Net Income Available to Common Shareholders Reaches $604 Million on Revenue
of $1.94 Billion and Production of 137 Bcfe
Company Expects Total Production Growth of 24% in 2006 and 7-10% in 2007;
Proved Reserves Reach Record Level of 7.8 Tcfe
Company Increases Hedges at Very Attractive Prices; Has Now Hedged 80%, 56%
and 41% of Expected Full-Year 2006, 2007 and 2008 Oil and Natural Gas
Production at Average NYMEX Prices of $9.45, $9.98 and $9.36 Per Mcfe
OKLAHOMA CITY, May 1 /PRNewswire-FirstCall/ -- Chesapeake Energy
Corporation (NYSE: CHK) today reported financial and operating results for
the first quarter of 2006. For the quarter, Chesapeake generated net income
available to common shareholders of $604 million ($1.44 per fully diluted
common share), operating cash flow of $1.047 billion (defined as cash flow
from operating activities before changes in assets and liabilities) and
ebitda of $1.407 billion (defined as income before income taxes, interest
expense, and depreciation, depletion and amortization expense) on revenue
of $1.945 billion and production of 137 billion cubic feet of natural gas
equivalent (bcfe).
The company's 2006 first quarter net income available to common
shareholders and ebitda include various items that are typically not
included in published estimates of the company's financial results by
certain securities analysts. Such items and their after-tax effects on 2006
first quarter reported results are described as follows:
* an unrealized mark-to-market gain of $122 million resulting from the
company's oil and natural gas and interest rate hedging programs;
* a realized gain of $73 million resulting from the sale of the
company's investment in the common stock of Pioneer Drilling
Corporation (Amex: PDC);
* a charge of $34 million relating to the acceleration of vesting of
stock options and restricted stock in connection with the retirement
in February 2006 of Chesapeake's President and Chief Operating
Officer, Tom L. Ward; and
* a reduction of net income available to common shareholders of $1
million resulting from issuances of common stock upon various
exchanges and conversions of preferred stock.
Excluding the above-mentioned items and giving effect to common shares
issued for preferred shares during the period, Chesapeake's net income to
common shareholders in the first quarter of 2006 would have been $444
million ($1.07 per fully diluted common share) and ebitda would have been
$1.147 billion. The foregoing items do not affect the calculation of
operating cash flow. A reconciliation of operating cash flow, ebitda,
adjusted ebitda and adjusted net income to comparable financial measures
calculated in accordance with generally accepted accounting principles is
presented on pages 15-16 of this release.
Oil and Natural Gas Production Sets Record for 19th Consecutive Quarter;
2006 First Quarter Average Daily Production Increases 31% and 7% Over
Production in the 2005 First Quarter and 2005 Fourth Quarter, Respectively
Daily production for the 2006 first quarter averaged 1.519 bcfe, an
increase of 357 million cubic feet of natural gas equivalent (mmcfe), or
31%, over the 1.162 bcfe of daily production in the 2005 first quarter and
an increase of 101 mmcfe, or 7%, over the 1.418 bcfe produced per day in
the 2005 fourth quarter. Of the 357 mmcfe increase in daily production from
the year ago quarter, 42% was generated from organic drillbit growth and
58% was generated from acquisitions, with the company's trailing 12-month
organic production growth rate calculated as 13%. Of the 101 mmcfe daily
increase in sequential quarterly production, 22% was generated from organic
drillbit growth and 78% was generated from acquisitions, with the company's
sequential quarterly organic production growth rate calculated as 1.7%.
Chesapeake is anticipating total production growth of 24% in 2006 and
organic growth rates of at least 10% in 2006 and 7-10% in 2007.
Chesapeake's 2006 first quarter production of 136.8 bcfe was comprised
of 124.1 billion cubic feet of natural gas (bcf) (91% on a natural gas
equivalent basis) and 2.12 million barrels of oil and natural gas liquids
(mmbbls) (9% on a natural gas equivalent basis). Chesapeake's average daily
production for the quarter of 1.519 bcfe consisted of 1.378 bcf of natural
gas and 23,511 barrels (bbls) of oil. The 2006 first quarter was
Chesapeake's 19th consecutive quarter of sequential U.S. production growth.
Over these 19 quarters, Chesapeake's U.S. production increased 280%, for an
average compound quarterly growth rate of 7.3% and an average compound
annual growth rate of 32.2%.
Average Prices Realized, Hedging Results and Hedging Positions Detailed
Average prices realized during the 2006 first quarter (including
realized gains or losses from oil and natural gas derivatives, but
excluding unrealized gains or losses on such derivatives) were $57.12 per
bbl and $9.61 per thousand cubic feet (mcf), for a realized natural gas
equivalent price of $9.60 per thousand cubic feet of natural gas equivalent
(mcfe). Chesapeake's average realized pricing differentials to NYMEX during
the first quarter were a negative $5.04 per bbl and a negative $1.61 per
mcf. Realized gains and losses from oil and natural gas hedging activities
during the quarter generated a $1.80 loss per bbl and a $2.03 gain per mcf,
for a 2006 first quarter realized hedging gain of $248 million, or $1.82
per mcfe.
During the past few weeks, Chesapeake has significantly added to its
2006, 2007 and 2008 oil and natural gas hedging positions previously
announced on February 23, 2006. The following tables compare Chesapeake's
hedged production volumes (including only swaps and excluding CNR's swaps)
as of May 1, 2006 to those as of February 23, 2006.
Swap Positions as of May 1, 2006
Natural Gas Oil
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
2006 1Q 76% $10.72 52% $60.03
2006 2Q 78% $8.77 69% $61.85
2006 3Q 86% $8.75 84% $63.90
2006 4Q 81% $9.42 85% $63.76
2006 Total 80% $9.37 72% $62.63
2007 Total 57% $9.90 44% $67.07
2008 Total 41% $9.22 37% $68.20
Swap Positions as of February 23, 2006
Natural Gas Oil
Quarter or Year % Hedged $ NYMEX % Hedged $ NYMEX
2006 1Q 74% $10.72 58% $60.03
2006 2Q 73% $8.82 67% $61.13
2006 3Q 74% $8.87 64% $61.50
2006 4Q 64% $9.36 62% $61.33
2006 Total 71% $9.43 63% $61.02
2007 Total 36% $9.85 22% $62.42
2008 Total 22% $9.10 14% $65.48
Depending on changes in oil and natural gas futures markets and
management's view of underlying oil and natural gas supply and demand
trends, Chesapeake may either increase or decrease its hedging positions at
any time in the future without notice.
The company's updated 2006 and 2007 forecasts are attached to this
release in an Outlook dated May 1, 2006 labeled as Schedule "A", which
begins on page 17. This Outlook has been changed from the Outlook dated
February 23, 2006 (attached as Schedule "B", which begins on page 21) to
reflect various updated information.
Key Operational and Financial Statistics Summarized Below
for the 2006 First Quarter
The table below summarizes Chesapeake's key results during the 2006
first quarter and compares them to the 2005 fourth quarter and first
quarter:
Three Months Ended:
3/31/06 12/31/05 3/31/05
Average daily production (in mmcfe) 1,519 1,418 1,162
Natural gas as % of total production 91 91 90
Natural gas production (in bcf) 124.1 118.3 94.1
Average realized natural gas price
($/mcf) (A) 9.61 8.08 6.20
Oil production (in mbbls) 2,116 2,014 1,746
Average realized oil price ($/bbl) (A) 57.12 52.65 41.74
Natural gas equivalent production
(in bcfe) 136.8 130.4 104.6
Natural gas equivalent realized
price ($/mcfe) (A) 9.60 8.14 6.27
Marketing income ($/mcfe) .10 .10 .07
Service operations income ($/mcfe) .11 --- ---
Production expenses ($/mcfe) (.87) (.72) (.66)
Production taxes ($/mcfe) (.40) (.55) (.34)
General and administrative costs
($/mcfe) (B) (.17) (.15) (.09)
Stock-based compensation ($/mcfe) (.05) (.04) (.02)
DD&A of oil and natural gas properties
($/mcfe) (2.23) (2.09) (1.73)
D&A of other assets ($/mcfe) (.17) (.12) (.10)
Interest expense ($/mcfe) (A) (.52) (.49) (.44)
Operating cash flow ($ in millions) (C) 1,046.9 832.8 504.6
Operating cash flow ($/mcfe) 7.66 6.39 4.82
Adjusted ebitda ($ in millions) (D) 1,147.2 887.7 549.1
Adjusted ebitda ($/mcfe) 8.39 6.81 5.25
Net income to common shareholders
($ in millions) 603.9 431.8 119.5
(A) includes the effects of realized gains or (losses) from hedging, but
does not include the effects of unrealized gains or (losses) from
hedging
(B) excludes expenses associated with non-cash stock-based compensation
(C) defined as cash flow provided by operating activities before changes
in assets and liabilities
(D) defined as income before income taxes, interest expense, and
depreciation, depletion and amortization expense, as adjusted to
remove the effects of certain items detailed on page 16.
