exv99w1
Exhibit 99.1
McMoRan Exploration Co. Reports
Second-Quarter/Six-Month 2011 Results
HIGHLIGHTS
| • |
|
Shallow Water, Ultra-Deep Exploration & Development Activities: |
| |
• |
|
In June 2011, results from wireline logs of the Cretaceous section
indicated that the Davy Jones No. 2 well encountered 192 net feet of potential
hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. Flow
testing will be required to confirm the potential hydrocarbons and flow rates
from these sandstones and limestones. |
| |
| |
• |
|
Completion for flow testing expected to commence in the second
quarter of 2012. |
| |
| |
• |
|
Previous wireline logs confirmed hydrocarbon bearing Wilcox sands
seen in the Davy Jones No. 1 discovery well. |
| |
• |
|
Exploration results to date indicate updip potential in the Miocene
(178 net feet of hydrocarbons) above 25,000 feet and downdip potential in the
Oligocene (Frio) below 30,000 feet. |
| |
| |
• |
|
In July 2011, commenced operations to drill a by-pass well at
approximately 30,700 feet to evaluate targets in the Eocene. |
| |
• |
|
Commenced drilling on October 3, 2010, currently below 24,200 feet
with a proposed total depth of 29,950 feet. Targeting Miocene and Oligocene
objectives. |
| • |
|
Shallow Water, Deep Gas Exploration & Development Activities: |
| |
• |
|
Production commenced in April 2011 and averaged a gross rate of
approximately 50 million cubic feet of natural gas equivalents per day (MMcfe/d)
(15 MMcfe/d net to McMoRan) in May and June of 2011. |
| |
• |
|
Exploratory well commenced drilling on February 27, 2011 and is
drilling below 19,350 feet towards a proposed total depth of 23,100 feet. |
| • |
|
Second-quarter 2011 production averaged 197 MMcfe/d net to McMoRan, compared with 165
MMcfe/d in the second quarter of 2010. |
| |
| • |
|
Average daily production for 2011 is expected to approximate 185 MMcfe/d net to
McMoRan, including 180 MMcfe/d in third quarter 2011. |
| |
| • |
|
Operating cash flows totaled $102.6 million for the second quarter of 2011, including
working capital sources of $28.4 million and $20.0 million in abandonment expenditures. |
| |
| • |
|
Capital expenditures totaled $162.4 million in the second quarter of 2011 and $258.9
million for the six months ended June 30, 2011. |
| |
| • |
|
Cash at June 30, 2011 totaled $765.3 million. |
1
NEW ORLEANS, LA, July 19, 2011 — McMoRan Exploration Co. (NYSE: MMR) today reported a net loss
applicable to common stock of $50.2 million, $0.32 per share, for the second quarter of 2011
compared with a net loss of $21.7 million, $0.23 per share, for the second quarter of 2010.
James R. Moffett and Richard Adkerson, McMoRan’s Co-Chairmen, said, “The data gained to
date from our ultra-deep drilling program in the shallow waters of the Gulf of Mexico add to
our enthusiasm for the resource potential of this important new geologic trend. Through our
drilling activities, we have confirmed the potential for large hydrocarbon bearing structures
below salt in the Miocene, Wilcox, Frio, Tuscaloosa and Cretaceous Carbonate formations. Our
ongoing exploration drilling and flow testing of the Davy Jones wells in the coming months have
the potential to enhance our reserve and production profile meaningfully.”
SUMMARY FINANCIAL TABLE*
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|
|
| |
|
Second Quarter |
|
|
Six Months |
|
| |
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
| |
|
(In thousands, except per share amounts) |
|
Revenues |
|
$ |
158,308 |
|
|
$ |
108,041 |
|
|
$ |
295,312 |
|
|
$ |
240,529 |
|
Operating loss |
|
|
(35,392 |
) |
|
|
(5,188 |
) |
|
|
(44,657 |
) |
|
|
(46,470 |
) |
Loss from continuing operations |
|
|
(37,866 |
) |
|
|
(15,017 |
) |
|
|
(52,400 |
) |
|
|
(66,771 |
) |
Loss from discontinued operations |
|
|
(1,989 |
) |
|
|
(1,436 |
) |
|
|
(3,233 |
) |
|
|
(3,076 |
) |
Net loss applicable to common stock(a,b,c,d) |
|
|
(50,198 |
) |
|
|
(21,746 |
) |
|
|
(77,748 |
) |
|
|
(87,906 |
) |
Diluted net loss per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
(0.31 |
) |
|
$ |
(0.22 |
) |
|
$ |
(0.47 |
) |
|
$ |
(0.93 |
) |
Discontinued operations |
|
|
(0.01 |
) |
|
|
(0.01 |
) |
|
|
(0.02 |
) |
|
|
(0.03 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Applicable to common stock |
|
$ |
(0.32 |
) |
|
$ |
(0.23 |
) |
|
$ |
(0.49 |
) |
|
$ |
(0.96 |
) |
Diluted average shares outstanding |
|
|
158,454 |
|
|
|
93,101 |
|
|
|
158,154 |
|
|
|
91,428 |
|
Operating cash flows(e) |
|
$ |
102,594 |
|
|
$ |
11,240 |
|
|
$ |
136,140 |
|
|
$ |
91,533 |
|
EBITDAX(f) |
|
$ |
96,939 |
|
|
$ |
59,010 |
|
|
$ |
175,590 |
|
|
$ |
143,740 |
|
Capital Expenditures |
|
$ |
162,352 |
|
|
$ |
60,598 |
|
|
$ |
258,894 |
|
|
$ |
101,436 |
|
|
|
|
| * |
|
If any in-progress well or unproved property is determined to be non-productive or no
longer meets the capitalization requirements under applicable accounting rules after the
date of this release but prior to the filing of McMoRan’s June 30, 2011 Form 10-Q, the
