 on the 10-1/2% Notes. The
agreements will reduce the Company's 1999 interest expense by approximately $1
million.
On March 10, 1998 the Company completed the sale of 4.37 million shares of its
6-1/2% Convertible Preferred Stock (the "Preferred Stock"). The Preferred Stock
has a liquidation preference of $25 per share and is convertible at the option
of the holder into shares of the Company's Common Stock at an initial conversion
rate of 1.1292 shares of Common Stock for each share of Preferred Stock,
equivalent to a conversion price of $22.14 per share of Common Stock. The
Company received net proceeds from the sale of the Preferred Stock of $105.1
million, which was used to pay down bank indebtedness.
On December 15, 1998, the Company's Board of Directors authorized the purchase
from time to time, in the open market or in privately negotiated transactions,
shares of its Common Stock and 6-1/2% Convertible Preferred Stock, in an
aggregate amount not to exceed $10 million. Through September 30, 1999 the
Company has expended approximately $2.0 million acquiring 130,900 shares of its
6-1/2% Convertible Preferred Stock and $0.6 million acquiring 95,800 shares of
its Common Stock.
On June 12, 1998, the Company, through its wholly-owned Canadian subsidiary,
purchased approximately $10.5 million of 5% Convertible Preferred Stock of Big
Bear, a Canadian oil and gas company, at approximately $0.85 per share with each
share convertible into one common share of Big Bear. The Company was also issued
approximately $120 million of Special Acquisition Warrants at a price of
approximately $0.72 per warrant. In connection with the issuance of the Special
Acquisition Warrants, the Company deposited a $60 million letter of credit and
3,436,000 shares of the Company's common stock into an escrow account. On
November 10, 1998, the Company executed a restructuring agreement whereby (i)
the Company agreed to convert the Big Bear 5% Convertible Preferred Stock into
21,428,571 shares of Big Bear common stock at a conversion price of
approximately $0.50 per share (reduced from $0.85 per share), (ii) the Special
Acquisition Warrants were canceled, (iii) the Belco representatives resigned
from Big Bear's Board of Directors, (iv) the $60 million letter of credit was
canceled, and (v) the 3,436,000 shares of Company common stock held in the
escrow account were returned to the Company and designated as unissued. The
restructuring agreement closed on January 22, 1999. Immediately following the
closing of the restructuring agreement, an 11 to 1 reverse split of Big Bear
common shares was effected and Belco, through its wholly-owned Canadian
subsidiary, now owns 1,948,052 common shares or approximately 4.6% ownership in
Big Bear.
In February 1998, the Company acquired properties consisting of approximately 65
Bcfe of long-lived reserves in the Permian Basin of west Texas from EnerVest
Texoma Acquisition L.P. for $37.3 million in cash.
In November 1998, the Company acquired approximately 20 Bcfe of long-lived
reserves on producing properties in Oklahoma and Kansas, as well as certain
undeveloped acreage and 3-D seismic data, for approximately $14.8 million.
In September 1999, the Company acquired 25.4 Bcfe of long lived reserves on
producting properties in the Permian Basin and south Texas for approximately
$16.3 million.
Cash Flow
Operating cash flow, a measure of performance for exploration and production
companies, is generally derived by adjusting net income to eliminate the effects
of the non-cash components included in the net income calculation such as
depreciation, depletion and amortization expense, provision for deferred income
taxes, ceiling test provisions, and the non-cash effects of investing and
commodity price risk management activities. Cash flow from operating activities
for the first nine months was approximately $54.3 and $66.3 million for 1999 and
1998, respectively. The Company had a working capital deficit of $14.1 million
as of September 30, 1999, a decrease of $17.5 million from the $3.4 million
available as of June 30, 1999. The deficit is created by the recording of
non-cash mark-to-market losses related to derivatives activities as required by
current accounting rules. Excluding the mark-to-market items, working capital
would have been $7.0 million at September 30, 1999.
Capital Expenditures
During the nine months ending September 30, 1999 the Company incurred
approximately $51.8 million of capital expenditures including approximately
$17.1 million in property acquisitions. For the full year 1998, the Company
incurred capital expenditures in the amount of $133.1 million, including
property acquisitions totalling $52.2 million.
The Company intends to fund its future capital expenditures, commitments and
working capital requirements through cash flows from operations, borrowings
under the Credit Facility or other potential financings. The Company has a 1999
capital expenditure budget of approximately $75 million, with $25 million
allocated to potential acquisitions. If there are changes in oil and natural gas
prices that correspondingly affect cash flows and the Borrowing Base under the
Credit Facility, the Company has the discretion and ability to adjust its
capital budget. The Company believes that it will have sufficient capital
resources and liquidity to fund its capital expenditures and meet all of its
financial obligations as they come due.