Oil and Natural Gas Proved Reserves Reach Record Level of 7.8 Tcfe;
Drilling and Acquisition Costs Average $2.13 per Mcfe as Company
Adds 290 Bcfe for a Reserve Replacement Rate of 312%
Chesapeake began 2006 with estimated proved reserves of 7.521 trillion
cubic feet of natural gas equivalent (tcfe) and ended the quarter with
7.811 tcfe, an increase of 290 bcfe, or 4%. During the 2006 first quarter,
Chesapeake replaced its 137 bcfe of production with an estimated 427 bcfe
of new proved reserves, for a reserve replacement rate of 312%. Reserve
replacement through the drillbit was 184 bcfe, or 135% of production
(including 76 bcfe of positive performance revisions and 88 bcfe of
downward revisions resulting from oil and natural gas price declines
between December 31, 2005 and March 31, 2006) and 43% of the total
increase. Excluding the impact of downward revisions from lower oil and
natural gas prices, Chesapeake's exploration and development costs through
the drillbit were $2.26 per mcfe during the 2006 first quarter. Reserve
replacement through acquisitions of proved reserves was 243 bcfe, or 177%
of production and 57% of the total increase, at a cost of $1.86 per mcfe.
Total costs incurred during the 2006 first quarter, including drilling,
completion, acquisition, seismic, leasehold, capitalized internal costs,
non- cash tax basis step-up from corporate acquisitions, asset retirement
obligations and all other miscellaneous costs capitalized to oil and
natural gas properties, were $1.901 billion. Excluding costs of $718
million for leasehold and unproved properties acquired during the quarter
and $87 million of tax basis step-up, asset retirement obligations and
other costs, as well as downward revisions of proved reserves from lower
oil and natural gas prices, the company's total finding and acquisition
costs were $2.13 per mcfe. A complete reconciliation of finding and
acquisition costs and a roll-forward of proved reserves is presented on
page 13 of this release.
As of March 31, 2006, Chesapeake's estimated future net cash flows
discounted at 10% before income taxes (PV-10) were $17.6 billion using
field differential adjusted prices of $62.06 per bbl (based on a NYMEX
quarter-end price of $66.33 per bbl) and $6.69 per mcf (based on a NYMEX
quarter-end price of $7.18 per mcf). In addition to the PV-10 value of its
proved reserves, the book value of the company's other assets (including
drilling rigs, land and buildings, investments in securities and other
non-current assets) was $1.6 billion as of March 31, 2006.
By comparison, as of March 31, 2005, Chesapeake's PV-10 was $14.2
billion using field differential adjusted prices of $51.38 per bbl (based
on a NYMEX quarter-end price of $55.32 per bbl) and $6.65 per mcf (based on
a NYMEX quarter-end price of $7.17 per mcf). In addition to the PV-10 value
of its proved reserves, the book value of the company's other assets
(including drilling rigs, land and buildings, investments in securities and
other non- current assets) was $0.6 billion as of March 31, 2005.
Chesapeake's PV-10 changes by approximately $300 million for every
$0.10 per mcf change in natural gas prices and approximately $50 million
for every $1.00 per bbl change in oil prices. The company calculates the
standardized measure of future net cash flows in accordance with SFAS 69
only at year-end because applicable income tax information on properties,
including recently acquired oil and natural gas interests, is not readily
available at other times during the year. As a result, the company is not
able to reconcile the March 31, 2006 and March 31, 2005 PV-10 values to the
standardized measure at such dates. The only difference between the two
measures is that PV-10 is calculated before considering the impact of
future income tax expenses, while the standardized measure includes such
effects.
Company's Leasehold and 3-D Seismic Inventories Now Exceed 8.9 Million Net
Acres and 12.3 Million Acres, Respectively; Estimated Unproved Reserves in
Company's Inventory Now 9.2 Tcfe
Chesapeake's exploratory and development drilling programs and
production enhancement operations on its existing and acquired properties
continue to produce operational results that distinguish the company among
its peers. During the 2006 first quarter, Chesapeake drilled 262 gross (210
net) operated wells and participated in another 371 gross (45 net) wells
operated by other companies. The company's drilling success rate was 97%
for company-operated wells and 98% for non-operated wells. During the
quarter, Chesapeake invested $505 million in operated wells (using an
average of 77 operated rigs), $110 million in non-operated wells (using an
average of 75 non-operated rigs) and $200 million in acquiring new 3-D
seismic data and leases (exclusive of leases acquired through
acquisitions).
Chesapeake attributes its strong organic growth rates during the 2006
first quarter and in this decade to management's early recognition that oil
and natural gas prices were undergoing structural change and its subsequent
decision to invest aggressively in the building blocks of value creation in
the E&P industry -- people, land and seismic. Since 2000, Chesapeake has
invested $3.8 billion in new leasehold and 3-D seismic acquisitions and now
owns what it believes to be the largest inventories of onshore leasehold
(8.9 million net acres) and 3-D seismic (12.3 million acres) in the U.S. On
this leasehold, the company has more than a 10-year drilling inventory of
an estimated 29,000 drilling locations on which it believes it can develop
approximately 2.8 tcfe of proved undeveloped reserves and approximately 9.2
tcfe of unproved reserves.
In addition, Chesapeake has significantly strengthened its technical
capabilities during the past five years by increasing its land, geoscience
and engineering staff by 425% to over 650 employees. Today, the company has
more than 3,600 employees, of which approximately 70% work in the company's
E&P operations and 30% work in the company's oilfield service operations.
Chesapeake characterizes its drilling activity by one of four play
types: conventional gas resource, unconventional gas resource, emerging gas
resource and Appalachian Basin gas resource. In these plays, Chesapeake
uses a probability-weighted statistical approach to estimate the potential
number of drillsites and potential unproved reserves associated with such
drillsites. The company's leasehold, proved undeveloped and estimated
potential unproved reserve totals by play type are set forth below:
* 2.9 million net acres in its traditional conventional areas (i.e.,
much of the Mid-Continent, Permian, Gulf Coast, South Texas and other
areas) on which it has approximately 2,700 drillsites, 1.0 tcfe of
proved undeveloped reserves and approximately 1.0 tcfe of unproved
reserves;
* 1.1 million net acres in its unconventional gas resource areas (i.e.,
Sahara, Granite/Cherokee/Atoka Washes, Hartshorne CBM, Barnett Shale
and Ark-La-Tex tight sands) on which it has approximately 14,000
drillsites, 1.3 tcfe of proved undeveloped reserves and approximately
4.5 tcfe of unproved reserves;
* 1.5 million net acres in its emerging gas resource areas (i.e.,
Fayetteville Shale, Caney/Woodford Shales, Deep Haley, Deep Bossier
and others) on which it has approximately 2,400 drillsites, 0.1 tcfe
of proved undeveloped reserves and approximately 2.0 tcfe of unproved
reserves; and
* 3.4 million net acres in the Appalachian Basin, where play types range
from conventional to unconventional to emerging gas resource. On its
significant Appalachian Basin acreage base acquired from CNR in
November 2005, Chesapeake has approximately 10,000 drillsites, 0.4
tcfe of proved undeveloped reserves and more than 1.7 tcfe of unproved
reserves.