related costs incurred through June 30, 2011 would be charged to expense in McMoRan’s
second-quarter 2011 financial statements. McMoRan’s total drilling costs for its six
in-progress or unproven wells totaled $438.7 million. In addition, McMoRan’s allocated
costs for the in-progress wells acquired from Plains Exploration & Production Company
(PXP) in the fourth quarter of 2010 totaled $659.5 million. |
| |
| a. |
|
After preferred dividends. |
| |
| b. |
|
Includes impairment charges totaling $29.2 million in second-quarter 2011, $13.7
million in second-quarter 2010, $50.7 million in the first six months of 2011 and $70.7
million in the first six months of 2010 to reduce certain fields’ net carrying value to
fair value. Also includes adjustments for asset retirement obligations associated with
certain of McMoRan’s oil and gas properties totaling approximately $20.4 million in the
second-quarter 2011 and $35.1 million in the first six months of 2011. |
| |
| c. |
|
Includes charges to exploration expense for non-commercial well costs primarily
associated with the Blueberry Hill #9 STK1 well totaling $36.8 million in second-quarter 2011
and $38.9 million in the first six months of 2011. |
| |
| d. |
|
Includes McMoRan’s share of insurance reimbursements related to losses incurred from
the September 2008 hurricanes totaling $12.9 million in second-quarter 2011, $29.4 million in
the first six months of 2011 and $9.2 million in the second- quarter and the first six months
of 2010. |
| |
| e. |
|
Includes reclamation spending of $20.0 million in second-quarter 2011, $24.1 million
in second-quarter 2010, $42.2 million in the first six months of 2011 and $41.6 million in the
first six months of 2010. Also includes working capital sources (uses) of $28.4 million in
second-quarter 2011, $(10.9) million in second quarter 2010, $5.7 million in the first six
months of 2011 and $20.3 million in the first six months of 2010. |
| |
| f. |
|
See reconciliation of EBITDAX to net loss applicable to common stock on page II. |
2
PRODUCTION AND DEVELOPMENT ACTIVITIES
Second-quarter 2011 production averaged 197 MMcfe/d net to McMoRan, compared with 165
MMcfe/d in the second quarter of 2010. Production in the second quarter of 2011 was higher
than McMoRan’s previously reported estimates of 190 MMcfe/d in April 2011 because of favorable
production performance. Production is expected to average approximately 180 MMcfe/d in the
third quarter of 2011 and 185 MMcfe/d for the year, higher than the previous 2011 annual
estimate of 175 MMcfe/d. McMoRan’s estimated production rates are dependent on the timing of
planned recompletions, production performance, weather and other factors.
Production from the Flatrock field averaged a gross rate of approximately 172 MMcfe/d (70
MMcfe/d net to McMoRan) in the second quarter of 2011. McMoRan owns a 55.0 percent working
interest and a 41.3 percent net revenue interest in the Flatrock field.
As previously reported, McMoRan successfully commenced production from the Laphroaig No. 2
well in St. Mary Parish, Louisiana in late April 2011. Production from the Laphroaig No. 2
well averaged a gross rate of approximately 50 MMcfe/d (15 MMcfe/d net to McMoRan) in May and
June of 2011. McMoRan owns a 38.4 percent working interest and a 29.5 percent net revenue
interest in the Laphroaig No. 2 well. Energy XXI (NASDAQ: EXXI) holds an 18.8 percent working
interest.
As previously reported, the Brazos A-23 development well commenced drilling on February
13, 2011, and was drilled to a total depth of 15,946 feet. This traditional Shelf well
targeted proved undeveloped reserves updip from logged pay zones. Log evaluation indicated
that the well encountered 30 net feet of hydrocarbon bearing sands and a protective liner has
been set. The well has been temporarily abandoned while future plans are developed. McMoRan
owns a 100.0 percent working interest and an 81.25 percent net revenue interest in the well.
McMoRan recorded a $23.8 million impairment charge in the second quarter to reduce the carrying
value of the Brazos A-23 well to $17.4 million.
EXPLORATION ACTIVITIES
McMoRan’s exploration strategy is focused in the shallow waters of the Gulf of Mexico
(GOM) and Gulf Coast area on the “ultra-deep gas play” and on the “deep gas play.”
Shallow Water, Ultra-Deep Exploration Update
Since 2008, McMoRan has actively pursued large ultra-deep targets located in the shallow
waters of the GOM below the salt weld (i.e. listric fault) at depths generally below 25,000
feet. The data gained to date from four wells confirm McMoRan’s geologic model and the highly
prospective nature of this emerging geologic trend. Prior to McMoRan’s involvement in the
ultra-deep, there had been only two wells drilled on the Shelf targeting these objectives; one
did not reach its targeted depth and the other was outside McMoRan’s focus area. McMoRan’s
results to date have indicated the potential for large accumulations of hydrocarbons at these
deeper depths in the shallow waters of the GOM.
