Chesapeake Energy Corporation Reports Financial and Operational Results for the 2011 Second Quarter
Company Reports 2011 Second Quarter Net Income to Common
Stockholders of $467 Million, or $0.68 per Fully Diluted Common Share,
on Revenue of $3.3 Billion; Company Reports Adjusted Net Income
Available to Common Stockholders of $528 Million, or $0.76 per Fully
Diluted Common Share, Adjusted Ebitda of $1.4 Billion and Operating Cash
Flow of $1.2 Billion
2011 Second Quarter Average Daily Total Production of 3.049 Bcfe
per Day Increases 9% Year over Year and Decreases 2% Sequentially Due to
the Sale of Fayetteville Shale Assets and VPP #9; 2011 Second Quarter
Liquids Production Increases 62% Year over Year and 19% Sequentially;
2011 Second Quarter Liquids Production Yields 16% of Total Production
and 28% of Realized Natural Gas and Liquids Revenue
Proved Reserves Total 16.5 Tcfe; Company Adds New Net Proved
Reserves of 2.7 Tcfe Through the Drillbit in the First Half of 2011 at a
Drilling and Completion Cost of $1.29 per Mcfe
Company Increases Full-Year 2011 and 2012 Production and Capital
Expenditure Outlook; Company Largely Offsets Oilfield Service Inflation
Through Its Wholly Owned Oilfield Service Businesses and Its 30% Stake
in Frac Tech
Chesapeake Announces a Major New Liquids-Rich Discovery in the
Utica Shale in Eastern Ohio
Chesapeake Energy Corporation (NYSE:CHK) today announced its 2011 second
quarter financial and operational results. For the quarter, Chesapeake
reported net income to common stockholders of $467 million ($0.68 per
fully diluted common share), operating cash flow of $1.207 billion
(defined as cash flow from operating activities before changes in assets
and liabilities) and ebitda of $1.289 billion (defined as net income
before income taxes, interest expense, and depreciation, depletion and
amortization) on revenue of $3.318 billion and production of 277 billion
cubic feet of natural gas equivalent (bcfe).
The company′s 2011 second quarter results include various items that are
typically not included in published estimates of the company′s financial
results by certain securities analysts. Excluding the items detailed
below, for the 2011 second quarter, Chesapeake reported adjusted net
income to common stockholders of $528 million ($0.76 per fully diluted
common share) and adjusted ebitda of $1.365 billion. The excluded items
and their effects on the 2011 second quarter reported results are
detailed as follows:
a net unrealized after-tax mark-to-market gain of $61 million
resulting from the company′s natural gas, liquids and interest rate
hedging programs; and
an after-tax loss of $122 million related to purchases of certain of
the company's senior notes, a loss on foreign currency derivatives and
other items.
A reconciliation of operating cash flow, ebitda, adjusted ebitda and
adjusted net income to comparable financial measures calculated in
accordance with generally accepted accounting principles is presented on
pages 17 ? 21 of this release.
Key Operational and Financial Statistics Summarized
The table below summarizes Chesapeake′s key results during the 2011
second quarter and compares them to results during the 2011 first
quarter and the 2010 second quarter.
| Three Months Ended | ||||||||||
| 6/30/11 | 3/31/11 | 6/30/10 | ||||||||
Average daily production (in mmcfe)(a) | 3,049 | 3,107 | 2,789 | |||||||
Natural gas as % of total production | 84 | 87 | 90 | |||||||
Natural gas production (in bcf) | 234.3 | 243.3 | 227.2 | |||||||
Average realized natural gas price ($/mcf)(b) | 5.19 | 5.31 | 5.66 | |||||||
Oil and NGL (liquids) production (in mbbls) | 7,192 | 6,048 | 4,429 | |||||||
Average realized liquids price ($/bbl)(b) | 65.23 | 63.20 | 61.43 | |||||||
Natural gas equivalent production (in bcfe) | 277.5 | 279.6 | 253.8 | |||||||
Natural gas equivalent realized price ($/mcfe)(b) | 6.07 | 5.99 | 6.14 | |||||||
Marketing, gathering and compression net margin ($/mcfe)(c) | .14 | .11 | .12 | |||||||
Service operations net margin ($/mcfe) (c) | .11 | .09 | .02 | |||||||
Production expenses ($/mcfe) | (.94 | ) | (.85 | ) | (.84 | ) | ||||
Production taxes ($/mcfe) | (.17 | ) | (.16 | ) |
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General and administrative costs ($/mcfe)(d) | (.38 | ) | (.38 | ) |
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Stock-based compensation ($/mcfe) | (.08 | ) | (.08 | ) |
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DD&A of natural gas and liquids properties ($/mcfe) | (1.32 | ) | (1.28 | ) |
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D&A of other assets ($/mcfe) | (.23 | ) | (.24 | ) |
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Interest (expense) income ($/mcfe)(b) | (.07 | ) | .00 |
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Operating cash flow ($ in millions)(e) | 1,207 | 1,381 | 1,304 | |||||||
Operating cash flow ($/mcfe) | 4.35 | 4.94 | 5.14 | |||||||
Adjusted ebitda ($ in millions)(f) | 1,365 | 1,346 | 1,256 | |||||||
Adjusted ebitda ($/mcfe) | 4.92 | 4.81 | 4.95 | |||||||
Net income (loss) to common stockholders ($ in millions) | 467 | (205 | ) | 235 | ||||||
Earnings (loss) per share ? assuming dilution ($) | .68 | (.32 | ) | .37 | ||||||
Adjusted net income to common stockholders ($ in millions)(g) | 528 | 518 | 491 | |||||||
Adjusted earnings per share ? assuming dilution ($) | .76 | .75 | .75 | |||||||
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(e) | Defined as cash flow provided by operating activities before changes in assets and liabilities. | |
(f) | Defined as net income (loss) before income taxes, interest expense, and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 19. | |
(g) | Defined as net income (loss) available to common stockholders, as adjusted to remove the effects of certain items detailed on page 20. |
2011 Second Quarter Average Daily Total Production of 3.049 Bcfe per
Day Increases 9%
Year over Year and Decreases 2%
Sequentially Due to the Sale of Fayetteville Shale
Assets
and VPP #9; 2011 Second Quarter Liquids Production Increases 62% Year
over
Year and 19% Sequentially; 2011 Second Quarter Liquids
Production Yields 16% of Total
Production and 28% of
Realized Natural Gas and Liquids Revenue
Chesapeake′s daily production for the 2011 second quarter averaged 3.049
bcfe, an increase of 260 million cubic feet of natural gas equivalent
(mmcfe), or 9%, over the 2.789 bcfe produced per day in the 2010 second
quarter and a decrease of 58 mmcfe, or 2%, from the 3.107 bcfe produced
per day in the 2011 first quarter. Adjusted for the sale of the
company′s Fayetteville Shale assets to BHP Billiton Petroleum, a wholly
owned subsidiary of BHP Billiton Limited (NYSE:BHP; ASX:BHP) on March
31, 2011 (which had an average production loss impact of approximately
400 mmcfe per day in the 2011 second quarter), and the company′s ninth
volumetric production payment (VPP #9) transaction on May 12, 2011
(which had an average production loss impact of approximately 40 mmcfe
per day in the 2011 second quarter), Chesapeake′s year over year and
sequential daily production growth would have been approximately 700
mmcfe and 380 mmcfe, or 25% and 12%, respectively.
Chesapeake′s average daily production of 3.049 bcfe for the 2011 second
quarter consisted of 2.575 billion cubic feet of natural gas (bcf) and
79,033 barrels (bbls) of oil and natural gas liquids (collectively,
'liquids?). The company′s 2011 second quarter production of 277.5 bcfe
was comprised of 234.3 bcf of natural gas (84% on a natural gas
equivalent basis) and 7.2 million barrels of liquids (mmbbls) (16% on a
natural gas equivalent basis). The company′s year over year growth rate
of natural gas production was 3% and its year over year growth rate of
liquids production was 62% before adjustments for asset sales and 20%
and 65%, respectively, after adjustments. The company′s percentage of
revenue from liquids in the 2011 second quarter was 28% of total
realized natural gas and liquids revenue compared to 17% in the 2010
second quarter and 23% in the 2011 first quarter.
2011 Second Quarter Average Realized Prices Benefit from Realized
Hedging
Gains of $407 Million, or $1.46 per Mcfe
Average prices realized during the 2011 second quarter (including
realized gains or losses from natural gas and oil derivatives, but
excluding unrealized gains or losses on such derivatives) were $5.19 per
thousand cubic feet (mcf) and $65.23 per bbl, for a realized natural gas
equivalent price of $6.07 per thousand cubic feet of natural gas
equivalent (mcfe). Realized gains from natural gas hedging activities
during the 2011 second quarter generated a $1.93 gain per mcf, while
realized losses from liquids hedging activities generated a $6.23 loss
per bbl, resulting in 2011 second quarter net realized hedging gains of
$407 million, or $1.46 per mcfe.