Chesapeake continues to actively acquire more acreage throughout its
operating areas, having acquired approximately 500,000 net acres in the
2006 first quarter through an aggressive land acquisition program that is
currently utilizing almost 1,000 contract landmen in the field.
Chesapeake's most significant land acquisition activities during the
quarter took place in the Arkansas Fayetteville Shale, Deep Bossier and
other East Texas plays in which the company now owns more than 1,000,000,
150,000 and 125,000 net acres, respectively. To date, Chesapeake has
drilled five vertical and two horizontal wells in the Fayetteville Shale
and now has three operated rigs in the play drilling horizontal wells. If
results are encouraging, the company may increase its drilling activity in
the Fayetteville Shale later this year. In addition, Chesapeake will drill
its first Deep Bossier well in East Texas and its first horizontal Woodford
well in Southeastern Oklahoma this summer.
The company continues to achieve outstanding drilling results in the
Barnett Shale play of Johnson and Tarrant Counties, Texas. To date,
Chesapeake has drilled and completed 83 Barnett Shale horizontal wells and
has current daily net production of 110 mmcfe (145 mmcfe gross). According
to our recent review of the State of Texas' production records as accessed
through the database of the Energy Division of IHS Inc., Chesapeake's
Barnett Shale wells have been the most productive in the industry as
calculated by peak month average daily production per horizontal well as
set forth in the table below.
Peak Month Average Peak Month Average
Reported Number of Production Per Daily Production Per
Barnett Shale Horizontal Well Horizontal Well
Company Horizontal Wells (mcfe) (mcfe)
Chesapeake 40 76,783 2,524
XTO 108 60,718 1,996
Chief (private) 65 58,280 1,916
EOG 60 52,544 1,727
Devon 212 51,090 1,680
EnCana 84 41,658 1,370
Quicksilver 27 29,847 981
ConocoPhillips
(Burlington) 46 27,230 895
Source: The Energy Division of IHS, Inc. based on production reported
through January 2006 and including only operators of more than 25
horizontal wells.
The company believes this achievement reflects its substantial
experience in drilling and completing horizontal wells in the U.S.
Chesapeake has drilled more horizontal wells than any other company in the
industry and believes it is the only company currently active in all of the
following shale plays: the Barnett and Woodford Shale in West Texas; the
Barnett Shale near Fort Worth, Texas; the Caney and Woodford Shales in
southeastern Oklahoma; the Fayetteville Shale in Arkansas; the New Albany
Shale in Illinois and Kentucky; and various Devonian Shale plays in
Appalachia. Because of this unique position in the industry, the company
believes that it has the distinct opportunity and competitive advantage to
transfer knowledge and technology across all of the major shale plays east
of the Rockies. Also, when combined with Chesapeake's expertise and
activity level in various tight gas sand plays in the southwestern U.S. and
Appalachia, Chesapeake believes it has established the leading natural gas
resource base in the U.S.
Chesapeake Records Gain from Sale of Pioneer Drilling Corporation
Common Stock
and Incurs Charge Related to Early Retirement of Tom L. Ward
In February, Chesapeake elected to sell its 17% ownership interest in
the common stock of Pioneer Drilling Corporation as public company
valuations for onshore U.S. land drilling rigs reached levels that
substantially exceeded the private market valuation of comparable rigs. On
February 10, 2006, Chesapeake sold its 7.7 million shares of Pioneer and
received proceeds of $159 million. The sale resulted in a pre-tax gain to
Chesapeake of $117 million, or a pre- tax profit margin of 275%, on an
investment which had an average holding period of approximately 2.3 years.
With proceeds from the Pioneer sale, the company acquired 13 U.S. onshore
drilling rigs from privately-owned Martex Drilling Company for $150 million
in February 2006.
The Martex acquisition bolstered the company's 100% owned drilling rig
subsidiary, Nomac Drilling Corporation, in which to date Chesapeake has
invested a total of $283 million to build or acquire 34 operating rigs, has
invested another $47 million in 23 rigs that Nomac is currently building
and has budgeted an additional $157 million for completion of these rigs.
In total, Chesapeake's rig fleet should reach 57 rigs within the next 12
months, which should represent one of the ten largest drilling rig fleets
in the U.S.
Chesapeake has also invested $52 million in two private drilling rig
contractors, DHS Drilling Company and Mountain Drilling Company, in which
Chesapeake owns 45% and 49%, respectively. DHS owns 12 rigs and has three
more rigs under construction. Mountain owns one rig and has ordered another
nine rigs for delivery later in 2006 and 2007. Chesapeake's rig investments
have served as an effective hedge to rising service costs and have also
provided competitive advantages in making acquisitions and in developing
its own leasehold on a more timely and efficient basis.
Also in the quarter, Chesapeake's co-founder, President and Chief
Operating officer, Tom L. Ward, announced his retirement from the company
and his resignation from the Board of Directors. As part of a negotiated
separation agreement, Mr. Ward agreed to remain as a consultant to the
company for no cash compensation through the term of his non-compete
agreement, which expires on August 10, 2006. In recognition of Mr. Ward's
role as a co-founder of the company and a key member of the senior
management team that has guided Chesapeake to the second best stock price
performance in the E&P industry since the company's IPO in February 1993
(and the #1 stock price performance since January 1, 1999 among all U.S.
public companies with starting market capitalizations of greater than $50
million), the company's Board agreed to accelerate the vesting of Mr.
Ward's unvested stock options and restricted stock. In connection with the
early vesting, Chesapeake recognized an after- tax charge of $34 million
during the 2006 first quarter. Subsequently, Mr. Ward exercised all of his
stock options on March 14, 2006 and paid the company an aggregate exercise
price of $37 million.
Management Comments
Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented,
"We are pleased to again report outstanding financial and operational
results for the 2006 first quarter. The company delivered top-tier
production growth from both the drillbit and acquisitions as well as record
margins as higher oil and natural gas price realizations far outpaced
modest cost inflation. We have also opportunistically hedged service costs
and a substantial portion of our anticipated production over the next three
years at exceptional prices in order to ensure strong profitability when
others in the industry are likely to face margin compression.
"In light of continued strong returns available through the drillbit on
our extensive prospect inventory, we continue to increase our industry
leading U.S. drilling activity. We currently have 87 operated rigs working
to generate new supplies of clean-burning, domestically-produced natural
gas, up from an average of 73 operated rigs last year, and we anticipate
increasing our drilling activity to over 100 operated rigs by year-end.
This increase in drilling activity creates the potential for increased
production levels in 2006 and 2007 and will allow an accelerated drilling
program in several key areas including: the Barnett Shale, where we plan to
operate an average of at least 12 rigs this year versus an average of four
rigs last year; Sahara, where we plan to operate an average of 12 rigs this
year versus an average of nine rigs last year; and, following the
successful integration of CNR, we now plan to accelerate drilling in
Appalachia to 10-12 rigs, up from four rigs at the time of acquisition last
November.
"We are also pleased to be recognized by Fortune this year as one the
country's 500 largest corporations. In that survey, we were ranked #451 by
revenues, #226 by market value, #206 by assets, #178 by total profits, #28
by profits as a percentage of revenues, and, most importantly, #11 by total
return to shareholders (an exceptional 94% in 2005). In addition, during
the quarter we were also added to the S&P 500 Index.
"The inclusion of Chesapeake in the Fortune 500 and S&P 500 Index is a
reminder of how well the company's business strategy has worked for
investors, royalty owners, consumers and other company stakeholders over
the years. Since our IPO on February 4, 1993, we have delivered an
approximate 2,300% increase in our common stock price. Our business
strategy features delivering growth through a balance of acquisitions and
organic drilling, focusing on clean-burning, domestically-produced natural
gas to take advantage of strong long-term natural gas supply and demand
fundamentals, building dominant regional scale to achieve low operating
costs and high returns on capital and successfully mitigating financial and
operational risks. We believe Chesapeake's management team can continue the
successful execution of the company's distinctive business strategy and
continue to deliver significant value to the company's investors for years
to come."