McMoRan’s activities to date have confirmed that drilling below the salt weld on the Shelf
of the GOM can be achieved safely. In addition, the data indicate the presence below the salt
weld of geologic formations including Middle/Lower Miocene, Wilcox, Frio, Tuscaloosa and
Cretaceous carbonate. These formations have been prolific onshore, in the deepwater GOM and in
international locations. McMoRan is encouraged by the results which indicate the potential for
prospects with high quality reservoirs on large structures with multi-Tcfe of gross unrisked
potential. McMoRan intends to conduct further drilling and flow testing to determine the
ultimate potential of this emerging geologic trend.
The Davy Jones offset appraisal well (Davy Jones No. 2), located on South Marsh Island
Block 234 two and a half miles southwest of the Davy Jones No. 1 discovery well, was drilled to
a total depth of 30,546 feet. Log results above 27,300 feet confirmed 120 net feet of
hydrocarbon bearing Wilcox sands, indicating continuity across the major structural features of
the Davy Jones prospect.
3
In June 2011, results from wireline logs of the Cretaceous section below 27,300 feet
indicated that the Davy Jones No. 2 well encountered 192 net feet of potential hydrocarbons in
the Tuscaloosa and Lower Cretaceous carbonate sections. Flow testing will be required to
confirm the potential hydrocarbons and flow rates. A 6 5/8 inch production liner has been set
to 30,511 feet and the well has been temporarily abandoned. McMoRan is evaluating development
options and expects to commence completion of the No. 2 well for flow testing in the second
quarter of 2012. McMoRan is also considering updip locations in a subsequent well to the north
to evaluate the Tuscaloosa sands and Lower Cretaceous carbonates higher on the Davy Jones
structure.
The Tuscaloosa sands are correlative with the prolific Tuscaloosa trend onshore South
Louisiana and the carbonate section may be analogous to productive fields located offshore and
onshore Mexico in the southern GOM. These potential hydrocarbon bearing zones are the first
Cretaceous sandstones and limestones encountered offshore Central Louisiana on the GOM Shelf.
McMoRan believes the combination of productive Wilcox and Cretaceous intervals on the same
structure could enhance the value of Davy Jones and the prospectivity of McMoRan’s other
ultra-deep prospects on its acreage position within the Davy Jones trend.
As previously reported, in January 2010 McMoRan logged 200 net feet of pay in multiple
Wilcox sands in the Davy Jones No. 1 well on South Marsh Island Block 230. In March 2010, a
production liner was set and the well was temporarily abandoned to prepare for completion.
McMoRan is preparing to complete and flow test the No. 1 well in late 2011.
Davy Jones involves a large ultra-deep structure encompassing four OCS lease blocks
(20,000 acres). McMoRan holds a 60.4 percent working interest and a 47.9 percent net revenue
interest in Davy Jones. Other working interest owners in Davy Jones include: Energy XXI
(NASDAQ: EXXI) (15.8%), JX Nippon Oil Exploration (U.S.A.) Limited (12%), Moncrief Offshore LLC
(8.8%) and a private investor (3%). McMoRan’s total investment in Davy Jones, a substantial
majority of which is associated with allocated costs associated with the PXP property
acquisition, totaled $619.4 million at June 30, 2011.
In July 2011, McMoRan commenced operations to drill a by-pass of the Blackbeard East
ultra-deep exploration well at approximately 30,700 feet to evaluate targets in the Eocene.
The well is permitted to 34,000 feet. Based on interpretations of drilling data obtained in
the first quarter of 2011 prior to the mechanical issue, McMoRan believes the well encountered
Sparta sands in the Eocene, which are younger than the Wilcox. Sparta sands are productive
onshore in South Louisiana. Wireline logs will be required to evaluate this interval.
As reported in January 2011, wireline logs indicated that Blackbeard East encountered
hydrocarbon bearing sands in the Oligocene (Frio) with good porosity below 30,000 feet.
McMoRan is considering down dip drilling opportunities on the flanks of the structure to
evaluate this section further. This is the first hydrocarbon bearing Frio sand encountered
either on the GOM Shelf or in the deepwater offshore Louisiana. The Frio sand section below
30,000 feet is in addition to the 178 net feet of hydrocarbons in the Miocene sands above
25,000 feet announced in December 2010 at Blackbeard East. Pressure and temperature data below
the salt weld between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion
at these depths could utilize conventional equipment and technologies.
Blackbeard East is located in 80 feet of water on South Timbalier Block 144. McMoRan
holds a 70.0 percent working interest and a 56.2 percent net revenue interest in the well.
Other working interest owners in Blackbeard East include: EXXI (18.0%), Moncrief Offshore LLC
(10.0%) and a private investor (2.0%). McMoRan’s total investment in Blackbeard East, which
includes allocated costs associated with the PXP property acquisition, totaled $216.1 million
at June 30, 2011.
The Lafitte ultra-deep exploration well commenced drilling on October 3, 2010 and is
currently drilling below 24,200 feet towards a proposed total depth of 29,950 feet. Lafitte is
located on Eugene Island Block 223 in 140 feet of water. The well is targeting Miocene
objectives and possibly Oligocene (Frio) sections below the salt weld. McMoRan holds a 72.0
percent working interest and 58.3 percent net
4
revenue interest in Lafitte. Other working interest owners in Lafitte include: EXXI
(18.0%), and Moncrief Offshore LLC (10.0%). McMoRan’s total investment in Lafitte, which
includes allocated costs associated with the PXP property acquisition, totaled $100.2 million
at June 30, 2011.
