Message #3 From:
Stock News Bot Date: August 11, 2006 10:23:00 AM
CXPI News Crimson Exploration Inc. Announces Second Quarter 2006 Financial and Operational Results
HOUSTON--(BUSINESS WIRE)--Aug. 11, 2006--Crimson Exploration Inc. (OTCBB:CXPI) today announced financial and operational results for the second quarter of 2006.
Summary Financial Results
Revenues for the second quarter of 2006 were $5.2 million compared to revenue of $4.4 million in the prior year quarter, an 18% increase due to higher average realized prices, partly offset by lower sales volumes, both of which are quantified below.
Production for the second quarter of 2006 was 636,968 mcfe of natural gas equivalents, or 7,000 mcfe per day, compared with production of 707,264 mcfe, or 7,772 per mcfe day, in the 2005 quarter. Lower volumes in the 2006 quarter, compared to the 2005 quarter, resulted from the continued restriction on production (approximately 600 mcfepd) at our Lacassine field in Cameron Parish where we were finishing repairs related to Hurricane Rita and installing production equipment to treat our high btu gas to meet more stringent pipeline requirements. In addition, we had a decline in production of 600 mcfepd from our horizontal wells in the Iola field in east Texas, where early life, flush production from second quarter 2005 drilling declined to a lower, but more consistent production rate. These production declines were partially offset by a 200 mcfepd average increase in production for the quarter in our Madisonville, Grand Lake and Colorado fields where we implemented workover and drilling projects during the current year. We are currently producing at an average net rate of approximately 7,000 mcfe per day.
Average prices received in the field during the second quarter of 2006 were $67.47 per barrel of oil and $6.56 per mcf of natural gas, or $8.55 per mcfe of natural gas equivalent, compared to $50.02 per barrel of oil, $6.64 per mcf and $7.33 per mcfe for the 2005 quarter. Adjusting for the effects of realized losses on our commodity price hedges, our average realized prices in the 2006 quarter were $60.48, $6.61 and $8.09 for oil, natural gas and natural gas equivalents, respectively. For 2005, average realized prices for the quarter were $37.26, $6.15 and $6.18 per barrel, mcf and mcfe, respectively.
Total Operating Expenses for the 2006 quarter were $4.8 million compared to $3.5 million in the 2005 quarter. Of the $1.3 million increase in total operating expenses, lease operating expenses contributed approximately $350,000 due to higher workover costs, higher salt-water disposal costs and higher prices for supplies and services prevalent in the industry. General and administrative costs increased by approximately $1.2 million, approximately $1.0 million of which is related to non-cash compensation expense related to the adoption of SFAS 123R for stock options. Included in expense for the 2005 quarter was $389,000 in dry hole costs.
Other Income and Expense was a net positive $69,000 for the 2006 quarter compared to a net positive amount of approximately $534,000 in 2005, with the main difference being higher unrealized gain on derivative instruments in 2005.
Cash flow from operations for the first quarter of 2006, exclusive of changes in working capital, increased to $2.2 million, a 29% increase over the $1.7 million reported for the 2005 quarter, due primarily to the price-related increase in revenue. We reported net income for the second quarter of 2006 of $202,000 compared to net income of $845,000 for the second quarter of 2005.