Conference Call Information
A conference call has been scheduled for Tuesday morning, May 2, 2006
at 9:00 a.m. EDT to discuss this release. The telephone number to access
the conference call is 913.981.4911 and the confirmation code is 1324430.
We encourage those who would like to participate in the call to dial the
access number between 8:50 and 8:55 am EDT. For those unable to participate
in the conference call, a replay will be available from 12:00 p.m. EDT, May
2, 2006 through midnight EDT on May 15, 2006. The number to access the
conference call replay is 719.457.0820 and the passcode for the replay is
1324430. The conference call will also be webcast live on the Internet and
can be accessed at http://www.chkenergy.com by selecting "Conference Calls"
under the "Investor Relations" section. The webcast of the conference call
will be available on our website indefinitely.
This press release and the accompanying Outlooks include
"forward-looking statements" within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. Forward-looking statements give our current expectations or forecasts
of future events. They include estimates of oil and natural gas reserves,
expected oil and natural gas production and future expenses, projections of
future oil and natural gas prices, planned capital expenditures for
drilling, leasehold acquisitions and seismic data, and statements
concerning anticipated cash flow and liquidity, business strategy and other
plans and objectives for future operations. Disclosures concerning the fair
value of derivative contracts and their estimated contribution to our
future results of operations are based upon market information as of a
specific date. These market prices are subject to significant volatility.
Factors that could cause actual results to differ materially from
expected results are described under "Risk Factors" in Item 1A of our 2005
Form 10-K filed with the Securities and Exchange Commission on March 14,
2006. They include the volatility of oil and natural gas prices; the
limitations our level of indebtedness may have on our financial
flexibility; our ability to compete effectively against strong independent
oil and natural gas companies and majors; the availability of capital on an
economic basis to fund reserve replacement costs; our ability to replace
reserves and sustain production; uncertainties inherent in estimating
quantities of oil and natural gas reserves and projecting future rates of
production and the timing of development expenditures; uncertainties in
evaluating oil and natural gas reserves of acquired properties and
associated potential liabilities; our ability to effectively consolidate
and integrate acquired properties and operations; unsuccessful exploration
and development drilling; declines in the values of our oil and natural gas
properties resulting in ceiling test write- downs; lower prices realized on
oil and natural gas sales and collateral required to secure hedging
liabilities resulting from our commodity price risk management activities;
the negative impact lower oil and natural gas prices could have on our
ability to borrow; and drilling and operating risks. We caution you not to
place undue reliance on these forward-looking statements, which speak only
as of the date of this press release, and we undertake no obligation to
update this information.
Our production forecasts are dependent upon many assumptions, including
estimates of production decline rates from existing wells and the outcome
of future drilling activity. Also, our internal estimates of reserves,
particularly those in the properties recently acquired or proposed to be
acquired where we may have limited review of data or experience with the
reserves, may be subject to revision and may be different from estimates by
our external reservoir engineers at year-end. Although we believe the
expectations and forecasts reflected in these and other forward-looking
statements are reasonable, we can give no assurance they will prove to have
been correct. They can be affected by inaccurate assumptions or by known or
unknown risks and uncertainties.
The SEC has generally permitted oil and natural gas companies, in
filings made with the SEC, to disclose only 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. We use the terms "probable", "possible" or "unproved" to
describe volumes of reserves potentially recoverable through additional
drilling or recovery techniques that the SEC's guidelines may prohibit us
from including in filings with the SEC. These estimates are by their nature
more speculative than estimates of proved reserves and accordingly are
subject to substantially greater risk of being actually realized by the
company. While we believe our calculations of unproved drillsites and
estimation of unproved reserves have been appropriately risked and are
reasonable, such calculations and estimates have not been reviewed by third
party engineers or appraisers.
Chesapeake Energy Corporation is the second largest independent
producer of natural gas in the U.S. Headquartered in Oklahoma City, the
company's operations are focused on exploratory and developmental drilling
and corporate and property acquisitions in the Mid-Continent, Permian
Basin, South Texas, Texas Gulf Coast, Barnett Shale, Ark-La-Tex and
Appalachian Basin regions of the United States. The company's Internet
address is http://www.chkenergy.com .
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in 000's, except per share data)
(unaudited)
THREE MONTHS ENDED: March 31, March 31,
2006 2005
$ $/mcfe $ $/mcfe
REVENUES:
Oil and natural gas sales 1,510,821 11.05 538,942 5.15
Marketing sales 404,367 2.96 244,508 2.34
Service operations revenue 29,379 0.21 --- ---
Total Revenues 1,944,567 14.22 783,450 7.49
OPERATING COSTS:
Production expenses 119,392 0.87 69,562 0.66
Production taxes 55,373 0.40 35,958 0.34
General and administrative
expenses 28,791 0.21 12,067 0.12
Marketing expenses 391,360 2.87 237,276 2.27
Service operations expense 14,437 0.11 --- ---
Oil and natural gas depreciation,
depletion and amortization 304,957 2.23 180,968 1.73
Depreciation and amortization
of other assets 23,872 0.17 10,082 0.10
Early retirement expense 54,753 0.40 --- ---
Total Operating Costs 992,935 7.26 545,913 5.22
INCOME FROM OPERATIONS 951,632 6.96 237,537 2.27
OTHER INCOME (EXPENSE):
Interest and other income 9,636 0.07 3,357 0.03
Interest expense (72,658) (0.53) (43,128) (0.41)
Gain on sale of investment 117,396 0.86 --- ---
Loss on repurchases or exchanges
of Chesapeake debt --- --- (900) (0.01)
Total Other Income (Expense) 54,374 0.40 (40,671) (0.39)
Income Before Income Taxes 1,006,006 7.36 196,866 1.88
Income Tax Expense:
Current --- --- --- ---
Deferred 382,283 2.80 71,856 0.69
Total Income Tax Expense 382,283 2.80 71,856 0.69
NET INCOME 623,723 4.56 125,010 1.19
Preferred stock dividends (18,812) (0.13) (5,463) (0.05)
Loss on exchange/conversion
of preferred stock (1,009) (0.01) --- ---
NET INCOME AVAILABLE TO
COMMON SHAREHOLDERS 603,902 4.42 119,547 1.14
EARNINGS PER COMMON SHARE:
Basic $1.64 $0.39
Assuming dilution $1.44 $0.36
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES OUTSTANDING
(in 000's)
Basic 368,625 309,857
Assuming dilution 431,455 351,357
CHESAPEAKE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(in 000's)
(unaudited)
March 31, December 31,
2006 2005
Cash $38,286 $60,027
Other current assets 1,155,910 1,123,370
Total Current Assets 1,194,196 1,183,397
Property and equipment (net) 16,307,278 14,411,887
Other assets 550,886 523,178
Total Assets $18,052,360 $16,118,462
Current liabilities $1,591,931 $1,964,088
Long term debt 6,320,915 5,489,742
Asset retirement obligation 166,249 156,593
Other long term liabilities 426,470 528,738
Deferred tax liability 2,183,972 1,804,978
Total Liabilities 10,689,537 9,944,139
STOCKHOLDERS' EQUITY 7,362,823 6,174,323
TOTAL LIABILITIES & STOCKHOLDERS' EQUITY $18,052,360 $16,118,462
COMMON SHARES OUTSTANDING 382,033 370,190
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF FIRST QUARTER 2006 ADDITIONS TO OIL AND NATURAL GAS
PROPERTIES
($ in 000's, except per unit amounts)
(unaudited)
Reserves
Cost (in mmcfe) $/mcfe
Exploration and development costs $615,338 272,544 (A) $2.26
Acquisition of proved properties 453,051 243,080 1.86
Subtotal 1,068,389 515,624 2.07
Divestitures (73) (67) ---
Geological and geophysical costs 27,498 --- ---
Adjusted subtotal 1,095,814 515,557 2.13
Revisions - price --- (88,217) ---
Acquisition of unproved properties 545,738 --- ---
Leasehold acquisition costs 172,553 --- ---
Adjusted subtotal 1,814,105 427,340 4.25
Tax basis step-up 81,145 --- ---
Asset retirement obligation and other 5,694 --- ---
Total $1,900,944 427,340 $4.45
(A) Includes positive performance revisions of 76 bcfe and excludes
downward revisions of 88 bcfe resulting from oil and natural gas
prices declines between December 31, 2005 and March 31, 2006.