Information gained from the Blackbeard East and Lafitte wells is expected to assist
McMoRan in developing plans for future operations at Blackbeard West. As previously reported,
the Blackbeard West ultra-deep exploratory well on South Timbalier Block 168 was drilled to
32,997 feet in 2008. Logs indicated four potential hydrocarbon bearing zones that require
further evaluation and the well was temporarily abandoned. McMoRan is evaluating whether to
drill deeper at Blackbeard West, drill an offset location or complete the well to test the
existing zones.
McMoRan has also identified a new location within the Blackbeard West unit on Ship Shoal
Block 188 to evaluate the Miocene age sands seen in Blackbeard East above 25,000 feet. McMoRan
is developing plans to commence drilling this ultra-deep well, which has a proposed total depth
of 26,000 feet, in the second half of 2011. The Ship Shoal Block 188 location is approximately
4 miles west of the Blackbeard West #1 well on South Timbalier Block 168. McMoRan holds a 67.3
percent working interest and 51.5 percent net revenue interest in the Blackbeard West well on
Ship Shoal Block 188. McMoRan’s total investment in Blackbeard West, which includes allocated
costs associated with the PXP property acquisition, totaled $58.9 million at June 30, 2011.
Shallow Water, Deep Gas Exploration Update
In addition to the ultra-deep play on the Shelf of the GOM, McMoRan’s exploration strategy
is also focused on the “deep gas play.” Deep gas prospects target large Miocene age deposits
above the salt weld (i.e. listric fault) at depths typically between 15,000 to 25,000 feet.
The Boudin deep gas exploration well commenced drilling on February 27, 2011 and is
drilling below 19,350 feet. Boudin, which is located in 20 feet of water on Eugene Island
Block 26, has a proposed total depth of 23,100 feet and will test Miocene objectives. McMoRan
holds a 53.5 percent working interest and a 42.4 percent net revenue interest in Boudin. EXXI
holds a 20.6 percent working interest. McMoRan’s total investment in Boudin, which includes
allocated costs associated with the PXP property acquisition, totaled $49.1 million at June 30,
2011.
The Hurricane Deep well, which is located in 12 feet of water on South Marsh Island Block
217, was drilled to a true vertical depth of 21,378 feet in July 2011. Log results indicated
the presence of Operc and Gyro sands that McMoRan determined could be pursued in an updip
location. The well is being temporarily abandoned to preserve the wellbore and McMoRan is
evaluating opportunities to sidetrack or deepen. McMoRan’s total investment in Hurricane Deep,
which includes allocated costs associated with the PXP property acquisition, totaled $54.5
million at June 30, 2011. McMoRan’s investment is expected to be reduced by approximately $11
million for reimbursable costs associated with its insurance programs.
Second-quarter 2011 exploration expense includes $36.8 million in costs for the previously
reported noncommercial well at Blueberry Hill.
REVENUES
McMoRan’s second-quarter 2011 oil and gas revenues totaled $155.5 million, compared to
$104.1 million during the second quarter of 2010. During the second quarter of 2011, McMoRan’s
sales volumes totaled 11.6 Bcf of gas, 778,400 barrels of oil and condensate and 1.6 Bcfe of
plant products, compared to 9.8 Bcf of gas, 626,400 barrels of oil and condensate and 1.4 Bcfe
of plant products in the second quarter of 2010. McMoRan’s second-quarter comparable average
realizations for gas were $4.71 per thousand cubic feet (Mcf) in 2011 and $4.66 per Mcf in
2010; for oil and condensate McMoRan received an average of $109.08 per barrel in
second-quarter 2011 compared to $76.20 per barrel in second-quarter 2010.
5
CASH, LIQUIDITY AND CAPITAL EXPENDITURES
At June 30, 2011, McMoRan had $765.3 million in cash. Total debt was $561.0 million at
June 30, 2011, including $74.7 million in Convertible Senior Notes due in October 2011 with a
conversion price of $16.575 per share and $186.3 million in Convertible Senior Notes due in
December 2017 with a conversion price of $16.00 per share. On June 30, 2011, McMoRan entered
into a new five-year, $150 million senior secured revolving credit facility, which replaced the
revolving credit facility that was scheduled to mature in August 2012. McMoRan had no
borrowings and $100 million of letters of credit issued under its revolving credit facility
resulting in total availability of $50 million at June 30, 2011.
Capital expenditures totaled $162.4 million for the second quarter of 2011 and $258.9
million for the six-months ended June 30, 2011. McMoRan expects 2011 capital expenditures to
approximate $500 million, including $300 million for exploration and $200 million for
development. Capital spending will continue to be driven by opportunities, drilling results
and follow-on development activities.
Net abandonment expenditures, which include scheduled conventional and hurricane-related
work, totaled $20.0 million for the second quarter of 2011 and $42.2 million for the six-months
ended June 30, 2011. Abandonment expenditures are expected to approximate $160 million in
2011.
In the second quarter of 2011, McMoRan recorded $12.9 million in gains for reimbursable
costs associated with its insurance programs. Since 2009, McMoRan has recorded $92.9 million
in gains associated with the 2008 hurricane events in the GOM and continues to pursue
reimbursement of certain hurricane-related abandonment costs under its insurance programs.
WEBCAST INFORMATION
A conference call with securities analysts to discuss McMoRan’s second-quarter 2011
results is scheduled for today at 10:00 a.m. Eastern Time. The conference call will be
broadcast on the internet along with slides. Interested parties may listen to the conference
call live and view the slides by accessing “www.mcmoran.com”. A replay of the webcast will be
available through Friday, August 12, 2011.