Selected Financial and Operating Data
The following table reflects certain comparative financial and operating data for the three and six month periods ending June 30, 2006 and 2005:
Three Months
------------
Ending June 30,
---------------
2006 2005 %
---- ----
Total Volumes Sold:
Crude oil (barrels) 45,187 47,771 -5%
Natural gas (mcf) 365,846 420,638 -13%
Natural gas equivalents (mcfe) 636,968 707,264 -10%
Daily sales volumes:
Crude oil (barrels) 497 525 -5%
Natural gas (mcf) 4,020 4,622 -13%
Natural gas equivalents (mcfe) 7,000 7,772 -10%
Daily Sales Volumes (mcfe) by Area:
Cameron Parish LA 3,509 3,981 -12%
Texas Onshore 2,682 3,143 -15%
DJ Basin CO 777 596 30%
Other 32 52 -38%
------------ ------------
7,000 7,772 -10%
Average oil sales price ($ per bbl):
Average price received in field $67.47 $50.02 35%
Realized effects of hedging
instruments $(6.99) (12.76) -45%
------------ ------------
Net realized price, after hedging $60.48 $37.26 62%
Average basis differential (NYMEX
-WTI) $(3.24) $(3.21) 1%
Average gas sales price ($ per mcf):
Average price received in field $6.56 $6.64 -1%
Realized effects of hedging na
instruments 0.05 (0.49)
------------ ------------
Net realized price, after hedging $6.61 $6.15 7%
Average basis differential (Houston
Ship Channel) $0.05 $0.07 -29%
Selected Costs ($ per mcfe):
Lease operating expenses $2.68 $1.93 39%
Depreciation and depletion expense $1.44 $1.18 22%
General and administrative $3.36 $1.32 36%
Interest $0.09 $0.03 243%
Cash provided by (used in) operating
activities, exclusive of changes in
working capital $2,222,423 $(1,660,275) 34%
Capital expenditures
Leasehold acquisition $403,391 $41,982
Exploratory 363,869 2,331,171
Development 2,765,717 1,949,059
Other 25,362 48,211
------------ ------------
$3,558,339 $4,370,423
Capital Expenditures (by area)
Cameron Parish LA $1,771,656 $824,767
Texas Onshore 1,107,675 1,165,442
Texas Offshore - 2,331,171
DJ Basin CO 653,646 1,082
Other 25,362 47,961
------------ ------------
$3,558,339 $4,370,423
Earnings per Common Share
Basic $(0.02) $(0.00)
Fully Diluted $(0.02) $(0.00)
Six Months
----------
Ending June 30,
---------------
2006 2005 %
---- ----
Total Volumes Sold:
Crude oil (barrels) 91,033 92,479 -2%
Natural gas (mcf) 683,452 764,653 -11%
Natural gas equivalents (mcfe) 1,229,650 1,319,527 -7%
Daily sales volumes:
Crude oil (barrels) 503 511 -2%
Natural gas (mcf) 3,776 4,225 -11%
Natural gas equivalents (mcfe) 6,794 7,290 -7%
Daily Sales Volumes (mcfe) by Area:
Cameron Parish LA 3,312 3,941 -16%
Texas Onshore 2,754 2,703 2%
DJ Basin CO 689 5,995 16%
Other 39 51 -24%
------------ ------------
6,794 7,290 -7%
Average oil sales price ($ per bbl):
Average price received in field $64.23 $48.95 31%
Realized effects of hedging
instruments (4.94) (12.38) -60%
------------ ------------
Net realized price, after hedging $59.29 $36.57 62%
Average basis differential (NYMEX
-WTI) $(2.90) $(2.70) 7%
Average gas sales price ($ per mcf):
Average price received in field $7.14 $6.47 10%
Realized effects of hedging
instruments (0.02) (0.43) -95%
------------ ------------
Net realized price, after hedging $7.12 $6.04 18%
Average basis differential (Houston
Ship Channel) $0.15 $0.23 -35%
Selected Costs ($ per mcfe):
Lease operating expenses $2.68 $2.10 28%
Depreciation and depletion expense $1.36 $1.13 20%
General and administrative $3.14 $1.18 47%
Interest $0.05 $0.92 -94%
Cash provided by (used in) operating
activities, exclusive of changes in
working capital $4 ,714,590 $2,551,668 85%
Capital expenditures
Leasehold acquisition $8,322,685 $727,513
Exploratory 363,869 2,331,171
Development 3,645,542 3,325,030
Other 76,629 93,935
------------ ------------
$12,408,725 $6,477,649
Capital Expenditures (by area)
Cameron Parish LA $2,175,335 $779,886
Texas Onshore 9,453,012 3,261,825
Texas Offshore - 2,331,171
DJ Basin CO 703,749 11,082
Other 76,629 93,685
------------ ------------
$12,408,725 $6,477,649
Earnings per Common Share
Basic $(0.01) $(0.15)
Fully Diluted $(0.01) $(0.15)
Non - GAAP Financial Measures
Crimson also presents net cash flow from operations, exclusive of working capital items, which consists of net cash provided by operating activities plus the period change in accounts receivable, other current assets, accounts payable and accrued expenses. Management uses this measure to assess the company's ability to generate cash to fund exploration and development activities. Management interprets trends in this measure in a similar manner as trends in cash flow and liquidity. Net cash flows from operations, exclusive of working capital items should not be considered as an alternative to net cash provided by operational activities as defined by GAAP. The following is a reconciliation of net cash provided by operational activities to net cash flow from operations, exclusive of working capital items:
Three Months Six Months
------------ ----------
Ended June 30, Ended June 30,
-------------- --------------
2006 2005 2006 2005
---- ---- ---- ----
Net cash provided by
(used in) operating
activities, per
Statement of Cash
Flows $2,888,720 $(2,273,133) $5,631,630 $(530,387)
Changes in working
capital
Accounts receivable (105,422) (61,424) (672,850) 1,010,646
Prepaid Expenses (162,729) 81,856 128,154 92,212
Accounts payable
and accrued
expenses (398,146) 592,426 (372,344) 1,979,197
----------- ------------ ----------- -----------
Net cash flow from
operations,
exclusive of working
capital items $2,222,423 $(1,660,275) $4,714,590 $2,551,668
=========== ============ =========== ===========
CRIMSON EXPLORATION INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
ASSETS 2006 2005
------ ------------ ------------
Total current assets $4,074,360 $5,825,078
Net property and equipment 64,953,592 54,223,059
Total other assets 709,498 3,066,812
------------ ------------
Total Assets $69,737,450 $63,114,949
============ ============
June 30, December 31,
LIABILITIES AND STOCKHOLDERS' EQUITY 2006 2005
------------------------------------ ------------ ------------
Total current liabilities $6, 359,356 $6,855,735
Total non-current liabilities 4,440,664 3,453,952
Total stockholders' equity 58,937,430 52,805,262
------------ ------------
Total Liabilities & Stockholders' Equity $69,737,450 $63,114,949
============ ============
CRIMSON EXPLORATION INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Six Months
Ending June 30, Ending June 30,
2006 2005 2006 2005
----------- ----------- ------------ -----------
OPERATING REVENUES
Oil and gas sales $5,150,063 $4,367,751 $10,263,560 $8,001,911
Operating overhead
and other income 30,130 25,289 56,282 55,462
----------- ----------- ------------ -----------
Total Operating
Revenues 5,180,193 4,393,040 10,319,842 8,057,373
----------- ----------- ------------ -----------
OPERATING EXPENSES
Lease operating
expenses 1,710,081 1,364,998 3,289,401 2,765,862
Geological and
geophysical 47,141 - 55,918 -
Depreciation,
depletion and
amortization 919,431 835,231 1,673,807 1,491,009
Dry holes, abandoned
property and
impaired assets 8,036 389,183 12,422 391,339
Asset retirement
obligations 20,994 19,161 41,988 38,322
General and
administrative 2,141,074 934,902 3,864,737 1,553,129
----------- ----------- ------------ -----------
Total Operating
Expenses 4,846,757 3,543,475 8,938,273 6,239,661
----------- ----------- ------------ -----------
INCOME FROM
OPERATIONS 333,436 849,565 1,381,569 1,817,712
----------- ----------- ------------ -----------
OTHER INCOME AND
EXPENSE
Interest expense (55,878) (18,099) (65,800) (1,216,600)
Financing cost (43,447) (5,000) (88,564) (1,910,159)
Loss from equity in
investments - (36,159) (1,843) (36,159)
Loss on sale of
assets - (25,894) - (38,916)
Unrealized gain
(loss) on
derivative
instruments 168,667 618,775 1,276,947 (1,394,706)
----------- ----------- ------------ -----------
Total Other
Income and
(Expense) 69,342 533,623 1,120,740 (4,596,540)
----------- ----------- ------------ -----------
INCOME (LOSS) BEFORE
INCOME TAXES 402,778 1,383,188 2,502,309 (2,778,828)
INCOME TAX (EXPENSE)
BENEFIT (200,913) (537,889) (927,635) 849,802
----------- ----------- ------------ -----------
NET INCOME (LOSS) 201,865 845,299 1,574,674 (1,929,026)
=========== =========== ============ ===========
Operational Review by Area
Madisonville Area
The Company continues to devote substantial time and effort to its Madisonville-Rodessa development project with significant progress being made during the second quarter of 2006. During the second quarter, we received the Texas Railroad Commission approval of our waste disposal well and plan, received verbal acknowledgment that receipt of the Commission's order granting access to the field gas plant is eminent, finalized agreements with land owners for disposal rights, and began clearing locations in preparation for drilling operations. We have since executed a contract for a drilling rig to drill two Rodessa wells (Crimson 67.8% WI) with an option on the rig to drill a third Rodessa well during the second half of 2006. We also plan to drill the waste disposal well which is required before production can commence. Net capital expenditures for this work is estimated to be approximately $9,000,000. First Rodessa production is expected in the first quarter of 2007 corresponding with the planned expansion of the existing gas plant. The company recognized no proved reserves for the Rodessa as of January 1, 2006 because we had not obtained the necessary regulatory permits as of that time.