CHESAPEAKE ENERGY CORPORATION
ROLL-FORWARD OF PROVED RESERVES
(unaudited)
Mmcfe
Beginning balance, 12/31/05 7,520,690
Extensions and discoveries 196,769
Acquisitions 243,080
Divestitures (67)
Revisions - performance 75,775
Revisions - price (88,217)
Production (136,752)
Ending balance, 3/31/06 7,811,278
Reserve replacement 427,340
Reserve replacement rate 312%
CHESAPEAKE ENERGY CORPORATION
SUPPLEMENTAL DATA - OIL AND NATURAL GAS SALES AND INTEREST EXPENSE
(in 000's)
(unaudited)
THREE MONTHS ENDED: March 31, March 31,
2006 2005
Oil and Natural Gas Sales ($ in thousands):
Oil sales $124,667 $79,944
Oil derivatives - realized gains (losses) (3,808) (7,067)
Oil derivatives - unrealized gains (losses) (1,335) (12,842)
Total Oil Sales 119,524 60,035
Natural gas sales 940,318 535,777
Natural gas derivatives - realized
gains (losses) 252,029 47,415
Natural gas derivatives - unrealized
gains (losses) 198,950 (104,285)
Total Natural Gas Sales 1,391,297 478,907
Total Oil and Natural Gas Sales $1,510,821 $538,942
Average Sales Price (excluding gains (losses)
on derivatives):
Oil ($ per bbl) $58.92 $45.79
Natural gas ($ per mcf) $ 7.58 $ 5.69
Natural gas equivalent ($ per mcfe) $ 7.79 $ 5.89
Average Sales Price (excluding unrealized gains
(losses) on derivatives):
Oil ($ per bbl) $57.12 $41.74
Natural gas ($ per mcf) $ 9.61 $ 6.20
Natural gas equivalent ($ per mcfe) $ 9.60 $ 6.27
Interest Expense ($ in thousands)
Interest $72,898 $47,293
Derivatives - realized (gains) losses (1,244) (1,121)
Derivatives - unrealized (gains) losses 1,004 (3,044)
Total Interest Expense $72,658 $43,128
CHESAPEAKE ENERGY CORPORATION
CONDENSED CONSOLIDATED CASH FLOW DATA
(in 000's)
(unaudited)
THREE MONTHS ENDED: March 31, March 31,
2006 2005
Cash provided by operating activities $967,458 $512,685
Cash (used in) investing activities (1,960,061) (1,173,937)
Cash provided by financing activities 970,862 654,356
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF OPERATING CASH FLOW AND EBITDA
(in 000's)
(unaudited)
THREE MONTHS ENDED: March 31, Dec. 31, March 31,
2006 2005 2005
CASH PROVIDED BY OPERATING ACTIVITIES $967,458 $829,543 $512,685
Adjustments:
Changes in assets and liabilities 79,405 3,250 (8,063)
OPERATING CASH FLOW* $1,046,863 $832,793 $504,622
* Operating cash flow represents net cash provided by operating
activities before changes in assets and liabilities. Operating cash
flow is presented because management believes it is a useful adjunct
to net cash provided by operating activities under accounting
principles generally accepted in the United States (GAAP). Operating
cash flow is widely accepted as a financial indicator of an oil and
natural gas company's ability to generate cash which is used to
internally fund exploration and development activities and to service
debt. This measure is widely used by investors and rating agencies in
the valuation, comparison, rating and investment recommendations of
companies within the oil and natural gas exploration and production
industry. Operating cash flow is not a measure of financial
performance under GAAP and should not be considered as an alternative
to cash flows from operating, investing, or financing activities as an
indicator of cash flows, or as a measure of liquidity.
THREE MONTHS ENDED: March 31, Dec. 31, March 31,
2006 2005 2005
NET INCOME $623,723 $452,525 $125,010
Income tax expense 382,283 260,114 71,856
Interest expense 72,658 64,177 43,128
Depreciation and amortization
of other assets 23,872 16,175 10,082
Oil and natural gas depreciation,
depletion and amortization 304,957 272,551 180,968
EBITDA** $1,407,493 $1,065,542 $431,044
** Ebitda represents net income (loss) before cumulative effect of
accounting change, income tax expense (benefit), interest expense,
and depreciation, depletion and amortization expense. Ebitda is
presented as a supplemental financial measurement in the evaluation
of our business. We believe that it provides additional information
regarding our ability to meet our future debt service, capital
expenditures and working capital requirements. This measure is
widely used by investors and rating agencies in the valuation,
comparison, rating and investment recommendations of companies.
Ebitda is also a financial measurement that, with certain negotiated
adjustments, is reported to our lenders pursuant to our bank credit
agreement and is used in the financial covenants in our bank credit
agreement and our senior note indentures. Ebitda is not a measure of
financial performance under GAAP. Accordingly, it should not be
considered as a substitute for net income, income from operations, or
cash flow provided by operating activities prepared in accordance
with GAAP. Ebitda is reconciled to cash provided by operating
activities as follows:
THREE MONTHS ENDED: March 31, Dec. 31, March 31,
2006 2005 2005
CASH PROVIDED BY OPERATING ACTIVITIES $967,458 $829,543 $512,685
Changes in assets and liabilities 79,405 3,250 (8,063)
Interest expense 72,658 64,177 43,128
Unrealized gains (losses) on oil
and natural gas derivatives 197,615 178,259 (117,127)
Other non-cash items 90,357 (9,687) 421
EBITDA $1,407,493 $1,065,542 $431,044
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON
($ in 000's, except per share amounts)
(unaudited)
March 31, Dec. 31, March 31,
THREE MONTHS ENDED: 2006 2005 2005
Net income available to common
shareholders $603,902 $431,832 $119,547
Adjustments:
Loss on conversion/exchange
of preferred stock 1,009 4,406 ---
Net Income $604,911 $436,238 $119,547
Adjustments, net of tax:
Unrealized (gains) losses
on derivatives (121,899) (112,965) 72,443
Loss on repurchases or exchanges of debt --- 236 572
Early retirement expense 33,947 --- ---
Gain on sale of investment (72,786) --- ---
Adjusted net income available to
common shareholders* $444,173 $323,509 $192,562
Adjusted earnings per share
assuming dilution** $1.07 $0.84 $0.56
* Adjusted net income available to common and adjusted earnings per
share assuming dilution exclude certain items that management believes
affect the comparability of operating results. The company discloses
these non-GAAP financial measures as a useful adjunct to GAAP earnings
because:
a. Management uses adjusted net income available to common to
evaluate the company's operational trends and performance relative
to other oil and natural gas producing companies.
b. Adjusted net income available to common are more comparable to
earnings estimates provided by securities analysts.
c. Items excluded generally are one-time items, or items whose timing
or amount cannot be reasonably estimated. Accordingly, any
guidance provided by the company generally excludes information
regarding these types of items.
** For purposes of calculating fully diluted shares and earnings per
share assuming dilution for the three months ended March 31, 2006 and
December 31, 2005, accounting rules prohibit the company from assuming
the conversion of the 5.0% (Series 2003) and the 4.125% preferred
stock for common shares prior to conversion or exchange since the
effect would have been anti-dilutive. In determining adjusted
earnings per share, we have reflected the converted shares as though
they were converted at the beginning of the period (fully diluted
share count of 431.7 million and 404.8 million for the three months
ended March 31, 2006 and December 31, 2005, respectively).