By comparison, average prices realized during the 2010 second quarter
(including realized gains or losses from natural gas and oil
derivatives, but excluding unrealized gains or losses on such
derivatives) were $5.66 per mcf and $61.43 per bbl, for a realized
natural gas equivalent price of $6.14 per mcfe. Realized gains from
natural gas and liquids hedging activities during the 2010 second
quarter generated a $2.43 gain per mcf and a $4.85 gain per bbl,
resulting in 2010 second quarter realized hedging gains of $573 million,
or $2.26 per mcfe. The company′s realized cash hedging gains since
January 1, 2006 have been $7.7 billion, or $1.67 per mcfe, on average,
for every mcfe produced.
Company Provides Update on Hedging Positions
The following table summarizes Chesapeake′s 2011 and 2012 open swap
positions as of July 28, 2011. Depending on changes in natural gas and
oil futures markets and management′s view of underlying natural gas and
oil supply and demand trends, Chesapeake may increase or decrease some
or all of its hedging positions at any time in the future without notice.
| Natural Gas | Liquids | |||||||||||||
| Year | % of Forecasted | $ NYMEX | % of Forecasted | $ NYMEX Oil | ||||||||||
3Q ? 4Q 2011 | 79 | % | $ | 4.79 | 9 | % | $ | 100.90 | ||||||
2012 | 9 | % | $ | 6.12 | 3 | % | $ | 105.03 | ||||||
In addition to the open hedging positions disclosed above, as of July
28, 2011, the company had an additional $501 million and $330 million of
net hedging gains on closed contracts and premiums collected on call
options that will be realized in 2011 and 2012, respectively, as set
forth below.
| Natural Gas | Liquids | |||||||||||||||||||
| Year | Forecasted | Gains | Gains | Forecasted | Gains | Gains | ||||||||||||||
3Q ? 4Q 2011 | 500 | $ | 535 | $ | 1.07 | 19,000 | $ | (34 | ) | $ | (1.80 | ) | ||||||||
2012 | 1,020 | $ | 248 | $ | 0.24 | 55,000 | $ | 82 | $ | 1.48 | ||||||||||
Assuming future NYMEX natural gas settlement prices average $4.50 and
$5.50 per mcf for the second half of 2011 and for the full year 2012,
respectively, and including the effect of the company′s open hedges,
closed contracts and previously collected call premiums, the company
estimates its average NYMEX natural gas prices will be $5.70 and $5.78
per mcf for the second half of 2011 and for the full year 2012,
respectively. Additionally, assuming future NYMEX oil settlement prices
average $100.00 per bbl for the second half of 2011 and for the full
year 2012, the company estimates its average NYMEX oil prices will be
$97.09 and $96.07 per bbl for the second half of 2011 and for the full
year 2012, respectively. Wellhead prices are further reduced from these
estimates by the effect of gathering costs, basis and quality
differentials and the effect of lower-priced natural gas liquids.
Details of the company′s quarter-end hedging positions, including sold
call options, are provided in the company′s Form 10-Q and Form 10-K
filings with the SEC and current positions are disclosed in summary
format in the company′s Outlook. The company′s updated forecasts for
2011 and 2012 are attached to this release in the Outlook dated July 28,
2011, labeled as Schedule 'A,? which begins on page 22. The Outlook has
been changed from the Outlook dated May 2, 2011, attached as Schedule
'B,? which begins on page 26, to reflect various updated information.
Proved Natural Gas and Liquids Reserves Decreased by 642 Bcfe, or 4%,
in the First Half
of 2011 to 16.5 Tcfe Due to the Sale of
2.8 Tcfe of Proved Reserves; Also in the First Half
of 2011,
Company Adds New Net Proved Reserves Before Sales of 2.7 Tcfe Through the
Drillbit
at a Drilling and Completion Cost of $1.29 per Mcfe
During the first half of 2011, Chesapeake continued the industry′s most
active drilling program drilling 759 gross operated wells (480 net wells
with an average working interest of 63%) and participating in another
708 gross non-operated wells (104 net wells with an average working
interest of 15%). The company′s drilling success rate was 98% for
company-operated wells and 99% for non-operated wells. During the first
half of 2011, Chesapeake′s drilling and completion costs of $3.427
billion included the benefit of approximately $1.129 billion of drilling
and completion carries from its joint venture partners.
The following table compares Chesapeake′s June 30, 2011 proved reserves,
the decrease versus its year-end 2010 proved reserves, estimated future
net cash flows from proved reserves (discounted at an annual rate of 10%
before income taxes (PV-10)), and proved developed percentage based on
the trailing 12-month average price required by the reserve reporting
rules of the Securities and Exchange Commission (SEC) and the 10-year
average NYMEX strip prices at June 30, 2011.
| Pricing Method | Natural Gas Price ($/mcf) |
Oil Price ($/bbl) | Proved Reserves (tcfe)(a) | Proved Reserves Decrease (bcfe)(b) | Proved Reserves Decrease %(b) | PV-10 (billions) | Proved Developed % | ||||||||||||
Trailing 12-month average (SEC)(c) | $ | 4.21 | $ | 89.86 | 16.5 | 642 | 4 | % | $ | 16.4 | 54 | % | |||||||
6/30/11 10-year average NYMEX strip(d) | $ | 5.80 | $ | 100.24 | 17.2 | 401 | 2 | % | $ | 27.4 | 54 | % | |||||||
(a) After sales of proved reserves of approximately 2.8 tcfe during the
first half of 2011.
(b) Compares proved reserve decrease for the first half of 2011 under
comparable pricing methods. At year-end 2010, Chesapeake′s proved
reserves were 17.1 tcfe using trailing 12-month average prices, which
are required by SEC reporting rules, and 17.6 tcfe using the 10-year
average NYMEX strip prices at December 31, 2010.
(c) Reserve volumes estimated using SEC reserve recognition standards
and pricing assumptions based on the trailing 12-month average
first-day-of-the-month prices as of June 30, 2011. This pricing yields
estimated 'proved reserves' for SEC reporting purposes. Natural gas and
liquids volumes estimated under any alternative pricing scenario reflect
the sensitivity of proved reserves to a different pricing assumption.
(d) Futures prices represent an unbiased consensus estimate by market
participants about the likely prices to be received for future
production. Management believes that 10-year average NYMEX strip prices
provide a better indicator of the likely economic producibility of the
company′s proved reserves than the historical 12-month average price.
The following table summarizes Chesapeake′s drilling and completion
costs for the first half of 2011 using the two pricing methods described
above.
Trailing | 6/30/11 | |||||
Drilling and completion costs(a) | $ | 1.29 | $ | 1.26 | ||
(a) Includes performance-related revisions and excludes price-related
revisions. Costs are net of drilling and completion carries paid by the
company′s joint venture partners.
A complete reconciliation of proved reserves based on these two
alternative pricing methods, along with total costs, is presented on
pages 13 and 14 of this release.
In addition to the PV-10 value of its proved reserves, the company also
has substantial value in its undeveloped leasehold. Furthermore, the net
book value of the company′s other assets (including gathering systems,
compressors, land and buildings, investments and other non-current
assets) was $6.6 billion as of June 30, 2011, an increase of
approximately $500 million from December 31, 2010.
Chesapeake′s Leasehold and 3-D Seismic Inventories Total 14.5 Million
Net Acres
and 29.4 Million Acres, Respectively; Risked
Unproved Resources in
the Company′s Inventory Total 109 Tcfe
Since 2000, Chesapeake has built the largest combined inventories of
onshore leasehold (14.5 million net acres) and 3-D seismic (29.4 million
acres) in the U.S. The company has also accumulated the largest
inventory of U.S. natural gas shale play leasehold (2.5 million net
acres) and now owns a leading position in 12 of what Chesapeake believes
are the Top 15 unconventional liquids-rich plays in the U.S. ? the
Granite Wash, Cleveland, Tonkawa and Mississippian plays in the Anadarko
Basin; the Avalon, Bone Spring, Wolfcamp and Wolfberry plays in the
Permian Basin; the Eagle Ford Shale in South Texas; the Niobrara Shale
in the Powder River and DJ basins; the Bakken/Three Forks in the
Williston Basin; and the Utica Shale in the Appalachian Basin.
On its total leasehold inventory, Chesapeake has identified an estimated
17.2 trillion cubic feet of natural gas equivalent (tcfe) of proved
reserves (using volume estimates based on the 10-year average NYMEX
strip prices at June 30, 2011), 109 tcfe of risked unproved resources
and 322 tcfe of unrisked unproved resources. The company is currently
using 166 operated drilling rigs to further develop its inventory of
approximately 38,400 net risked drillsites. Of Chesapeake′s 166 operated
rigs, 81 are drilling wells primarily focused on unconventional natural
gas plays (including 48 operated rigs utilizing drilling carries), 82
are drilling wells primarily focused on unconventional liquids-rich
plays (including 28 operated rigs utilizing drilling carries) and three
are drilling conventional natural gas plays. In addition, 163 of the
company′s 166 operated rigs are drilling horizontal wells.