Commodity Price Risk Management Transactions
Certain of the Company's commodity price risk management arrangements require
the Company to deliver cash collateral or other assurances of performance to the
counterparties in the event that the Company's payment obligations with respect
to its commodity price risk management transactions exceed certain levels. At
September 30, 1999, the Company had $3.9 million on deposit for margin calls
related to its commodity price risk management activities.
With the primary objective of achieving more predictable revenues and cash flows
and reducing the exposure to fluctuations in oil and natural gas prices, the
Company has entered into commodity price risk management transactions of various
kinds with respect to both oil and natural gas. While the use of certain of
these price risk management arrangements limits the downside risk of adverse
price movements, it may also limit future revenues from favorable price
movements. The Company engages in transactions such as selling covered calls or
straddles which are marked-to-market at the end of the relevant accounting
period. Since the futures market historically has been highly volatile, these
fluctuations may cause significant impact on the results of any given accounting
period. The Company has entered into price risk management transactions with
respect to a substantial portion of its estimated production for 1999 and lesser
portions of its estimated production thereafter. The Company continues to
evaluate whether to enter into additional price risk management transactions for
future years. In addition, the Company may determine from time to time to unwind
its then existing price risk management positions as part of its price risk
management strategy.
Other
Environmental Matters
The Company's operations are subject to various federal, state and local laws
and regulations relating to the protection of the environment, which have become
increasingly stringent. The Company believes its current operations are in
material compliance with current environmental laws and regulations. There are
no environmental claims pending or, to the Company's knowledge, threatened
against the Company. There can be no assurance, however, that current regulatory
requirements will not change, currently unforeseen environmental incidents will
not occur or past noncompliance with environmental laws will not be discovered
on the Company's properties.
<PAGE>
Year 2000 Compliance
The year 2000 issue concerns deal with the potential inability of information
technology and non-information technology systems and processes to properly
recognize and process date-sensitive information before, during, and after
December 31, 1999.
The Company has a variety of operating systems, computer software program
applications, computer hardware equipment and other equipment with embedded
electronic circuits, including applications used in the Company's financial
business systems, field operations, and administrative functions (collectively,
the "systems").
Members of the Company's management group and financial department personnel
have oversight of the information systems and personnel charged with
implementing the Company's year 2000 compliance program.
The Company has upgraded hardware and software over the past year and believes
that its internal financial and most of the operational systems are currently
year 2000 compliant. The Company does not separately track the costs associated
with the year 2000 compliance effort, as they have not been material and,
further, no projects with any significant impact to the Company's operations
have been deferred due to the year 2000 compliance effort. To date, the Company
estimates that it has incurred less than $100,000 in upgrading a limited amount
of hardware and does not expect to incur any significant additional cost in
becoming year 2000 compliant. The Company does not know whether its significant
vendors' and customers' systems are yet fully year 2000 compliant. If they are
not, such failure could partially affect the Company's ability to sell its oil
and gas and receive related payments. In addition, there could be disruptions in
getting certain vendors to provide supplies and/or services in support of the
Company's operations. While this is the most likely worst case scenario, the
Company believes that its significant vendors and customers will be year 2000
compliant before that critical date.
Additionally, the Company fully understands that there are risks associated with
year 2000 issues that it cannot directly control, primarily the readiness of its
key suppliers and customers. The Company has had contact with a significant
number of its customers and vendors and furnished information about how it is
addressing the year 2000 issue. The Company is presently investigating
contingency strategies primarily with existing internal resources in the event
of any third party or internal system failure. Contingency plans contemplated
include the use of alternative hardware and software vendors and customers as
appropriate in the event that a presently unforeseen failure of a key vendor or
customer is burdened with some non-controllable year 2000 compliance related
failure.
The Company presently expects that its financial and related information
systems, operations systems and other essential functions will be ready for the
year 2000 transition, and that year 2000 issues would not have a material effect
on the Company's business or financial condition.