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED EBITDA
($ in 000's)
(unaudited)
March 31, Dec. 31, March 31,
THREE MONTHS ENDED: 2006 2005 2005
EBITDA $1,407,493 $1,065,542 $431,044
Adjustments, before tax:
Unrealized (gains) losses on oil
and natural gas derivatives (197,615) (178,259) 117,127
Loss on repurchases or exchanges
of debt --- 372 900
Early retirement expense 54,753 --- ---
Gain on sale of investment (117,396) --- ---
Adjusted EBITDA* $1,147,235 $887,655 $549,071
* Adjusted EBITDA excludes certain items that management believes affect
the comparability of operating results. The company discloses these
non-GAAP financial measures as a useful adjunct to EBITDA because:
a. Management uses adjusted EBITDA to evaluate the company's
operational trends and performance relative to other oil and
natural gas producing companies.
b. Adjusted EBITDA is more comparable to earnings estimates provided
by securities analysts.
c. Items excluded generally are one-time items, or items whose timing
or amount cannot be reasonably estimated. Accordingly, any
guidance provided by the company generally excludes information
regarding these types of items.
SCHEDULE "A"
CHESAPEAKE'S OUTLOOK AS OF MAY 1, 2006
Quarter Ending June 30, 2006; Year Ending December 31, 2006; Year
Ending December 31, 2007.
We have adopted a policy of periodically providing investors with
guidance on certain factors that affect our future financial performance.
As of May 1, 2006, we are using the following key assumptions in our
projections for the second quarter of 2006, the full-year 2006 and the
full-year 2007.
The primary changes from our February 23, 2006 Outlook are in
italicized bold in the table and are explained as follows:
1) We have updated the projected effect of changes in our hedging
positions since our February 23, 2006 Outlook.
2) We have updated our expectations for future NYMEX oil and natural gas
prices based on current market conditions in order to illustrate
hedging effects only.
3) We have updated certain of our cost assumptions.
4) We have shown our projections for the quarter ending June 30, 2006
for the first time.
Quarter Ending Year Ending Year Ending
6/30/2006 12/31/2006 12/31/2007
Estimated Production:
Oil - mbbls 2,000 8,000 8,000
Natural gas - bcf 127 - 132 528 - 538 571 - 581
Natural gas equivalent - bcfe 139 - 144 576 - 586 619 - 629
Daily natural gas equivalent
midpoint - in mmcfe 1,555 1,592 1,710
NYMEX Prices (A) (for calculation
of realized hedging effects only):
Oil - $/bbl $60.00 $60.87 $50.00
Natural gas - $/mcf $7.08 $7.52 $7.00
Estimated Realized Hedging Effects
(based on assumed NYMEX
prices above):
Oil - $/bbl $1.33 $1.43 $7.83
Natural gas - $/mcf $1.67 $2.02 $2.00
Estimated Differentials
to NYMEX Prices:
Oil - $/bbl 6 - 8% 6 - 8% 6 - 8%
Natural gas - $/mcf 8 - 12% 8 - 12% 8 - 12%
Operating Costs per Mcfe of
Projected Production:
Production expense $0.85 - 0.95 $0.85 - 0.95 $0.90 - 1.00
Production taxes (generally
6.0% of O&G revenues) (B) $0.48 - 0.53 $0.41 - 0.46 $0.36 - 0.41
General and administrative $0.15 - 0.20 $0.15 - 0.20 $0.15 - 0.20
Stock-based compensation
(non-cash) $0.05 - 0.07 $0.06 - 0.08 $0.08 - 0.10
DD&A of oil and natural
gas assets $2.25 - 2.35 $2.30 - 2.35 $2.35 - 2.45
Depreciation of other assets $0.16 - 0.20 $0.16 - 0.20 $0.20 - 0.25
Interest expense (C) $0.52 - 0.57 $0.52 - 0.57 $0.53 - 0.58
Other Income per Mcfe:
Marketing and other income $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04
Service operations income $0.10 - 0.15 $0.10 - 0.15 $0.10 - 0.15
Book Tax Rate (approximately
equal to 95% deferred) 38% 38% 38%
Equivalent Shares Outstanding:
Basic 377 mm 376 mm 387 mm
Diluted 436 mm 436 mm 441 mm
Capital Expenditures:
Drilling, leasehold
and seismic $700 - 750 $3,200 - 3,500 $3,400 - 3,600
mm mm mm
(A) Oil NYMEX prices have been updated for actual contract prices
through March 2006 and natural gas NYMEX prices have been updated
for actual contract prices through April 2006.
(B) Severance tax per mcfe is based on NYMEX prices of $60.00 per bbl
and natural gas prices ranging from $8.75 to $9.75 per mcf during Q2
2006, $7.35 to $8.35 per mcf during calendar 2006 and $50.00 per bbl
and $6.50 to $7.50 per mcf during calendar 2007.
(C) Does not include gains or losses on interest rate derivatives (SFAS
133).
Commodity Hedging Activities
The company utilizes hedging strategies to hedge the price of a portion
of its future oil and natural gas production. These strategies include:
(i) For swap instruments, we receive a fixed price for the hedged
commodity and pay a floating market price, as defined in each
instrument, to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due to
or from the counterparty.
(ii) For cap-swaps, Chesapeake receives a fixed price and pays a
floating market price. The fixed price received by Chesapeake
includes a premium in exchange for a "cap" limiting the
counterparty's exposure. In other words, there is no limit to
Chesapeake's exposure but there is a limit to the downside exposure
of the counterparty.
(iii) Basis protection swaps are arrangements that guarantee a price
differential of oil or natural gas from a specified delivery point.
Chesapeake receives a payment from the counterparty if the price
differential is greater than the stated terms of the contract and
pays the counterparty if the price differential is less than the
stated terms of the contract.
Commodity markets are volatile, and as a result, Chesapeake's hedging
activity is dynamic. As market conditions warrant, the company may elect to
settle a hedging transaction prior to its scheduled maturity date and lock
in the gain or loss on the transaction.
Chesapeake enters into oil and natural gas derivative transactions in
order to mitigate a portion of its exposure to adverse market changes in
oil and natural gas prices. Accordingly, associated gains or loses from the
derivative transactions are reflected as adjustments to oil and natural gas
sales. All realized gains and losses from oil and natural gas derivatives
are included in oil and natural gas sales in the month of related
production. Pursuant to SFAS 133, certain derivatives do not qualify for
designation as cash flow hedges. Changes in the fair value of these
non-qualifying derivatives that occur prior to their maturity (i.e. because
of temporary fluctuations in value) are reported currently in the
consolidated statement of operations as unrealized gains (losses) within
oil and natural gas sales.
Following provisions of SFAS 133, changes in the fair value of
derivative instruments designated as cash flow hedges, to the extent
effective in offsetting cash flows attributable to hedged risk, are
recorded in other comprehensive income until the hedged item is recognized
in earnings. Any change in fair value resulting from ineffectiveness is
recognized currently in oil and natural gas sales.
Excluding the swaps assumed in connection with the acquisition of CNR
which are described below, the company currently has the following natural gas
swaps in place:
% Hedged
Open Swap
Positions
Avg. NYMEX Assuming as a % of
Avg. NYMEX Gain Price Natural Estimated
Strike (Loss) Including Gas Total
Price from Open & Production Natural
Open Swaps Of Open Locked Locked in Gas
in Bcf's Swaps Swaps Positions Bcf's of: Production
2006:
Q1 93.8 $10.81 -$0.09 $10.72 124.1 76%
Q2 101.4 $8.82 -$0.05 $8.77 129.5 78%
Q3 117.9 $8.80 -$0.05 $8.75 137.0 86%
Q4 114.9 $9.46 -$0.04 $9.42 142.4 81%
Total 2006(A) 428.0 $9.42 -$0.05 $9.37 533.0 80%
Total 2007 330.0 $9.94 -$0.04 $9.90 576.0 57%
Total 2008 248.9 $9.22 --- $9.22 604.0 41%
Total 2009 3.7 $9.02 --- $9.02 634.0 1%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $3.75 to $5.50 covering 43.0 bcf in 2006.