In recognition of the value gap between liquids and natural gas prices,
Chesapeake has directed a significant portion of its technological and
leasehold acquisition expertise during the past three years to identify,
secure and commercialize new unconventional liquids-rich plays. To date,
Chesapeake has built leasehold positions and established production in
multiple liquids-rich plays on approximately 5.5 million net leasehold
acres with 6.5 billion bbls of oil equivalent (bboe) (or 39 tcfe) of
risked unproved resources and 24.0 bboe (or 144 tcfe) of unrisked
unproved resources based on the company′s internal estimates. As a
result of its success to date, Chesapeake expects to increase its
liquids production through its drilling activities to more than 150,000
bbls per day, or 20%-25% of total production, by year-end 2012 and to
more than 250,000 bbls per day, or 30%-35% of total production, by
year-end 2015.
The following table summarizes Chesapeake′s ownership and activity in
its unconventional natural gas plays, its unconventional liquids-rich
plays and its other conventional and unconventional plays. Chesapeake
uses a probability-weighted statistical approach to estimate the
potential number of drillsites and unproved resources associated with
such drillsites.
| Est. | Risked | Total | Risked | Unrisked | July 2011 | July 2011 | |||||||||||||
| CHK | Drilling | Net | Proved | Unproved | Unproved | Daily Net | Operated | ||||||||||||
| Net | Density | Risk | Undrilled | Reserves | Resources | Resources | Production | Rig | |||||||||||
| Play Type/Area | Acreage(1) | (Acres) | Factor | Wells | (bcfe)(1)(2) | (bcfe)(1) | (bcfe)(1) | (mmcfe) | Count | ||||||||||
Unconventional Natural Gas Plays: | |||||||||||||||||||
Marcellus | 1,750,000 | 90 | 60 | % | 7,710 | 1,059 | 37,100 | 93,600 | 320 | 30 | |||||||||
Haynesville | 495,000 | 80 | 30 | % | 4,040 | 4,157 | 16,800 | 25,300 | 1,085 | 28 | |||||||||
Bossier(3) | 190,000 | 80 | 60 | % | 970 | 16 | 4,000 | 10,000 | 15 | 5 | |||||||||
Barnett | 220,000 | 60 | 25 | % | 1,670 | 3,831 | 2,800 | 3,700 | 395 | 16 | |||||||||
Pearsall(4) | 350,000 | 160 | 75 | % | 550 | 3 | 2,500 | 9,800 | ND | 2 | |||||||||
| Subtotal | 2,465,000 | 14,940 | 9,066 | 63,200 | 142,400 | 1,815 | 81 | ||||||||||||
Unconventional Liquids Plays: | |||||||||||||||||||
Anadarko Basin(5) | 2,035,000 | 155 | 70 | % | 4,360 | 2,506 | 12,500 | 33,100 | 510 | 35 | |||||||||
Eagle Ford | 460,000 | 80 | 50 | % | 2,830 | 399 | 8,100 | 16,600 | 50 | 20 | |||||||||
Permian Basin(6) | 835,000 | 160 | 65 | % | 1,810 | 302 | 2,800 | 9,000 | 110 | 12 | |||||||||
Powder River and DJ basins(7) | 595,000 | ND | ND | ND | ND | ND | ND | ND | 8 | ||||||||||
Utica | 1,250,000 | ND | ND | ND | ND | ND | ND | ND | 5 | ||||||||||
Other | 320,000 | ND | ND | ND | ND | ND | ND | ND | 2 | ||||||||||
| Subtotal | 5,495,000 | 13,670 | 3,224 | 38,900 | 144,000 | 680 | 82 | ||||||||||||
| Other Conventional and | |||||||||||||||||||
| Unconventional Plays: | 6,520,000 | Various | Various | 9,790 | 4,910 | 7,100 | 35,600 | 640 | 3 | ||||||||||
| Total | 14,480,000 | 38,400 | 17,200 | 109,200 | 322,000 | 3,135 | 166 | ||||||||||||
Note: ND denotes 'not disclosed?
(1) As of June 30, 2011, pro forma for recent leasehold transactions
(2) Based on 10-year average NYMEX strip prices at June 30, 2011
(3) Bossier Shale acreage overlaps with Haynesville Shale acreage and is
excluded from the sub-totals to avoid double counting of acreage
(4) Pearsall Shale acreage overlaps with Eagle Ford Shale acreage and is
excluded from the sub-totals to avoid double counting of acreage
(5) Includes Granite Wash, Cleveland, Tonkawa and Mississippian plays
(6) Includes various Delaware and Midland basin plays, including
Wolfcamp, Avalon, Bone Spring and Wolfberry
(7) Includes Niobrara, Frontier, Codell and Greenhorn plays
Company Increases Full-Year 2011 and 2012 Production and Capital
Expenditure
Outlook; Company Largely Offsets Oilfield
Service Inflation Through Its Wholly
Owned Oilfield Service
Businesses and Its 30% Stake in Frac Tech
As a result of continued strong drilling results, particularly in the
Haynesville Shale and the Marcellus Shale (where Chesapeake has recently
increased its expected estimated ultimate per well recoveries to 5.75
bcfe from 5.25 bcfe), Chesapeake has increased its production forecast
for the full-year 2011 and 2012 to approximately 1.170 tcfe and 1.350
tcfe, respectively, and now anticipates delivering approximately 30%
production growth for the two-year period ending December 31, 2012, a
20% increase from its prior forecasted growth rate of 25% as projected
in the company′s 25/25 Plan announced in January 2011. Chesapeake′s
full-year 2011 liquids production forecast range has been reduced by 2
mmbbls, or 6%, to 31-33 mmbbls due to short-term infrastructure and
logistical constraints in many of its liquids-rich plays, which
Chesapeake expects to resolve in the coming months. As a result, the
company has increased the lower end of its 2012 liquids production
forecast range by an offsetting 2 mmbbls to 53 mmbbls.
Because of persistent and significant oilfield service inflation and a
more accelerated drilling program in the Utica Shale play, Chesapeake
has increased its planned drilling and completion capital expenditure
budget for each of full-year 2011 and 2012 by $500 million to a range of
$6.0-$6.5 billion in each year.
Chesapeake has uniquely been able to offset a significant portion of
recent oilfield service inflation though its vertical integration
strategy and ownership of subsidiary companies that own drilling rigs
(Nomac Drilling), pressure pumping equipment (Performance Technologies),
rental tools (Great Plains), trucking equipment (Thunder Oilfield),
compression manufacturing equipment (Compass) and a variety of other
oilfield services, all of which are organized under Chesapeake′s wholly
owned subsidiary, Chesapeake Oilfield Services, L.L.C. (COS). In
aggregate, Chesapeake projects that if these oilfield service businesses
were viewed on a standalone basis, operating cash flow from these
businesses would be an estimated $600 million in 2012. In addition, COS
owns a 30% interest in Frac Tech Services, LLC, the fourth-largest
onshore pressure pumping and well stimulation company in the U.S. Based
on comparable public company trading multiples, the company believes its
stakes in COS and Frac Tech are worth in excess of $7.0 billion.
Chesapeake is considering options to monetize a portion of its oilfield
service assets to create a cash offset to the oilfield inflation it has
experienced in 2011 and expects to experience again in 2012.
Chesapeake Announces a Major New Liquids-Rich Discovery
in
the Utica Shale in Eastern Ohio
Having achieved successful results from recent drilling activities in
eastern Ohio, Chesapeake is announcing the discovery of a major new
liquids-rich play in the Utica Shale. Based on its proprietary
geoscientific, petrophysical and engineering research during the past
two years and the results of six horizontal and nine vertical wells it
has drilled, Chesapeake believes that its industry-leading 1.25 million
net leasehold acres in the Utica Shale play could be worth $15 - $20
billion in increased value to the company. Chesapeake′s dataset on the
Utica Shale includes approximately 2,000 well logs, full-suite
petrophysical data on approximately 200 wells, 3,200 feet of proprietary
core samples from nine wells and production results from three wells. As
a result of its analysis, the company believes the Utica Shale will be
characterized by a western oil phase, a central wet gas phase and an
eastern dry gas phase and is likely most analogous, but economically
superior to, the Eagle Ford Shale in South Texas.
Chesapeake is currently drilling in the Utica Shale with five operated
rigs to further evaluate and develop its leasehold and anticipates
increasing its rig count to eight by the end of 2011 and reaching at
least a range of 16-20 rigs by year-end 2012. Also, the company believes
that its leasehold position in the Utica Shale will support a drilling
effort of at least 40 rigs by year-end 2014. Chesapeake is currently
conducting a competitive process to monetize a portion of its Utica
Shale leasehold position, which will be through an industry joint
venture process or through a number of other monetization alternatives.
The company anticipates completing a Utica Shale transaction in the 2011
fourth quarter.
Conference Call Information
A conference call to discuss this release has been scheduled for Friday,
July 29, 2011, at 9:00 a.m. EDT. The telephone number to access the
conference call is 913-312-0417 or toll-free 888-599-8685.
The passcode for the call is 5165869. We encourage those who
would like to participate in the call to dial the access number between
8:50 and 9:00 a.m. EDT. For those unable to participate in the
conference call, a replay will be available for audio playback from 1:00
p.m. EDT on July 29, 2011 through midnight EDT on August 12, 2011. The
number to access the conference call replay is 719-457-0820 or
toll-free 888-203-1112. The passcode for the replay is 5165869.
The conference call will also be webcast live on Chesapeake′s website at www.chk.com
in the 'Events? subsection of the 'Investors? section of the website.