McMoRan Exploration Co. is an independent public company engaged in the exploration,
development and production of natural gas and oil in the shallow waters of the GOM Shelf and
onshore in the Gulf Coast area. Additional information about McMoRan is available on its
internet website “www.mcmoran.com”.
CAUTIONARY STATEMENT: This press release contains forward-looking statements that
involve a number of assumptions, risks and uncertainties that could cause actual results to
differ materially from those contained in the forward-looking statements. We caution readers
that those statements are not guarantees of future performance or exploration and development
success, and our actual exploration experience and future financial results may differ
materially from those anticipated, projected or assumed in the forward-looking statements. Such
forward-looking statements include, but are not limited to, statements regarding various oil
and gas discoveries, oil and gas exploration, development and production activities, capital
expenditures, reclamation costs, anticipated and potential production and flow rates, and other
statements that are not historical facts. No assurance can be given that any of the events
anticipated by the forward-looking statements will transpire or occur, or if any of them do so,
what impact they may have on our results of operations or financial condition. Important
factors that can cause actual results to differ materially from the results anticipated by
forward-looking statements include, but are not limited to, those associated with general
economic and business conditions, failure to realize expected value creation from acquired
properties, variations in the market demand for, and prices of, oil and natural gas, drilling
results, unanticipated fluctuations in flow rates of producing wells due to mechanical or
operational issues (including those experienced at wells operated by third parties where we are
a participant), changes in oil and natural gas reserve expectations, the potential adoption of
new governmental regulations, failure of third party partners to fulfill their capital and
other commitments, the ability to satisfy future cash obligations and environmental costs,
adverse conditions, such as high temperatures and pressure that could lead to mechanical
failures or increased costs, the ability to retain current or future lease acreage rights, the
ability to satisfy future cash obligations and environmental costs, access to capital to fund
drilling activities, as well as other general exploration and development risks and hazards,
and other factors described in more detail in Part I, Item 1A. “Risk Factors” included in our
Annual Report on Form 10-K for the year ended December 31, 2010 filed with the SEC.
6
Investors are cautioned that many of the assumptions upon which our forward-looking
statements are based are likely to change after our forward-looking statements are made,
including for example the market prices of oil and natural gas,
which we cannot control, and production volumes and costs, some aspects of which we may or
may not be able to control. Further, we may make changes to our business plans that could or
will affect our results. We caution investors that we do not intend to update our
forward-looking statements, notwithstanding any changes in our assumptions, changes in our
business plans, our actual experience, or other changes, and we undertake no obligation to
update any forward-looking statements.
This press release contains a financial measure, earnings before interest, taxes,
depreciation, amortization and exploration expenses (EBITDAX), commonly used in the oil and
natural gas industry but not recognized under GAAP. As required by SEC Regulation G,
reconciliations of this measure to amounts reported in McMoRan’s consolidated financial
statements are included in the supplemental schedules of this press release.
The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved
reserves that a company has demonstrated by actual production or conclusive formation tests to
be economically and legally producible under existing economic and operating conditions.
Beginning with year-end reserves for 2009, the SEC permits oil and gas companies, in their
filings with the SEC, to disclose probable and possible reserves, as such terms are defined by
the SEC. We use certain phrases and terms in this press release, such as “gross unrisked
potential” and “resource potential” which the SEC’s guidelines prohibit us from including in
filings with the SEC “Gross unrisked potential” and “resource potential” do not take into
account the certainty of resource recovery, which is contingent on exploration success,
technical improvements in drilling access, commerciality and other factors, and are therefore
not indicative of expected future resource recovery and should not be relied upon. We urge you
to consider closely the disclosure of proved reserves included in our Annual Report on Form
10-K for the year ended December 31, 2010 filed with the SEC.
# # #
7
McMoRan EXPLORATION CO.