Note: Not shown above are collars covering 0.2 bcf of production in
2006 at a weighted average floor and ceiling of $6.00 and $9.70 and call
options covering 7.3 bcf of production in 2006 at a weighted average price
of $12.50, 25.6 bcf of production in 2007 at a weighted average price of
$10.53 and 7.3 bcf of production in 2008 at a weighed average price of
$12.50.
The company has the following natural gas basis protection swaps in
place:
Mid-Continent Appalachia
Volume in Bcf's NYMEX less*: Volume in Bcf's NYMEX plus*:
2006 130.1 $ 0.32 --- $ ---
2007 137.2 0.33 32.9 0.34
2008 118.6 0.27 25.6 0.34
2009 86.6 0.29 18.2 0.31
Totals 472.5 $ 0.30 76.7 $ 0.33
* weighted average
We assumed certain liabilities related to open derivative positions in
connection with the CNR acquisition. In accordance with SFAS 141, these
derivative positions were recorded at fair value in the purchase price
allocation as a liability of $592 million ($523 million as of March 31,
2006). The recognition of the derivative liability and other assumed
liabilities resulted in an increase in the total purchase price which was
allocated to the assets acquired. Because of this accounting treatment,
only cash settlements for changes in fair value subsequent to the
acquisition date for the derivative positions assumed result in adjustments
to our oil and natural gas revenues upon settlement. For example, if the
fair value of the derivative positions assumed does not change, then upon
the sale of the underlying production and corresponding settlement of the
derivative positions, cash would be paid to the counterparties and there
would be no adjustment to oil and natural gas revenues related to the
derivative positions. If, however, the actual sales price is different from
the price assumed in the original fair value calculation, the difference
would be reflected as either a decrease or increase in oil and natural gas
revenues, depending upon whether the sales price was higher or lower,
respectively, than the prices assumed in the original fair value
calculation. For accounting purposes, the net effect of these acquired
hedges is that we hedged the production volumes listed below at their fair
values on the date of our acquisition of CNR.
Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative Instruments
and Hedging Activities", the derivative instruments assumed in connection
with the CNR acquisition are deemed to contain a significant financing
element and all cash flows associated with these positions are reported as
financing activity in the statement of cash flows.
The following details the CNR derivatives (natural gas swaps) we have
assumed:
% Hedged
Open Swap
Positions
Avg. NYMEX Avg. Fair Assuming as a % of
Strike Value Upon Natural Estimated
Price Acquisition Initial Gas Total
Of Open of Open Liability Production Natural
Open Swaps Swaps Swaps Acquired in Gas
in Bcf's (per Mcf) (per Mcf) (per Mcf) Bcf's of: Production
2006:
Q1 7.9 $4.91 $12.14 ($7.23) 124.1 6%
Q2 10.5 $4.86 $9.97 ($5.11) 129.5 8%
Q3 10.6 $4.86 $9.95 ($5.09) 137.0 8%
Q4 10.6 $4.86 $10.38 ($5.52) 142.4 7%
Total 2006 39.6 $4.87 $10.51 ($5.64) 533.0 7%
Total 2007 42.0 $4.82 $9.18 ($4.36) 576.0 7%
Total 2008 38.4 $4.67 $8.01 ($3.34) 604.0 6%
Total 2009 18.3 $5.18 $7.28 ($2.10) 634.0 3%
Note: Not shown above are collars covering 3.7 bcf of production in
2009 at an average floor and ceiling of $4.50 and $6.00, respectively.
The company also has the following crude oil swaps in place:
% Hedged
Open Swap
Avg. Assuming Oil Positions
Open Swaps NYMEX Production as % of Total
in mbbls Strike Price in mbbls of: Estimated Production
2006:
Q1 1,109.5 $60.03 2,116 52%
Q2 1,379.5 $61.85 2,000 69%
Q3 1,625.0 $63.90 1,942 84%
Q4 1,656.0 $63.76 1,942 85%
Total 2006(A) 5,770.0 $62.63 8,000 72%
Total 2007 3,555.0 $67.07 8,000 44%
Total 2008 2,928.0 $68.20 8,000 37%
Total 2009 182.5 $66.26 8,000 2%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $40.00 to $42.00 covering 501.5 mbbls in 2006.
SCHEDULE "B"
CHESAPEAKE'S PREVIOUS OUTLOOK AS OF FEBRUARY 23, 2006
(PROVIDED FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF MAY 1, 2006
Quarter Ending March 31, 2006; Year Ending December 31, 2006; Year
Ending December 31, 2007.
We have adopted a policy of periodically providing investors with
guidance on certain factors that affect our future financial performance.
As of February 23, 2006, we are using the following key assumptions in our
projections for the first quarter of 2006, the full-year 2006 and the full-
year 2007.
The primary changes from our January 17, 2006 Outlook are in italicized
bold in the table and are explained as follows:
1) We have updated the projected effect of changes in our hedging
positions since our January 17, 2006 Outlook.
2) We have updated our expectations for future NYMEX oil and gas prices
based on current market conditions in order to illustrate hedging
effects only.
3) We have updated the share count for the effect of accelerating the
stock-based awards to our former Chief Operating Officer; however, we
have not reflected the impact to stock-based compensation that will
occur in the 2006 first quarter or full year.
4) We have not reflected the gain related to the sale of our investment
in Pioneer Drilling Company in other income for the 2006 first
quarter or full year.
5) We have updated the book tax rate for 2006 and 2007 primarily to
account for the impact of state income taxes associated with our
newly acquired Appalachian operations.
Quarter Ending Year Ending Year Ending
3/31/2006 12/31/2006 12/31/2007
Estimated Production:
Oil - Mbbl 1,900 7,700 7,750
Gas - Bcf 121 - 131 530 - 540 572 - 582
Gas Equivalent - Bcfe 132 - 142 576 - 586 619 - 629
Daily gas equivalent midpoint
- in Mmcfe 1,522 1,593 1,709
NYMEX Prices (for calculation
of realized hedging
effects only):
Oil - $/Bbl $58.51 $54.00 $50.00
Gas - $/Mcf $9.47 $7.99 $7.00
Estimated Realized Hedging Effects
(based on assumed NYMEX prices
above):
Oil - $/Bbl $0.96 $4.51 $2.77
Gas - $/Mcf $1.54 $1.40 $1.34
Estimated Differentials
to NYMEX Prices:
Oil - $/Bbl 6-8% 6-8% 6-8%
Gas - $/Mcf 10 - 15% 8 - 12% 8 - 12%
Operating Costs per Mcfe of
Projected Production:
Production expense $0.77 - 0.82 $0.77 - 0.82 $0.80 - 0.85
Production taxes (generally
6.0% of O&G revenues) (A) $0.48 - 0.53 $0.41 - 0.46 $0.36 - 0.41
General and administrative $0.15 - 0.17 $0.14 - 0.16 $0.14 - 0.15
Stock-based compensation
(non-cash) $0.07 - 0.09 $0.08 - 0.10 $0.10 - 0.12
DD&A - oil and gas $2.12 - 2.18 $2.15 - 2.20 $2.25 - 2.30
Depreciation of other
assets $0.14 - 0.16 $0.14 - 0.16 $0.14 - 0.16
Interest expense (B) $0.52 - 0.57 $0.52 - 0.57 $0.53 - 0.58
Other Income and Expense
per Mcfe:
Marketing and other
income $0.02 - 0.04 $0.02 - 0.04 $0.02 - 0.04
Book Tax Rate (approximately
equal to 95% deferred) 38% 38% 38%
Equivalent Shares Outstanding:
Basic 368 mm 374 mm 381 mm
Diluted 431 mm 435 mm 440 mm
Capital Expenditures:
Drilling, leasehold
and seismic $650 - 700 $3,000 - 3,200 $3,300 - 3,500
mm mm mm
(A) Severance tax per mcfe is based on NYMEX prices of $58.51 per bbl
and natural gas prices ranging from $9.00 to $10.00 per mcf during
Q1 2006, $54.00 per bbl and $7.50 to $8.50 per mcf during calendar
2006 and $50.00 per bbl and $6.50 to $7.50 per mcf during calendar
2007.