The webcast of the conference call will be available on Chesapeake′s
website for one year.
This news 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 natural gas
and liquids reserves and resources, expected natural gas and liquids
production and future expenses, assumptions regarding future natural gas
and oil prices, planned drilling activity and drilling and completion
costs, anticipated asset monetizations, estimates of asset values,
projected cash flow and liquidity, business strategy and other plans and
objectives for future operations.Disclosures of the estimated
realized effects of our current hedging positions on future natural gas
and liquids sales are based upon market prices that are subject to
significant volatility. We caution you not to place undue reliance on
our forward-looking statements, which speak only as of the date of this
news release, and we undertake no obligation to update this information.
Factors that could cause actual results to differ materially from
expected results are described under 'Risk Factors? in our 2010 Form
10-K filed with the U.S. Securities and Exchange Commission on March 1,
2011.These risk factors include the volatility of natural gas
and oil prices; the limitations our level of indebtedness may have on
our financial flexibility; declines in the values of our natural gas and
liquids properties resulting in ceiling test write-downs; the
availability of capital on an economic basis, including planned asset
monetization transactions, to fund reserve replacement costs; our
ability to replace reserves and sustain production; uncertainties
inherent in estimating quantities of natural gas and liquids reserves
and projecting future rates of production and the amount and timing of
development expenditures; inability to generate profits or achieve
targeted results in drilling and well operations; leasehold terms
expiring before production can be established; hedging activities
resulting in lower prices realized on natural gas and liquids sales, the
need to secure hedging liabilities and the inability of hedging
counterparties to satisfy their obligations; a reduced ability to borrow
or raise additional capital as a result oflower natural gas and
oil prices; drilling and operating risks, including potential
environmental liabilities; legislative and regulatory changes adversely
affecting our industry and our business; general economic conditions
negatively impacting us and our business counterparties; transportation
capacity constraints and interruptions that could adversely affect our
revenues and cash flow; and adverse results in pending or future
litigation.
Our production forecasts are dependent upon many assumptions,
including estimates of production decline rates from existing wells and
the outcome of future drilling activity.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 requires natural gas and oil companies, in filings made with
the SEC, to disclose proved reserves, which are those quantities of
natural gas and liquids that by analysis of geoscience and engineering
data can be estimated with reasonable certainty to be economically
producible ? from a given date forward, from known reservoirs, and under
existing economic conditions, operating methods, and government
regulations ? prior to the time at which contracts providing the right
to operate expire, unless evidence indicates that renewal is reasonably
certain, regardless of whether deterministic or probabilistic methods
are used for the estimation.In this news release, we use the
terms 'risked and unrisked unproved resources? to describe Chesapeake′s
internal estimates of volumes of natural gas and liquids that are not
classified as proved reserves but are potentially recoverable through
exploratory drilling or additional drilling or recovery techniques.These
are broader descriptions of potentially recoverable volumes than
probable and possible reserves, as defined by SEC regulations.Estimates
of unproved resources are by their nature more speculative than
estimates of proved reserves and accordingly are subject to
substantially greater risk of actually being realized by the company.We believe our estimates of unproved resources are reasonable, but
such estimates have not been reviewed by independent engineers.Estimates
of unproved resources may change significantly as development provides
additional data, and actual quantities that are ultimately recovered may
differ substantially from prior estimates.The company calculates
the standardized measure of future net cash flows of proved reserves
only at year end because applicable income tax information on
properties, including recently acquired natural gas and liquids
interests, is not readily available at other times during the year.As
a result, the company is not able to reconcile interim period-end 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.Year-end standardized
measure calculations are provided in the financial statement notes in
our annual reports on Form 10-K.
Chesapeake Energy Corporation is the second-largest producer of
natural gas, a Top 15 producer of oil and natural gas liquids and the
most active driller of new wells in the U.S.Headquartered
in Oklahoma City, the company's operations are focused on discovering
and developing unconventional natural gas and oil fields onshore in the
U.S.Chesapeake owns leading positions in the Barnett,
Haynesville, Bossier, Marcellus and Pearsall natural gas shale plays and
in the Granite Wash, Cleveland, Tonkawa, Mississippian, Bone Spring,
Avalon, Wolfcamp, Wolfberry, Eagle Ford, Niobrara, Bakken/Three Forks
and Utica unconventional liquids plays.The company has
also vertically integrated its operations and owns substantial
midstream, compression, drilling and oilfield service assets.Chesapeake′s
stock is listed on the New York Stock Exchange under the symbol CHK.Further information is available at www.chk.com
where Chesapeake routinely posts announcements, updates, events,
investor information, presentations and press releases.
| CHESAPEAKE ENERGY CORPORATION | |||||||||||||||
| CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | |||||||||||||||
| ($ in millions, except per-share and unit data) | |||||||||||||||
| (unaudited) | |||||||||||||||
| THREE MONTHS ENDED: | June 30, | June 30, | |||||||||||||
| 2011 | 2010 | ||||||||||||||
| $ | $/mcfe | $ | $/mcfe | ||||||||||||
| REVENUES: | |||||||||||||||
| Natural gas and liquids sales | 1,792 | 6.46 | 1,161 | 4.57 | |||||||||||
| Marketing, gathering and compression sales | 1,404 | 5.06 | 793 | 3.13 | |||||||||||
| Service operations revenue | 122 | 0.44 | 58 | 0.23 | |||||||||||
| Total Revenues | 3,318 | 11.96 | 2,012 | 7.93 | |||||||||||
| OPERATING COSTS: | |||||||||||||||
| Production expenses | 262 | 0.94 | 213 | 0.84 | |||||||||||
| Production taxes | 46 | 0.17 | 37 | 0.15 | |||||||||||
| General and administrative expenses | 130 | 0.46 | 106 | 0.41 | |||||||||||
| Marketing, gathering and compression expenses | 1,366 | 4.92 | 763 | 3.01 | |||||||||||
| Service operations expense | 92 | 0.33 | 53 | 0.21 | |||||||||||
| Natural gas and liquids depreciation, depletion and amortization | 366 | 1.32 | 340 | 1.34 | |||||||||||
| Depreciation and amortization of other assets | 63 | 0.23 | 53 | 0.21 | |||||||||||
| Losses on sales of other property and equipment | 4 | 0.02 | ? | ? | |||||||||||
| Other impairments | 4 | 0.02 | ? | ? | |||||||||||
| Total Operating Costs | 2,333 | 8.41 | 1,565 | 6.17 | |||||||||||
| INCOME FROM OPERATIONS | 985 | 3.55 | 447 | 1.76 | |||||||||||
| OTHER INCOME (EXPENSE): | |||||||||||||||
| Interest (expense) income | (25 | ) | (0.09 | ) | 16 | 0.06 | |||||||||
| Earnings from equity investees | 47 | 0.17 | 27 | 0.11 | |||||||||||
| Losses on purchases or exchanges of debt | (174 | ) | (0.63 | ) | (69 | ) | (0.27 | ) | |||||||
| Other income (expense) | 2 | 0.01 | (7 | ) | (0.03 | ) | |||||||||
| Total Other Income (Expense) | (150 | ) | (0.54 | ) | (33 | ) | (0.13 | ) | |||||||
| INCOME BEFORE INCOME TAXES | 835 | 3.01 | 414 | 1.63 | |||||||||||
| INCOME TAX EXPENSE: | |||||||||||||||
| Current income taxes | 6 | 0.02 | 5 | 0.02 | |||||||||||