STATEMENTS OF OPERATIONS (Unaudited)
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Three Months Ended |
|
|
Six Months Ended |
|
| |
|
June 30, |
|
|
June 30, |
|
| |
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
| |
|
(In Thousands, Except Per Share Amounts) |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas |
|
$ |
155,469 |
|
|
$ |
104,103 |
|
|
$ |
289,181 |
|
|
$ |
232,949 |
|
Service |
|
|
2,839 |
|
|
|
3,938 |
|
|
|
6,131 |
|
|
|
7,580 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
158,308 |
|
|
|
108,041 |
|
|
|
295,312 |
|
|
|
240,529 |
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and delivery costs |
|
|
51,911 |
|
|
|
46,439 |
|
|
|
99,868 |
|
|
|
89,224 |
|
Depletion, depreciation and amortization expensea |
|
|
95,338 |
|
|
|
57,887 |
|
|
|
182,008 |
|
|
|
166,132 |
|
Exploration expensesb |
|
|
47,896 |
|
|
|
10,434 |
|
|
|
60,674 |
|
|
|
22,843 |
|
(Gain) loss on oil and gas derivative contracts |
|
|
— |
|
|
|
477 |
|
|
|
— |
|
|
|
(3,268 |
) |
General and administrative expenses |
|
|
11,223 |
|
|
|
10,376 |
|
|
|
27,175 |
|
|
|
24,119 |
|
Main Pass Energy Hub™ costs |
|
|
278 |
|
|
|
242 |
|
|
|
513 |
|
|
|
575 |
|
Insurance recoveriesc |
|
|
(12,946 |
) |
|
|
(9,171 |
) |
|
|
(29,369 |
) |
|
|
(9,171 |
) |
Gain on sale of oil and gas property |
|
|
— |
|
|
|
(3,455 |
) |
|
|
(900 |
) |
|
|
(3,455 |
) |
Total costs and expenses |
|
|
193,700 |
|
|
|
113,229 |
|
|
|
339,969 |
|
|
|
286,999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating loss |
|
|
(35,392 |
) |
|
|
(5,188 |
) |
|
|
(44,657 |
) |
|
|
(46,470 |
) |
Interest expense, net |
|
|
(2,704 |
) |
|
|
(9,873 |
) |
|
|
(8,153 |
) |
|
|
(20,406 |
) |
Other income, net |
|
|
230 |
|
|
|
44 |
|
|
|
410 |
|
|
|
105 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations before income taxes |
|
|
(37,866 |
) |
|
|
(15,017 |
) |
|
|
(52,400 |
) |
|
|
(66,771 |
) |
Income tax expense |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations |
|
|
(37,866 |
) |
|
|
(15,017 |
) |
|
|
(52,400 |
) |
|
|
(66,771 |
) |
Loss from discontinued operations |
|
|
(1,989 |
) |
|
|
(1,436 |
) |
|
|
(3,233 |
) |
|
|
(3,076 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
(39,855 |
) |
|
|
(16,453 |
) |
|
|
(55,633 |
) |
|
|
(69,847 |
) |
Preferred dividends and inducement payments for
early conversion of convertible preferred stock |
|
|
(10,343 |
) |
|
|
(5,293 |
)d |
|
|
(22,115 |
)d |
|
|
(18,059 |
)d |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss applicable to common stock |
|
$ |
(50,198 |
) |
|
$ |
(21,746 |
) |
|
$ |
(77,748 |
) |
|
$ |
(87,906 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net loss per share of common stock: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations |
|
$ |
(0.31 |
) |
|
$ |
(0.22 |
) |
|
$ |
(0.47 |
) |
|
$ |
(0.93 |
) |
Discontinued operations |
|
|
(0.01 |
) |
|
|
(0.01 |
) |
|
|
(0.02 |
) |
|
|
(0.03 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per share of common stock |
|
$ |
(0.32 |
) |
|
$ |
(0.23 |
) |
|
$ |
(0.49 |
) |
|
$ |
(0.96 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted |
|
|
158,454 |
|
|
|
93,101 |
|
|
|
158,154 |
|
|
|
91,428 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| a. |
|
Includes impairment charges totaling $29.2 million and $50.7 million in the second
quarter and six months ended June 30, 2011, respectively, and $13.7 million and $70.7 million
in the second quarter and six months ended June 30, 2010, respectively. Also includes
reclamation accrual adjustments totaling approximately $20.4 million and $35.1 million for
asset retirement obligations associated with certain oil and gas properties in the second
quarter and six months ended June 30, 2011, respectively. Approximately $18.7 million of these
reclamation charges are reimbursable under McMoRan’s insurance policies when the related
reclamation expenditures are incurred. |
| |
| b. |
|
Includes charges for non-productive well costs of $36.8 million and $38.9 million in
the second quarter and six months ended June 30, 2011, respectively, and $2.9 million and $7.5
million in the second quarter and six months ended June 30, 2010, respectively. |
| |
| c. |
|
Represents McMoRan’s share of insurance reimbursements related to losses incurred from
the September 2008 hurricanes. |
| |
| d. |
|
Includes payments of $1.5 million to induce the conversion of approximately 8,100
shares of McMoRan’s 8% convertible perpetual preferred stock (8% preferred stock) into
approximately 1.2 million shares of its common stock in the six months ended June 30, 2011.
Includes payments of $1.9 million to induce the conversion of approximately 9,600 shares of
McMoRan’s 8% preferred stock into approximately 1.4 million shares of its common stock in the
second quarter ended June 30, 2010 and $10.8 million of payments to induce conversion of
approximately 57,200 shares of 8% preferred stock into approximately 8.4 million shares of
common stock in the six months ended June 30, 2010. |
I
McMoRan EXPLORATION CO.
RECONCILATION OF REPORTED AMOUNTS TO NON-GAAP ITEMS (Unaudited)
EBITDAX is a financial measure commonly used in the oil and natural gas industry but is not a
recognized accounting term under accounting principles generally accepted in the United States of
America (GAAP). As defined by McMoRan, EBITDAX reflects the company’s adjusted oil and gas
operating income (loss). EBITDAX is derived from net loss from continuing operations before other
income, net; interest expense, net; income tax expense; Main Pass Energy HubTM costs;
exploration expenses; depletion, depreciation and amortization expense; hurricane repair charges
included in production and delivery costs; stock-based compensation charged to general and
administrative expenses; insurance recoveries; gain on sale of oil and gas property; and change in
fair value of oil and gas derivative contracts. EBITDAX should not be considered by itself or as a
substitute for net income (loss), operating income (loss), cash flows from operating activities or
any other measure of financial performance presented in accordance with GAAP, or as a measure of
McMoRan’s profitability or liquidity. Because EBITDAX excludes some, but not all, items that
affect net income (loss), the computation of this non-GAAP financial measure may be different from
similar presentations of other companies, including oil and gas companies in our industry. As a
result, the EBITDAX data presented below may not be comparable to similarly titled measures of
other companies.