D-J Basin, CO
During the second quarter of 2006, the Company drilled two successful wells in Colorado. The Kissler #2 well (99.5% WI) was drilled in the Wattenberg Field located in Weld County and has been completed in the Codell sand at approximately 7200'. It is currently producing at approximately 250 mcfe per day, net. The Amoco State 41-16 well (93.9% WI) was drilled in the Wattenberg Field in Adams County and has been completed in the J Sand at approximately 8000'. It is currently waiting on facility hook-up expected in the third quarter. The net cost of these two wells was approximately $935,000.
Also during the quarter, the Company retained a Denver-based consulting firm to analyze its entire holdings in the D-J Basin to identify additional potential drilling opportunities. The Company owns approximately 14,300 gross (10,700 net) undeveloped acres in the D-J basin. Further drilling in this field during 2006 will be based on the results of this study and contingent upon rig availability.
Cameron Parish LA
During the second quarter of 2006, in the Grand Lake Field (WI 100%) production commenced at a net rate of 350 mcfe from the #33 well which was recompleted in the first quarter. The #38 well was recompleted during the second quarter and commenced production at approximately 225 mcfe per day. A workover on the #17 well was in progress at quarter-end and is expected to commence production in August. These increases allowed us to offset normal production decline and restore production levels to pre-hurricane rates. Total capital expended during the quarter on these projects was approximately $1,000,000.
At Lacassine Field (WI 100%), production rates have been limited by salt water disposal capacity caused as a result of the shut-in from the hurricanes last fall. At the end of the quarter, we began converting the Lacassine Co. B-11 well to an additional salt water disposal well with work expected to be completed early in the third quarter of 2006. Once this work is complete, we will perform remedial work on two shut-in wells in order to restore them to production. Total net capital expenditures for these projects is estimated to be approximately $700,000.
Mississippi Coal Bed Methane
During the second quarter, we also finalized plans to drill 3 stratigraphic core wells to evaluate the feasibility of developing and producing coal bed methane from Wilcox coals between 900 feet and 3200 feet in southeast Mississippi, where we have 125,000 acres under option. Existing well control in the area shows the existence of coal beds but have limited quantitative and qualitative data to determine their producibility. The actual drilling of those wells should commence in the third quarter. The Company anticipates spending approximately $400,000 on this feasibility study during the latter half of 2006. Crimson will pay 85% of the cost of the core wells to earn a 70% WI in the project.
Exploratory Joint Venture
In July 2006 we entered into a joint exploration agreement with a privately owned prospect generation company focused on generating exploratory drilling opportunities primarily in the onshore Gulf Coast area. Under this agreement, which has an initial term of one year with an option for a second, we are entitled to a first right of refusal for up to 50% working interest on all prospects generated during the term of the agreement. If we elect to participate in any of the prospects generated, it will be on a normal third for a quarter basis.
Teleconference Call
Crimson management will hold a conference call to discuss the information described in this press release at 1:30 p.m. CDT on Monday, August 14, 2006. Those interested in participating may do so by calling the following phone number: (800) 811-8845, (International (913) 981-4905) and entering the participant code 9557249. A replay of the call will be available from August 14, 2006 through August 21, 2006 by dialing toll free (888) 203-1112, (International (719) 457-0820) and asking for replay ID code 9557249.
This press release includes "forward-looking statements" as defined by the Securities and Exchange Commission ("SEC"). Such statements include those concerning Crimson's strategic plans, expectations and objectives for future operations. All statements included in this press release that address activities, events or developments that Crimson expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions Crimson made based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond Crimson's control. Statements regarding future production are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are not limited to, inflation or lack of availability of goods and services, environmental risks, drilling risks and regulatory changes and the potential lack of capital resources. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. Please refer to our filings with the SEC, including our Form 10-K for the year ended December 31, 2005 for a further discussion of these risks.