| Deferred income taxes | 319 | 1.15 | 154 | 0.61 | |||||||||||
| Total Income Tax Expense | 325 | 1.17 | 159 | 0.63 | |||||||||||
| NET INCOME | 510 | 1.84 | 255 | 1.00 | |||||||||||
| Preferred stock dividends | (43 | ) | (0.16 | ) | (20 | ) | (0.07 | ) | |||||||
| NET INCOME AVAILABLE TO COMMON STOCKHOLDERS | 467 | 1.68 | 235 | 0.93 | |||||||||||
| EARNINGS PER COMMON SHARE: | |||||||||||||||
| Basic | $ | 0.74 | $ | 0.37 | |||||||||||
| Diluted | $ | 0.68 | $ | 0.37 | |||||||||||
| WEIGHTED AVERAGE COMMON AND COMMON | |||||||||||||||
| EQUIVALENT SHARES OUTSTANDING (in millions) | |||||||||||||||
| Basic | 635 | 631 | |||||||||||||
| Diluted | 751 | 635 | |||||||||||||
| CHESAPEAKE ENERGY CORPORATION | ||||||||||||||||
| CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS | ||||||||||||||||
| ($ in millions, except per-share and unit data) | ||||||||||||||||
| (unaudited) | ||||||||||||||||
| SIX MONTHS ENDED: | June 30, | June 30, | ||||||||||||||
| 2011 | 2010 | |||||||||||||||
| $ | $/mcfe | $ | $/mcfe | |||||||||||||
| REVENUES: | ||||||||||||||||
| Natural gas and liquids sales | 2,286 | 4.10 | 3,059 | 6.29 | ||||||||||||
| Marketing, gathering and compression sales | 2,421 | 4.35 | 1,637 | 3.36 | ||||||||||||
| Service operations revenue | 223 | 0.40 | 114 | 0.24 | ||||||||||||
| Total Revenues | 4,930 | 8.85 | 4,810 | 9.89 | ||||||||||||
| OPERATING COSTS: | ||||||||||||||||
| Production expenses | 500 | 0.90 | 421 | 0.86 | ||||||||||||
| Production taxes | 91 | 0.16 | 85 | 0.18 | ||||||||||||
| General and administrative expenses | 259 | 0.46 | 215 | 0.44 | ||||||||||||
| Marketing, gathering and compression expenses | 2,352 | 4.22 | 1,578 | 3.24 | ||||||||||||
| Service operations expense | 169 | 0.30 | 102 | 0.21 | ||||||||||||
| Natural gas and liquids depreciation, depletion and amortization | 724 | 1.30 | 647 | 1.33 | ||||||||||||
| Depreciation and amortization of other assets | 131 | 0.24 | 103 | 0.21 | ||||||||||||
| Gains on sales of other property and equipment | (1 | ) | ? | ? | ? | |||||||||||
| Other impairments | 4 | 0.01 | ? | ? | ||||||||||||
| Total Operating Costs | 4,229 | 7.59 | 3,151 | 6.47 | ||||||||||||
| INCOME FROM OPERATIONS | 701 | 1.26 | 1,659 | 3.42 | ||||||||||||
| OTHER INCOME (EXPENSE): | ||||||||||||||||
| Interest expense | (33 | ) | (0.06 | ) | (9 | ) | (0.02 | ) | ||||||||
| Earnings from equity investees | 72 | 0.13 | 39 | 0.08 | ||||||||||||
| Losses on purchases or exchanges of debt | (176 | ) | (0.32 | ) | (71 | ) | (0.15 | ) | ||||||||
| Other income (expense) | 5 | 0.01 | (4 | ) | (0.01 | ) | ||||||||||
| Total Other Income (Expense) | (132 | ) | (0.24 | ) | (45 | ) | (0.10 | ) | ||||||||
| INCOME BEFORE INCOME TAXES | 569 | 1.02 | 1,614 | 3.32 | ||||||||||||
| INCOME TAX EXPENSE: | ||||||||||||||||
| Current income taxes | 12 | 0.02 | 5 | 0.01 | ||||||||||||
| Deferred income taxes | 210 | 0.38 | 616 | 1.27 | ||||||||||||
| Total Income Tax Expense | 222 | 0.40 | 621 | 1.28 | ||||||||||||
| NET INCOME | 347 | 0.62 | 993 | 2.04 | ||||||||||||
| Preferred stock dividends | (85 | ) | (0.15 | ) | (25 | ) | (0.05 | ) | ||||||||
| NET INCOME AVAILABLE TO COMMON STOCKHOLDERS | 262 | 0.47 | 968 | 1.99 | ||||||||||||
| EARNINGS PER COMMON SHARE: | ||||||||||||||||
| Basic | $ | 0.41 | $ | 1.54 | ||||||||||||
| Diluted | $ | 0.41 | $ | 1.49 | ||||||||||||
| WEIGHTED AVERAGE COMMON AND COMMON | ||||||||||||||||
| EQUIVALENT SHARES OUTSTANDING (in millions) | ||||||||||||||||
| Basic | 635 | 630 | ||||||||||||||
| Diluted | 645 | 665 | ||||||||||||||
| CHESAPEAKE ENERGY CORPORATION | ||||||
| CONDENSED CONSOLIDATED BALANCE SHEETS | ||||||
| ($ in millions) | ||||||
| (unaudited) | ||||||
| June 30, | December 31, | |||||
| 2011 | 2010 | |||||
| Cash and cash equivalents | $ | 109 | $ | 102 | ||
| Other current assets | 3,017 | 3,164 | ||||
| Total Current Assets | 3,126 | 3,266 | ||||
| Property and equipment (net) | 32,052 | 32,378 | ||||
| Other assets | 1,478 | 1,535 | ||||
| Total Assets | $ | 36,656 | $ | 37,179 | ||
| Current liabilities | $ | 5,728 | $ | 4,490 | ||
| Long-term debt, net of discounts (a) | 10,047 | 12,640 | ||||
| Asset retirement obligations | 305 | 301 | ||||
| Other long-term liabilities | 2,611 | 2,100 | ||||
| Deferred tax liability | 2,482 | 2,384 | ||||
| Total Liabilities | 21,173 | 21,915 | ||||
| Stockholders′ Equity | 15,483 | 15,264 | ||||
| Total Liabilities & Stockholders' Equity | $ | 36,656 | $ | 37,179 | ||
| Common Shares Outstanding (in millions) | 658 | 654 | ||||
| CHESAPEAKE ENERGY CORPORATION | ||||||||||||
| CAPITALIZATION | ||||||||||||
| ($ in millions) | ||||||||||||
| (unaudited) | ||||||||||||
| June 30, | % of Total Book | December 31, | % of Total Book | |||||||||
| 2011 | Capitalization | 2010 | Capitalization | |||||||||
| Total debt, net of cash (a) | $ | 9,938 | 39 | % | $ | 12,538 | 45 | % | ||||
| Stockholders' equity | 15,483 | 61 | % | 15,264 | 55 | % | ||||||
| Total | $ | 25,421 | 100 | % | $ | 27,802 | 100 | % | ||||
(a) | At June 30, 2011, the company had $1.710 billion of borrowings under its $4.0 billion corporate revolving bank credit facility and $104.2 million of borrowings under its $600 million midstream revolving bank credit facility. |
| CHESAPEAKE ENERGY CORPORATION | ||||||||||
| RECONCILIATION OF 2011 ADDITIONS TO NATURAL GAS AND LIQUIDS PROPERTIES | ||||||||||
| BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT JUNE 30, 2011 | ||||||||||
| ($ in millions, except per-unit data) | ||||||||||
| (unaudited) | ||||||||||
| Proved Reserves | ||||||||||
| Cost | Bcfe (a) | $/Mcfe | ||||||||
| Drilling and completion costs(b) | $ | 3,427 |
| (c) | 1.29 | |||||
| Acquisition of proved properties | 35 | 28 | 1.26 | |||||||
| Sale of proved properties | (2,613 | ) | (2,760 | ) | 0.95 | |||||
| Drilling and completion costs, net of proved property divestitures | 849 | (80 | ) | (10.61 | ) | |||||
| Revisions ? price | ? | (5 | ) | ? | ||||||
| Acquisition of unproved properties | 1,990 | ? | ? | |||||||
| Sale of unproved properties | (3,478 | ) | ? | ? | ||||||
| Net unproved properties acquisition | (1,488 | ) | ? | ? | ||||||
| Capitalized interest on unproved properties | 379 | ? | ? | |||||||
| Geological and geophysical costs | 103 | ? | ? | |||||||
| Capitalized interest and geological and geophysical costs | 482 | ? | ? | |||||||
| Subtotal | (157 | ) | (85 | ) | 1.84 | |||||
| Asset retirement obligations and other | (5 | ) | ? | ? | ||||||
| Total costs | $ | (162 | ) | (85 | ) | 1.91 | ||||
| CHESAPEAKE ENERGY CORPORATION | ||||
| ROLL-FORWARD OF PROVED RESERVES | ||||
| SIX MONTHS ENDED JUNE 30, 2011 | ||||
| BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT JUNE 30, 2011 | ||||
| (unaudited) | ||||
| Bcfe(a) | ||||
| Beginning balance, 01/01/11 | 17,096 | |||
| Production | (557 | ) | ||
| Acquisitions | 28 | |||
| Divestitures | (2,760 | ) | ||
| Revisions ? changes to previous estimates | 145 | |||
| Revisions ? price | (5 | ) | ||
| Extensions and discoveries | 2,507 | |||
| Ending balance, 06/30/11 | 16,454 | |||
| Proved reserves growth rate | (4 | )% | ||
| Proved developed reserves | 8,922 | |||
| Proved developed reserves percentage | 54 | % | ||
| PV-10 ($ in billions) (a) | $ | 16.4 | ||
(a) | Reserve volumes and PV-10 value estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of June 30, 2011, of $4.21 per mcf of natural gas and $89.86 per bbl of oil, before field differential adjustments. | |
(b) | Net of drilling and completion carries of $1.129 billion associated with the Statoil, Total, CNOOC-Eagle Ford and CNOOC-Niobrara joint venture agreements. | |
(c) | Includes 145 bcfe of positive revisions resulting from changes to previous estimates and excludes downward revisions of 5 bcfe resulting from lower natural gas prices using the average first-day-of-the-month price for the twelve months ended June 30, 2011, compared to the twelve months ended December 31, 2010. |
| CHESAPEAKE ENERGY CORPORATION | ||||||||||
| RECONCILIATION OF 2011 ADDITIONS TO NATURAL GAS AND LIQUIDS PROPERTIES | ||||||||||
| BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT JUNE 30, 2011 | ||||||||||