McMoRan’s management utilizes both the GAAP and non-GAAP results presented in this news release to
evaluate McMoRan’s performance and believes that comparative analysis of results are useful to
investors and other internal and external users of our financial statements in evaluating our
operating performance, and such analysis can be enhanced by excluding the impact of these items to
help investors meaningfully compare our results from period to period. The following is a
reconciliation of reported amounts from net loss applicable to common stock to EBITDAX (in
thousands):
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Second Quarter |
|
|
Six Months |
|
| |
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Net loss applicable to common stock, as reported |
|
$ |
(50,198 |
) |
|
$ |
(21,746 |
) |
|
$ |
(77,748 |
) |
|
$ |
(87,906 |
) |
Preferred dividends and inducement payments for early
conversion of convertible preferred stock |
|
|
10,343 |
|
|
|
5,293 |
|
|
|
22,115 |
|
|
|
18,059 |
|
Loss from discontinued operations |
|
|
1,989 |
|
|
|
1,436 |
|
|
|
3,233 |
|
|
|
3,076 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations, as reported |
|
|
(37,866 |
) |
|
|
(15,017 |
) |
|
|
(52,400 |
) |
|
|
(66,771 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income, net |
|
|
(230 |
) |
|
|
(44 |
) |
|
|
(410 |
) |
|
|
(105 |
) |
Interest expense, net |
|
|
2,704 |
|
|
|
9,873 |
|
|
|
8,153 |
|
|
|
20,406 |
|
Income tax expense |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Main Pass Energy HubTM costs |
|
|
278 |
|
|
|
242 |
|
|
|
513 |
|
|
|
575 |
|
Exploration expenses |
|
|
47,896 |
|
|
|
10,434 |
|
|
|
60,674 |
|
|
|
22,843 |
|
Depletion, depreciation and amortization expense |
|
|
95,338 |
|
|
|
57,887 |
|
|
|
182,008 |
|
|
|
166,132 |
|
Hurricane repair charges included in production and
delivery costs |
|
|
27 |
|
|
|
2,115 |
|
|
|
70 |
|
|
|
2,652 |
|
Stock-based compensation charged to general and
administrative expenses |
|
|
1,639 |
|
|
|
1,594 |
|
|
|
6,872 |
|
|
|
6,524 |
|
Insurance recoveries |
|
|
(12,946 |
) |
|
|
(9,171 |
) |
|
|
(29,369 |
) |
|
|
(9,171 |
) |
Gain on sale of oil and gas property |
|
|
— |
|
|
|
(3,455 |
) |
|
|
(900 |
) |
|
|
(3,455 |
) |
Change in fair value of oil and gas derivative contracts |
|
|
— |
|
|
|
4,552 |
|
|
|
— |
|
|
|
4,110 |
|
Other |
|
|
99 |
|
|
|
— |
|
|
|
379 |
|
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX |
|
$ |
96,939 |
|
|
$ |
59,010 |
|
|
$ |
175,590 |
|
|
$ |
143,740 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
II
McMoRan EXPLORATION CO.
OPERATING DATA (Unaudited)
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Second Quarter |
|
|
Six Months |
|
| |
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Sales volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (thousand cubic feet, or Mcf) |
|
|
11,600,800 |
|
|
|
9,802,800 |
|
|
|
23,270,300 |
|
|
|
21,041,600 |
|
Oil (barrels) |
|
|
778,400 |
|
|
|
626,400 |
|
|
|
1,465,100 |
|
|
|
1,317,900 |
|
Plant products (per Mcf equivalent)a |
|
|
1,642,800 |
|
|
|
1,447,600 |
|
|
|
3,381,300 |
|
|
|
3,196,600 |
|
Average realizations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (per Mcf) |
|
$ |
4.71 |
|
|
$ |
4.66 |
|
|
$ |
4.62 |
|
|
$ |
5.12 |
|
Oil (per barrel) |
|
|
109.08 |
|
|
|
76.20 |
|
|
|
103.31 |
|
|
|
76.28 |
|
|
|
|
| a. |
|
Results include approximately $15.8 million and $29.8 million of revenues associated with
plant products (ethane, propane, butane, etc.) during the second quarter and six months ended
June 30, 2011, respectively. Plant product revenues for the comparable prior year periods
totaled $10.6 million and $24.5 million. One Mcf equivalent is determined using an estimated
energy content differential ratio of six Mcf of natural gas to one barrel of crude oil,
condensate or natural gas liquids. |
III
McMoRan EXPLORATION CO.