(B) Does not include gains or losses on interest rate derivatives (SFAS
133).
Commodity Hedging Activities
The company utilizes hedging strategies to hedge the price of a portion
of its future oil and gas production. These strategies include:
(i) For swap instruments, we receive a fixed price for the hedged
commodity and pay a floating market price, as defined in each
instrument, to the counterparty. The fixed-price payment and the
floating-price payment are netted, resulting in a net amount due
to or from the counterparty.
(ii) For cap-swaps, Chesapeake receives a fixed price and pays a
floating market price. The fixed price received by Chesapeake
includes a premium in exchange for a "cap" limiting the
counterparty's exposure. In other words, there is no limit to
Chesapeake's exposure but there is a limit to the downside
exposure of the counterparty.
(iii) Basis protection swaps are arrangements that guarantee a price
differential of oil or gas from a specified delivery point.
Chesapeake receives a payment from the counterparty if the price
differential is greater than the stated terms of the contract and
pays the counterparty if the price differential is less than the
stated terms of the contract.
Commodity markets are volatile, and as a result, Chesapeake's hedging
activity is dynamic. As market conditions warrant, the company may elect to
settle a hedging transaction prior to its scheduled maturity date and lock
in the gain or loss on the transaction.
Chesapeake enters into oil and natural gas derivative transactions in
order to mitigate a portion of its exposure to adverse market changes in
oil and natural gas prices. Accordingly, associated gains or loses from the
derivative transactions are reflected as adjustments to oil and gas sales.
All realized gains and losses from oil and natural gas derivatives are
included in oil and gas sales in the month of related production. Pursuant
to SFAS 133, certain derivatives do not qualify for designation as cash
flow hedges. Changes in the fair value of these non-qualifying derivatives
that occur prior to their maturity (i.e. because of temporary fluctuations
in value) are reported currently in the consolidated statement of
operations as unrealized gains (losses) within oil and gas sales.
Following provisions of SFAS 133, changes in the fair value of
derivative instruments designated as cash flow hedges, to the extent
effective in offsetting cash flows attributable to hedged risk, are
recorded in other comprehensive income until the hedged item is recognized
in earnings. Any change in fair value resulting from ineffectiveness is
recognized currently in oil and natural gas sales.
Excluding the swaps assumed in connection with the acquisition of CNR
which are described below, the company currently has in place the following
natural gas swaps:
% Hedged
Open Swap
Avg. NYMEX Positions
Avg. NYMEX Gain Price Assuming as a % of
Strike (Loss) Including Gas Estimated
Price from Open & Production Total
Open Swaps Of Open Locked Locked in Gas
in Bcf's Swaps Swaps Positions Bcf's of: Production
2006:
Q1 93.8 $10.81 -$0.09 $10.72 126.0 74%
Q2 96.9 $8.88 -$0.06 $8.82 132.0 73%
Q3 101.7 $8.93 -$0.06 $8.87 137.0 74%
Q4 90.0 $9.41 -$0.05 $9.36 140.0 64%
Total 2006(A) 382.4 $9.49 -$0.06 $9.43 535.0 71%
Total 2007 206.9 $9.91 -$0.06 $9.85 577.0 36%
Total 2008 131.8 $9.10 --- $9.10 604.0 22%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $3.75 to $5.50 covering 43.0 bcf in 2006.
Note: Not shown above are collars covering 0.2 bcf of production in
2006 at a weighted average floor and ceiling of $6.00 and $9.70 and call
options covering 7.3 bcf of production in 2006 at a weighted average price
of $12.50, 25.6 bcf of production in 2007 at a weighted average price of
$10.57 and 7.3 bcf of production in 2008 at a weighed average price of
$12.50.
The company has also entered into the following natural gas basis
protection swaps:
Assuming Gas
Volume NYMEX Production
in Bcf's less*: in Bcf's of: % Hedged
2006 130.1 $0.32 535 24%
2007 137.2 0.33 577 24%
2008 118.6 0.27 604 20%
2009 86.6 0.29 634 14%
Totals 472.5 $0.30 2,350 20%
* weighted average
The company has entered into the following crude oil hedging arrangements:
% Hedged
Open Swap
Positions
as %
Assuming Oil of Total
Open Swaps Avg. NYMEX Production Estimated
in mbo's Strike Price in mbo's of: Production
2006:
Q1 1,109.5 $60.03 1,900.0 58%
Q2 1,289.5 $61.13 1,920.0 67%
Q3 1,242.0 $61.50 1,940.0 64%
Q4 1,196.0 $61.33 1,940.0 62%
Total 2006(A) 4,837.0 $61.02 7,700.0 63%
Total 2007 1,730.0 $62.42 7,750.0 22%
Total 2008 1,098.0 $65.48 7,800.0 14%
(A) Certain hedging arrangements include swaps with knockout prices
ranging from $40.00 to $42.00 covering 501.5 mbo in 2006.
We assumed certain liabilities related to open derivative positions in
connection with the CNR acquisition. In accordance with SFAS 141, these
derivative positions were recorded at fair value in the purchase price
allocation as a liability of $592 million. The recognition of the
derivative liability as do other liabilities assumed in connection with the
acquisition resulted in an increase in the total purchase price which is
allocated to the assets acquired. Because of this accounting treatment,
only cash settlements for changes in fair value subsequent to the
acquisition date for the derivative positions assumed will result in
adjustments to our oil and gas revenues upon settlement. For example, if
the fair value of the derivative positions assumed do not change then upon
the sale of the underlying production and corresponding settlement of the
derivative positions, cash would be paid to the counterparties and there
would be no adjustment to oil and gas revenues related to the derivative
positions. If, however, the actual sales price is different than the price
assumed in the original fair value calculation, the difference would be
reflected as either a decrease or increase in oil and gas revenues,
depending upon whether the sales price was higher or lower, respectively,
than the prices assumed in the original fair value calculation. For
accounting purposes, the net effect of these acquired hedges is that we
have hedged the production volumes listed below at their fair values on the
date of our acquisition of CNR.
Pursuant to SFAS 149 "Amendment of SFAS 133 on Derivative Instruments
and Hedging Activities", the derivative instruments assumed in connection
with the CNR acquisitions are deemed to contain a significant financing
element and all cash flows associated with these positions will be reported
as financing activity in the statement of cash flows.
The following details in the CNR derivatives (natural gas swaps) we have
assumed:
% Hedged
Avg.
NYMEX Avg. Fair Open Swap
Strike Value Upon Positions
Price Acquisition Initial Assuming as a % of
Open Of Open of Open Liability Gas Estimated
Swaps Swaps Swaps Acquired Production Total Gas
in Bcf's (per Mcf) (per Mcf) (per Mcf) in Bcf's of: Production
2006:
Q1 7.9 $4.91 $12.14 ($7.23) 126.0 6%
Q2 10.5 $4.86 $9.97 ($5.11) 132.0 8%
Q3 10.6 $4.86 $9.95 ($5.09) 137.0 8%
Q4 10.6 $4.86 $10.38 ($5.52) 140.0 8%
Total
2006 39.6 $4.87 $10.51 ($5.64) 535.0 7%
Total
2007 42.0 $4.82 $9.18 ($4.36) 577.0 7%
Total
2008 38.4 $4.67 $8.01 ($3.34) 604.0 6%
Total
2009 18.3 $5.18 $7.28 ($2.10) 634.0 3%
Note: Not shown above are collars covering 3.7 bcf of production in
2009 at an average floor and ceiling of $4.50 and $6.00, respectively.
SOURCE Chesapeake Energy Corporation
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Related links:
http://www.chkenergy.com
CONTACT:
investors, Jeffrey L. Mobley, CFA, Senior
Vice President- Investor Relations and Research, +1-405-767-4763,
or jmobley@chkenergy.com , or media, Thomas S. Price, Jr., Senior
Vice President-Corporate Development, +1-405-879-9257, or
tprice@chkenergy.com , both of Chesapeake Energy Corporation
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