| ($ in millions, except per-unit data) | ||||||||||
| (unaudited) | ||||||||||
| Proved Reserves | ||||||||||
| Cost | Bcfe (a) | $/Mcfe | ||||||||
| Drilling and completion costs (b) | $ | 3,427 |
| (c) |
| |||||
| Acquisition of proved properties | 35 | 28 | 1.26 | |||||||
| Sale of proved properties | (2,613 | ) | (2,760 | ) | 0.95 | |||||
| Drilling and completion costs, net of proved property divestitures | 849 | (17 | ) | (49.94 | ) | |||||
| Revisions ? price | ? | 173 | ? | |||||||
| Acquisition of unproved properties | 1,990 | ? | ? | |||||||
| Sale of unproved properties | (3,478 | ) | ? | ? | ||||||
| Net unproved properties acquisition | (1,488 | ) | ? | ? | ||||||
| Capitalized interest on unproved properties | 379 | ? | ? | |||||||
| Geological and geophysical costs | 103 | ? | ? | |||||||
| Capitalized interest and geological and geophysical costs | 482 | ? | ? | |||||||
| Subtotal | (157 | ) | 156 | (1.00 | ) | |||||
| Asset retirement obligations and other | (5 | ) | ? | ? | ||||||
| Total costs | $ | (162 | ) | 156 | (1.04 | ) | ||||
| CHESAPEAKE ENERGY CORPORATION | ||||
| ROLL-FORWARD OF PROVED RESERVES | ||||
| SIX MONTHS ENDED JUNE 30, 2011 | ||||
| BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT JUNE 30, 2011 | ||||
| (unaudited) | ||||
| Bcfe (a) | ||||
| Beginning balance, 01/01/11 | 17,605 | |||
| Production | (557 | ) | ||
| Acquisitions | 28 | |||
| Divestitures | (2,760 | ) | ||
| Revisions ? changes to previous estimates | 446 | |||
| Revisions ? price | 173 | |||
| Extensions and discoveries | 2,269 | |||
| Ending balance, 06/30/11 | 17,204 | |||
| Proved reserves growth rate | (2 | )% | ||
| Proved developed reserves | 9,372 | |||
| Proved developed reserves percentage | 54 | % | ||
| PV-10 ($ in billions) (a) | $ | 27.4 | ||
| Reserve volumes and PV-10 value estimated using SEC reserve recognition standards and 10-year average NYMEX strip prices as of June 30, 2011 of $5.80 per mcf of natural gas and $100.24 per bbl of oil, before field differential adjustments. Futures prices, such as the 10-year average NYMEX strip prices, represent an unbiased consensus estimate by market participants about the likely prices to be received for our future production. Chesapeake uses such forward-looking market-based data in developing its drilling plans, assessing its capital expenditure needs and projecting future cash flows. Chesapeake believes these prices are better indicators of the likely economic producibility of proved reserves than the trailing 12-month average price required by the SEC's reporting rule. | |
(b) | Net of drilling and completion carries of $1.129 billion associated with the Statoil, Total, CNOOC-Eagle Ford and CNOOC-Niobrara joint venture agreements. | |
(c) | Includes 446 bcfe of positive revisions resulting from changes to previous estimates and excludes positive revisions of 173 bcfe resulting from higher natural gas and oil prices using 10-year average NYMEX strip prices as of June 30, 2011, compared to NYMEX strip prices as of December 31, 2010. |
| CHESAPEAKE ENERGY CORPORATION | ||||||||||||||||||
| SUPPLEMENTAL DATA ? NATURAL GAS AND LIQUIDS SALES AND INTEREST EXPENSE | ||||||||||||||||||
| (unaudited) | ||||||||||||||||||
| THREE MONTHS ENDED | SIX MONTHS ENDED | |||||||||||||||||
| JUNE 30, | JUNE 30, | |||||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||||
| Natural Gas and Liquids Sales ($ in millions): | ||||||||||||||||||
Natural gas sales | $ | 764 | $ | 733 | $ | 1,552 | $ | 1,676 | ||||||||||
Natural gas derivatives ? realized gains (losses) | 452 | 552 | 958 | 931 | ||||||||||||||
Natural gas derivatives ? unrealized gains (losses) | (115 | ) | (195 | ) | (665 | ) | 219 | |||||||||||
Total Natural Gas Sales | 1,101 | 1,090 | 1,845 | 2,826 | ||||||||||||||
Liquids sales | 514 | 251 | 913 | 493 | ||||||||||||||
Oil derivatives ? realized gains (losses) | (45 | ) | 21 | (62 | ) | 41 | ||||||||||||
Oil derivatives ? unrealized gains (losses) | 222 | (201 | ) | (410 | ) | (301 | ) | |||||||||||
Total Liquids Sales | 691 | 71 | 441 | 233 | ||||||||||||||
Total Natural Gas and Liquids Sales | $ | 1,792 | $ | 1,161 | $ | 2,286 | $ | 3,059 | ||||||||||
| Average Sales Price ? excluding gains (losses) on derivatives: | ||||||||||||||||||
Natural gas ($ per mcf) | $ | 3.26 | $ | 3.23 | $ | 3.25 | $ | 3.84 | ||||||||||
Liquids ($ per bbl) | $ | 71.46 | $ | 56.58 | $ | 69.00 | $ | 59.38 | ||||||||||
Natural gas equivalent ($ per mcfe) | $ | 4.61 | $ | 3.88 | $ | 4.43 | $ | 4.46 | ||||||||||
| Average Sales Price ? excluding unrealized gains (losses) on derivatives: | ||||||||||||||||||
Natural gas ($ per mcf) | $ | 5.19 | $ | 5.66 | $ | 5.25 | $ | 5.97 | ||||||||||
Liquids ($ per bbl) | $ | 65.23 | $ | 61.43 | $ | 64.30 | $ | 64.35 | ||||||||||
Natural gas equivalent ($ per mcfe) | $ | 6.07 | $ | 6.14 | $ | 6.03 | $ | 6.46 | ||||||||||
| Interest Expense (Income) ($ in millions): | ||||||||||||||||||
Interest (a) | $ | 6 | $ | 35 | $ | 15 | $ | 90 | ||||||||||
Derivatives ? realized (gains) losses | 13 | (2 | ) | 6 | (4 | ) | ||||||||||||
Derivatives ? unrealized (gains) losses | 6 | (49 | ) | 12 | (77 | ) | ||||||||||||
Total Interest Expense (Income) | $ | 25 | $ | (16 | ) | $ | 33 | $ | 9 | |||||||||
(a) | Net of amounts capitalized. |
| CHESAPEAKE ENERGY CORPORATION | ||||||||
| CONDENSED CONSOLIDATED CASH FLOW DATA | ||||||||
| ($ in millions) | ||||||||
| (unaudited) | ||||||||
| THREE MONTHS ENDED: | June 30, | June 30, | ||||||
| 2011 | 2010 | |||||||
| Beginning cash | $ | 849 | $ | 516 | ||||
| Cash provided by operating activities | $ | 1,375 | $ | 1,795 | ||||
| Cash flows from investing activities: | ||||||||
Exploration and development of natural gas and liquids | $ | (1,703 | ) | $ | (1,311 | ) | ||
| Acquisitions of proved and unproved properties | (1,271 | ) | (1,825 | ) | ||||
| Divestitures of proved and unproved properties | 991 | 709 | ||||||
| Investments, net | 208 | (103 | ) | |||||
| Other property and equipment, net | (673 | ) | (150 | ) | ||||
| Other | (18 | ) | (38 | ) | ||||
| Total cash used in investing activities | $ | (2,466 | ) | $ | (2,718 | ) | ||
| Cash provided by financing activities | $ | 351 | $ | 1,008 | ||||
| Ending cash | $ | 109 | $ | 601 | ||||
| SIX MONTHS ENDED: | June 30, | June 30, | ||||||
| 2011 | 2010 | |||||||
| Beginning cash | $ | 102 | $ | 307 | ||||
| Cash provided by operating activities | $ | 2,093 | $ | 2,978 | ||||
| Cash flows from investing activities: | ||||||||
Exploration and development of natural gas and liquids | $ | (3,395 | ) | $ | (2,331 | ) | ||
| Acquisitions of proved and unproved properties | (2,529 | ) | (2,855 | ) | ||||
| Divestitures of proved and unproved properties | 6,173 | 1,933 | ||||||
| Investments, net | 212 | (109 | ) | |||||
| Other property and equipment, net | (676 | ) | (373 | ) | ||||
| Other | (25 | ) | 3 | |||||
| Total cash used in investing activities | $ | (240 | ) | $ | (3,732 | ) | ||
| Cash provided by (used in) financing activities | $ | (1,846 | ) | $ | 1,048 | |||
| Ending cash | $ | 109 | $ | 601 | ||||
| CHESAPEAKE ENERGY CORPORATION | ||||||||||||
| RECONCILIATION OF OPERATING CASH FLOW AND EBITDA | ||||||||||||
| ($ in millions) | ||||||||||||
| (unaudited) | ||||||||||||
| THREE MONTHS ENDED: | June 30, | March 31, | June 30, | |||||||||
| 2011 | 2011 | 2010 | ||||||||||
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 1,375 | $ | 718 | $ | 1,795 | ||||||
| Changes in assets and liabilities | (168 | ) | 663 | (491 | ) | |||||||
| OPERATING CASH FLOW (a) | $ | 1,207 | $ | 1,381 | $ | 1,304 | ||||||
| THREE MONTHS ENDED: | June 30, | March 31, | June 30, | |||||||||
| 2011 | 2011 | 2010 | ||||||||||
| NET INCOME (LOSS) | $ | 510 | $ | (162 | ) | $ | 255 | |||||
| Income tax expense (benefit) | 325 | (104 | ) | 159 | ||||||||
| Interest expense (income) | 25 | 7 | (16 | ) | ||||||||
| Depreciation and amortization of other assets | 63 | 68 | 53 | |||||||||
Natural gas and liquids depreciation, depletion and Amortization | 366 | 358 | 340 | |||||||||
| EBITDA (b) | $ | 1,289 | $ | 167 | $ | 791 | ||||||
| THREE MONTHS ENDED: | June 30, | March 31, | June 30, | |||||||||