CONDENSED BALANCE SHEETS (Unaudited)
| |
|
|
|
|
|
|
|
|
| |
|
June 30, |
|
|
December 31, |
|
| |
|
2011 |
|
|
2010 |
|
| |
|
(In Thousands) |
|
ASSETS |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
765,320 |
|
|
$ |
905,684 |
|
Accounts receivable |
|
|
100,317 |
|
|
|
86,516 |
|
Inventories |
|
|
32,023 |
|
|
|
38,461 |
|
Prepaid expenses |
|
|
5,793 |
|
|
|
15,478 |
|
Current assets from discontinued operations, including restricted cash
of $473 |
|
|
1,367 |
|
|
|
702 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
904,820 |
|
|
|
1,046,841 |
|
Property, plant and equipment, net |
|
|
1,915,443 |
|
|
|
1,785,607 |
|
Restricted cash |
|
|
56,483 |
|
|
|
53,975 |
|
Deferred financing costs and other assets |
|
|
9,399 |
|
|
|
9,952 |
|
Long-term assets from discontinued operations |
|
|
2,989 |
|
|
|
2,989 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
2,889,134 |
|
|
$ |
2,899,364 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
108,035 |
|
|
$ |
102,658 |
|
Accrued liabilities |
|
|
162,753 |
|
|
|
99,363 |
|
Accrued interest and dividends payable |
|
|
14,798 |
|
|
|
6,768 |
|
Current portion of accrued oil and gas reclamation costs |
|
|
153,636 |
|
|
|
120,970 |
|
5 1/4% convertible senior notes |
|
|
74,720 |
|
|
|
74,720 |
|
Current portion of accrued sulphur reclamation costs (discontinued operations) |
|
|
8,681 |
|
|
|
11,772 |
|
Current liabilities from discontinued operations |
|
|
1,652 |
|
|
|
1,993 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
524,275 |
|
|
|
418,244 |
|
11.875% senior notes |
|
|
300,000 |
|
|
|
300,000 |
|
4% convertible senior notes |
|
|
186,309 |
|
|
|
185,256 |
|
Accrued oil and gas reclamation costs |
|
|
183,736 |
|
|
|
237,654 |
|
Other long-term liabilities |
|
|
15,963 |
|
|
|
16,596 |
|
Accrued sulphur reclamation costs (discontinued operations) |
|
|
14,020 |
|
|
|
13,494 |
|
Other long-term liabilities from discontinued operations |
|
|
4,301 |
|
|
|
3,783 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
1,228,604 |
|
|
|
1,175,027 |
|
|
|
|
|
|
|
|
Stockholders’ equity |
|
|
1,660,530 |
|
|
|
1,724,337 |
|
|
|
|
|
|
|
|
Total liabilities and stockholders’ equity |
|
$ |
2,889,134 |
|
|
$ |
2,899,364 |
|
|
|
|
|
|
|
|
IV
McMoRan EXPLORATION CO.
STATEMENTS OF CASH FLOWS (Unaudited)
| |
|
|
|
|
|
|
|
|
| |
|
Six Months Ended |
|
| |
|
June 30, |
|
| |
|
2011 |
|
|
2010 |
|
| |
|
(In Thousands) |
|
Cash flow from operating activities: |
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(55,633 |
) |
|
$ |
(69,847 |
) |
Adjustments to reconcile net loss to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
Loss from discontinued operations |
|
|
3,233 |
|
|
|
3,076 |
|
Depletion, depreciation and amortization expense |
|
|
182,008 |
|
|
|
166,132 |
|
Exploration drilling and related expenditures |
|
|
38,886 |
|
|
|
7,471 |
|
Compensation expense associated with stock-based awards |
|
|
12,814 |
|
|
|
12,657 |
|
Amortization of deferred financing costs |
|
|
3,030 |
|
|
|
1,862 |
|
Change in fair value of oil and gas derivative contracts |
|
|
— |
|
|
|
4,110 |
|
Reclamation expenditures, net of prepayments by third parties |
|
|
(42,235 |
) |
|
|
(41,632 |
) |
Increase in restricted cash |
|
|
(2,508 |
) |
|
|
(7,506 |
) |
Gain on sale of oil and gas property |
|
|
(900 |
) |
|
|
(3,455 |
) |
Other |
|
|
(313 |
) |
|
|
556 |
|
(Increase) decrease in working capital: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(42,594 |
) |
|
|
(7,588 |
) |
Accounts payable and accrued liabilities |
|
|
30,600 |
|
|
|
11,086 |
|
Prepaid expenses, inventories and other |
|
|
17,675 |
|
|
|
16,775 |
|
|
|
|
|
|
|
|
Net cash provided by continuing operations |
|
|
144,063 |
|
|
|
93,697 |
|
Net cash used in discontinued operations |
|
|
(7,923 |
) |
|
|
(2,164 |
) |
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
136,140 |
|
|
|
91,533 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from investing activities: |
|
|
|
|
|
|
|
|
Exploration, development and other capital expenditures |
|
|
(258,894 |
) |
|
|
(101,436 |
) |
Proceeds from sale of oil and gas property |
|
|
900 |
|
|
|
2,920 |
|
|
|
|
|
|
|
|
Net cash used in continuing operations |
|
|
(257,994 |
) |
|
|
(98,516 |
) |
Net cash activity from discontinued operations |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(257,994 |
) |
|
|
(98,516 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from financing activities: |
|
|
|
|
|
|
|
|
Dividends paid and inducement payments on early conversion
of convertible preferred stock |
|
|
(17,267 |
) |
|
|
(17,589 |
) |
Credit facility refinancing fees |
|
|
(1,609 |
) |
|
|
— |
|
Debt and equity issuance costs |
|
|
(543 |
) |
|
|
— |
|
Proceeds from exercise of stock options and other |
|
|
909 |
|
|
|
182 |
|
|
|
|
|
|
|
|
Net cash used in continuing operations |
|
|
(18,510 |
) |
|
|
(17,407 |
) |
Net cash activity from discontinued operations |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(18,510 |
) |
|
|
(17,407 |
) |
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
|
(140,364 |
) |
|
|
(24,390 |
) |
Cash and cash equivalents at beginning of year |
|
|
905,684 |
|
|
|
241,418 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
765,320 |
|
|
$ |
217,028 |
|
|
|
|
|
|
|
|
V