New Accounting Standards
In June 1998, the Financial Accounting Standards Board issued Statement No. 133,
Accounting for Derivative Instruments and Hedging Activities ("FAS 133"). FAS
133 requires all derivatives to be recorded on the balance sheet at fair value
and established "special accounting" for the following three different types of
hedges: hedges of changes in the fair value of assets, liabilities, or firm
commitments (referred to as fair value hedges); hedges of the variable cash
flows of forecasted transactions (cash flow hedges); and hedges of foreign
currency exposures of net investments in foreign operations. Though the
accounting treatment and criteria for each of the three types of hedges is
unique, they all result in offsetting changes in fair values or cash flows of
both the hedge and the hedged item being recognized in earnings in the same
period with no net impact on reported earnings. Changes in fair value of
derivatives that do not meet the criteria of one of these three categories of
hedges are included in income and reported as either gain or loss for the
current period. Transition adjustments resulting from adoption must be
recognized in income and comprehensive income, as appropriate, as a cumulative
effect of an accounting change. Belco has not yet determined the effect of total
compliance, but it is not expected to materially impact the financial statements
of the Company. FAS 133 will be effective for fiscal year 2001 for the Company.
Information Regarding Forward Looking Statements
The information contained in this Form 10-Q includes certain forward-looking
statements. When used in this document, such words as "expect", "believes",
"potential", and similar expressions are intended to identify forward-looking
statements. Although the Company believes that its expectations are based on
reasonable assumptions, it is important to note that actual results could differ
materially from those projected by such forward-looking statements. Important
factors that could cause actual results to differ materially from those in the
forward-looking statements include, but are not limited to, the timing and
extent of changes in commodity prices for oil and gas, the need to develop and
replace reserves, environmental risk, the substantial capital expenditures
required to fund its operations, drilling and operating risks, risks related to
exploration and development, uncertainties about the estimates of reserves,
competition, government regulation and the ability of the Company to implement
its business strategy.
ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's market risk exposures relate primarily to
commodity prices, interest rates and marketable equity securities. The Company
enters into various transactions involving commodity price risk management
activities involving a variety of derivatives instruments to, in effect, hedge
the impact of crude oil and natural gas price fluctuations. In addition, the
Company entered into interest rate swap agreements to reduce current interest
burdens related to its fixed long-term debt. The derivatives instruments are
generally put in place to limit the risk of adverse oil and natural gas price
movements, however, such instruments can limit future gains resulting from
upward favorable oil and natural gas price movements. Recognition of both
realized and unrealized gains or losses are reported currently in the Company's
financial statements as required by existing generally accepted accounting
principles. The cash flow impact of all derivative related transactions is
reflected as cash flows from operating activities.
As of September 30, 1999, the Company had substantial derivative financial
instruments outstanding and related to its market risk management program. See
Item 1, Note 2 and Item 2, "Management's Discussion And Analysis of Financial
Condition And Results of Operations" for additional information related to the
Company's market risk management activities during the third quarter of 1999.
There has not been a material change in the Company's exposure to commodity
price and interest rate risk since the date of the 1998 Form 10-K filing.
<PAGE>
PART II - OTHER INFORMATION
ITEM 1 - LEGAL PROCEEDINGS NONE
ITEM 2 - CHANGES IN SECURITIES AND USE OF PROCEEDS NONE
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 AND REPORTS ON FORM 8-K
(a) Exhibits.
Exhibit No.
27* Financial Data Schedule
- -------------------
* Filed herewith
(b) Reports on Form 8-K: None.
<PAGE>
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.
BELCO OIL & GAS CORP.,
a Nevada corporation
(REGISTRANT)
<TABLE>
<S> <C>
Date: November 12, 1999 /s/ LAURENCE D. BELFER
----------------------------------
Laurence D. Belfer,
Vice-Chairman and Chief Operating
Officer
Date: November 12, 1999 /s/ DOMINICK J. GOLIO
----------------------------------
Dominick J. Golio,
Senior Vice President - Finance
and Chief Financial Officer
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 4,971
<SECURITIES> 0
<RECEIVABLES> 22,027
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 38,819
<PP&E> 1,056,758
<DEPRECIATION> (605,813)
<TOTAL-ASSETS> 501,941
<CURRENT-LIABILITIES> 52,893
<BONDS> 302,013
0
42
<COMMON> 317
<OTHER-SE> 111,970
<TOTAL-LIABILITY-AND-EQUITY> 501,941
<SALES> 39,520
<TOTAL-REVENUES> 15,246
<CGS> 22,814
<TOTAL-COSTS> 22,814
<OTHER-EXPENSES> 1,178
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 5,838
<INCOME-PRETAX> (14,584)
<INCOME-TAX> (5,104)
<INCOME-CONTINUING> (9,480)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (9,480)
<EPS-BASIC> (0.35)
<EPS-DILUTED> (0.35)
</TABLE>