| 2011 | 2011 | 2010 | ||||||||||
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 1,375 | $ | 718 | $ | 1,795 | ||||||
| Changes in assets and liabilities | (168 | ) | 663 | (491 | ) | |||||||
| Interest expense (income) | 25 | 7 | (16 | ) | ||||||||
| Unrealized gains (losses) on natural gas and oil derivatives | 106 | (1,182 | ) | (396 | ) | |||||||
| Gains (losses) on equity investments | 19 | 5 | (48 | ) | ||||||||
| Stock-based compensation | (39 | ) | (40 | ) | (35 | ) | ||||||
| Other items | (29 | ) | (4 | ) | (18 | ) | ||||||
| EBITDA (b) | $ | 1,289 | $ | 167 | $ | 791 | ||||||
(a) | 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 a natural gas and oil 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 natural gas and oil 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. | |
(b) | Ebitda represents net income (loss) before income tax expense, 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 agreements and is used in the financial covenants in our bank credit agreements. 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. |
| CHESAPEAKE ENERGY CORPORATION | ||||||||
| RECONCILIATION OF OPERATING CASH FLOW AND EBITDA | ||||||||
| ($ in millions) | ||||||||
| (unaudited) | ||||||||
| SIX MONTHS ENDED: | June 30, | June 30, | ||||||
| 2011 | 2010 | |||||||
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 2,093 | $ | 2,978 | ||||
| Changes in assets and liabilities | 495 | (414 | ) | |||||
| OPERATING CASH FLOW (a) | $ | 2,588 | $ | 2,564 | ||||
| SIX MONTHS ENDED: | June 30, | June 30, | ||||||
| 2011 | 2010 | |||||||
| NET INCOME | $ | 347 | $ | 993 | ||||
| Income tax expense | 222 | 621 | ||||||
| Interest expense | 33 | 9 | ||||||
| Depreciation and amortization of other assets | 131 | 103 | ||||||
| Natural gas and liquids depreciation, depletion and amortization | 724 | 647 | ||||||
| EBITDA (b) | $ | 1,457 | $ | 2,373 | ||||
| SIX MONTHS ENDED: | June 30, | June 30, | ||||||
| 2011 | 2010 | |||||||
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 2,093 | $ | 2,978 | ||||
| Changes in assets and liabilities | 495 | (414 | ) | |||||
| Interest expense | 33 | 9 | ||||||
| Unrealized losses on natural gas and oil derivatives | (1,075 | ) | (82 | ) | ||||
| Losses on equity investments | 24 | (35 | ) | |||||
| Stock-based compensation | (79 | ) | (67 | ) | ||||
| Other items | (34 | ) | (16 | ) | ||||
| EBITDA (b) | $ | 1,457 | $ | 2,373 | ||||
(a) | 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 a natural gas and oil 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 natural gas and oil 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. | |
(b) | Ebitda represents net income before income tax expense, 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 agreements and is used in the financial covenants in our bank credit agreements. 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. | |
CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF ADJUSTED
EBITDA
($ in millions)
(unaudited)
| June 30, | March 31, | June 30, | |||||||||
| THREE MONTHS ENDED: | 2011 | 2011 | 2010 | ||||||||
| EBITDA | $ | 1,289 | $ | 167 | $ | 791 | |||||
| Adjustments: | |||||||||||
| Unrealized (gains) losses on natural gas and oil derivatives | (106 | ) | 1,182 | 396 | |||||||
| Losses on purchases or exchanges of debt | 174 | 2 | 69 | ||||||||
(Gains) losses on sales of other property and equipment | 4 | (5 | ) | ? | |||||||
| Other impairments | 4 | ? | ? | ||||||||
| Adjusted EBITDA (a) | $ | 1,365 | $ | 1,346 | $ | 1,256 | |||||
(a) | 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: | |||
i. | Management uses adjusted ebitda to evaluate the company′s operational trends and performance relative to other natural gas and oil producing companies. | |||
ii. | Adjusted ebitda is more comparable to estimates provided by securities analysts. | |||
iii. | 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. | |||
| June 30, | June 30, | ||||||
| SIX MONTHS ENDED: | 2011 | 2010 | |||||
| EBITDA | $ | 1,457 | $ | 2,373 | |||
| Adjustments: | |||||||
| Unrealized losses on natural gas and oil derivatives | 1,075 | 82 | |||||
| Losses on purchases or exchanges of debt | 176 | 71 | |||||
| Gains on sales of other property and equipment | (1 | ) | ? | ||||
| Other impairments | 4 | ? | |||||
| Adjusted EBITDA (a) | $ | 2,711 | $ | 2,526 | |||
(a) | 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: | |||
i. | Management uses adjusted ebitda to evaluate the company′s operational trends and performance relative to other natural gas and oil producing companies. | |||
ii. | Adjusted ebitda is more comparable to estimates provided by securities analysts. | |||
iii. | 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. | |||
| CHESAPEAKE ENERGY CORPORATION | |||||||||||
| RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS | |||||||||||
| ($ in millions, except per-share data) | |||||||||||
| (unaudited) | |||||||||||
| June 30, | March 31, | June 30, | |||||||||
| THREE MONTHS ENDED: | 2011 | 2011 | 2010 | ||||||||
| Net income (loss) available to common stockholders | $ | 467 | $ | (205 | ) | $ | 235 | ||||
| Adjustments: | |||||||||||
| Unrealized (gains) losses on derivatives, net of tax | (61 | ) | 725 | 214 | |||||||
| Losses on purchases or exchanges of debt, net of tax | 106 | 1 | 42 | ||||||||
(Gains) losses on sales of other property and equipment, net of | 3 | (3 | ) | ? | |||||||
| Other impairments, net of tax | 2 | ? | ? | ||||||||
| Loss on foreign currency derivatives | 11 | ? | ? | ||||||||
| Adjusted net income available to common stockholders (a) | 528 | 518 | 491 | ||||||||
| Preferred stock dividends | 43 | 43 | 20 | ||||||||
| Total adjusted net income | $ | 571 | $ | 561 | $ | 511 | |||||
| Weighted average fully diluted shares outstanding (b) | 751 | 750 | 682 | ||||||||
| Adjusted earnings per share assuming dilution (a) | $ | 0.76 | $ | 0.75 | $ | 0.75 | |||||
(a) | Adjusted net income available to common stockholders 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: | |||
i. | Management uses adjusted net income available to common stockholders to evaluate the company′s operational trends and performance relative to other natural gas and oil producing companies. | |||
ii. | Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. | |||
iii. | 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. | |||
(b) | Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP. | |||
| CHESAPEAKE ENERGY CORPORATION | ||||||
| RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS | ||||||
| ($ in millions, except per-share data) | ||||||
| (unaudited) | ||||||
| June 30, | June 30, | |||||
| SIX MONTHS ENDED: | 2011 | 2010 | ||||
| Net income available to common stockholders | $ | 262 | $ | 968 | ||
| Adjustments: | ||||||
| Unrealized losses on derivatives, net of tax | 663 | 3 | ||||
| Losses on purchases or exchanges of debt, net of tax | 107 | 44 | ||||
| Other impairments, net of tax | 2 | ? | ||||
| Loss on foreign currency derivatives | 11 | ? | ||||
| Adjusted net income available to common stockholders (a) | 1,045 | 1,015 | ||||
| Preferred stock dividends | 85 | 25 | ||||
| Total adjusted net income | $ | 1,130 | $ | 1,040 | ||
| Weighted average fully diluted shares outstanding (b) | 751 | 665 | ||||
| Adjusted earnings per share assuming dilution (a) | $ | 1.51 | $ | 1.56 | ||
(a) | Adjusted net income available to common stockholders 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: | |||
i. | Management uses adjusted net income available to common stockholders to evaluate the company′s operational trends and performance relative to other natural gas and oil producing companies. | |||
ii. | Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. | |||
iii. | 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. | |||
(b) | Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP. | |||
SCHEDULE 'A?
CHESAPEAKE′S OUTLOOK AS OF JULY 28, 2011
Years Ending December 31, 2011 and 2012
Our policy is to periodically provide guidance on certain factors that
affect our future financial performance. As of July 28, 2011, we are
using the following key assumptions in our projections for 2011 and 2012.
The primary changes from our May 2, 2011 Outlook are in italicized
bold and are explained as follows:
1) Our production guidance has been updated;
2) Projected effects of changes in our hedging positions have been
updated;
3) Certain cost assumptions have been updated; and
4) Our cash flow projections have been updated, including increased
drilling and completion costs.
| Year Ending | Year Ending | |||
| 12/31/2011 | 12/31/2012 | |||
Estimated Production: | ||||
Natural gas ? bcf | 970 ? 990 | 1,000 ? 1,040 | ||
Liquids ? mbbls | 31,000 ? 33,000 | 53,000 ? 57,000 | ||
Natural gas equivalent ? bcfe | 1,156 ? 1,188 | 1,318 ? 1,382 | ||
Daily natural gas equivalent midpoint ? mmcfe | 3,200 | 3,700 | ||
Year over year (YOY) estimated production increase | 12 ? 15% | 12 - 18% | ||
YOY estimated production increase excluding asset sales | 23 ? 26% | 13 - 19% | ||
NYMEX Price(a) (for calculation of realized hedging effects only): | ||||
Natural gas - $/mcf | $4.34 | $5.50 | ||
Oil - $/bbl | $99.15 | $100.00 | ||
Estimated Realized Hedging Effects (based on assumed NYMEX prices above): | ||||
Natural gas - $/mcf | $1.60 | $0.28 | ||
Liquids - $/bbl | $(3.65) | $(3.93) | ||
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices: | ||||
Natural gas - $/mcf | $0.90 ? $1.10 | $0.90 ? $1.10 | ||
Liquids - $/bbl(b) | $30.00 ? $35.00 | $30.00 ? $35.00 | ||
Operating Costs per Mcfe of Projected Production: | ||||
Production expense | $0.90 ? 1.00 | $0.90 ? 1.00 | ||
Production taxes (~ 5% of O&G revenues) | $0.25 ? 0.30 | $0.25 ? 0.30 | ||
General and administrative(c) | $0.36 ? 0.41 | $0.36 ? 0.41 | ||
Stock-based compensation (non-cash) | $0.07 ? 0.09 | $0.07 ? 0.09 | ||
DD&A of natural gas and liquids assets | $1.25 ? 1.40 | $1.25 ? 1.40 | ||
Depreciation of other assets | $0.20 ? 0.25 | $0.20 ? 0.25 | ||
Interest expense(d) | $0.05 ? 0.10 | $0.05 ? 0.10 | ||
Other Income per Mcfe: | ||||
Marketing, gathering and compression net margin | $0.12 ? 0.14 | $0.12 ? 0.14 | ||
Service operations net margin | $0.09 ? 0.11 | $0.15 ? 0.20 | ||
Other income (including equity investments) | $0.06 ? 0.08 | $0.06 ? 0.08 | ||
Book Tax Rate | 39% | 39% | ||
| ||||
Equivalent Shares Outstanding (in millions): | ||||
Basic | 640 ? 645 | 647 ? 652 | ||
Diluted | 750 ? 755 | 760 ? 765 | ||
Operating cash flow before changes in assets and liabilities(e)(f) | $5,100 ? 5,200 | $6,000 ? 6,800 | ||
Drilling and completion costs, net of joint venture carries | ($6,000 ? 6,500) | ($6,000 ? 6,500) | ||
Note: please refer to footnotes on following page
a) NYMEX natural gas prices have been updated for actual contract prices
through July 2011 and NYMEX oil prices have been updated for actual
contract prices through June 2011.
b) Differentials include effects of natural gas liquids.
c) Excludes expenses associated with noncash stock compensation.
d) Does not include gains or losses on interest rate derivatives.
e) A non-GAAP financial measure. We are unable to provide a
reconciliation to projected cash provided by operating activities, the
most comparable GAAP measure, because of uncertainties associated with
projecting future changes in assets and liabilities.
f) Assumes NYMEX prices of $4.00 to $5.00 per mcf and $100.00 per bbl in
2011 and $5.00 to $6.00 per mcf and $100.00 per bbl in 2012.
Commodity Hedging Activities
Chesapeake enters into natural gas and oil derivative transactions in
order to mitigate a portion of its exposure to adverse market changes in
natural gas and oil prices. The company utilizes the following types of
natural gas and oil derivative instruments:
1) | Swaps: Chesapeake receives a fixed | |
2) | Call options: Chesapeake sells call | |
3) | Put options: Chesapeake receives a | |
4) | Knockout swaps: Chesapeake receives a | |
5) | Basis protection swaps: These |
All of our derivative instruments are net settled based on the
difference between the fixed-price payment and the floating-price
payment, resulting in a net amount due to or from the counterparty.
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. Since the latter half of
2009 through June 2011, the company has taken advantage of attractive
strip prices in 2012 through 2017 and sold natural gas and oil call
options to its counterparties in exchange for 2010, 2011 and 2012
natural gas swaps with strike prices above the then current market
price. This effectively allowed the company to sell out-year volatility
through call options at terms acceptable to Chesapeake in exchange for
natural gas swaps with fixed prices in excess of the market price at the
time.
Gains or losses from commodity derivative transactions are reflected as
adjustments to natural gas and liquids sales. All realized gains
(losses) from natural gas and oil derivatives are included in natural
gas and liquids sales in the month of related production. In accordance
with generally accepted accounting principles, changes in the fair value
of derivative instruments designated as cash flow hedges, to the extent
they are effective in offsetting cash flows attributable to the hedged
risk, are recorded in accumulated other comprehensive income until the
hedged item is recognized in earnings as the physical transactions being
hedged occur. Any change in fair value resulting from ineffectiveness is
currently recognized in natural gas and liquids sales as unrealized
gains (losses). Realized gains (losses) are comprised of settled trades
related to the production periods being reported. Unrealized gains
(losses) are comprised of both temporary fluctuations in the
mark-to-market values of nonqualifying trades and settled values of
nonqualifying derivatives related to future production periods.
At July 28, 2011, the company has the following open natural gas swaps
in place for 2011 and 2012. In addition, the company currently has $630
million of net hedging gains related to closed natural gas contracts and
premiums collected on call options for future production periods.
| Open Swaps (Bcf) | Avg. NYMEX
| Forecasted
| Open Swap
| Total Gains
| Total Gains from
| |||||||||||
Q3 2011 | 200 | $ | 4.81 | $ | 285 | ||||||||||||
Q4 2011 | 197 | $ | 4.78 | $ | 250 | ||||||||||||
Total 2011 | 397 | $ | 4.79 | 500 | 79 | % | $ | 535 | $ | 1.07 | |||||||
Total 2012 | 94 | $ | 6.12 | 1,020 | 9 | % | $ | 248 | $ | 0.24 | |||||||
Total 2013 | $ | 21 | |||||||||||||||
Total 2014 | $ | (32 | ) | ||||||||||||||
Total 2015 | $ | (46 | ) | ||||||||||||||
Total 2016 ? 2020 | $ | (96 | ) | ||||||||||||||
The company currently has the following natural gas written call options
in place for 2011 through 2020:
Call Options (Bcf) | Avg. NYMEX
| Forecasted
| Call Options
| |||||||
Total 2012 | 161 | $ | 6.54 | 1,020 | 16 | % | ||||
Total 2013 | 415 | $ | 6.44 | |||||||
Total 2014 | 330 | $ | 6.43 | |||||||
Total 2015 | 226 | $ | 6.31 | |||||||
Total 2016 ? 2020 | 393 | $ | 7.93 | |||||||
The company has the following natural gas basis protection swaps in
place for 2011 through 2022:
Non-Appalachia | Appalachia | |||||||||
Volume (Bcf) | Avg. NYMEX less | Volume (Bcf) | Avg. NYMEX plus | |||||||
2011 | 26 | $ | 0.82 | 25 | $ | 0.14 | ||||
2012 | 51 | $ | 0.78 | ? | $ | ? | ||||
2013 - 2022 | 29 | $ | 0.69 | ? | $ | ? | ||||
Totals | 106 | $ | 0.77 | 25 | $ | 0.14 | ||||
At July 28, 2011, the company has the following open crude oil swaps in
place for 2011 and 2012. In addition, the company has $60 million of net
hedging gains related to closed crude oil contracts and premiums
collected on call options for future production periods.
Open
| Avg. NYMEX
| Forecasted
| Open Swap
| Total Gains
| Total Gains (Losses) from
| |||||||||||||
Q3 2011 | 828 | $ | 100.90 | ? | ? | $ | (17 | ) | ||||||||||
Q4 2011 | 828 | $ | 100.90 | ? | ? | $ | (17 | ) | ||||||||||
Total 2011(a) | 1,656 | $ | 100.90 | 19,000 | 9 | % | $ | (34 | ) | $ | (1.80 | ) | ||||||
Total 2012(a) | 1,830 | $ | 105.03 | 55,000 | 3 | % | $ | 82 | $ | 1.48 | ||||||||
Total 2013 | $ | 6 | ||||||||||||||||
Total 2014 | $ | (197 | ) | |||||||||||||||
Total 2015 | $ | 145 | ||||||||||||||||
Total 2016 ? 2020 | $ | 58 | ||||||||||||||||
(a) | Certain hedging contracts include knockout swaps with provisions limiting the counterparty′s exposure below prices of $60.00 covering 0.6 mmbbls in 2011 and 0.7 mmbbls in 2012. |
The company currently has the following crude oil written call options
in place for 2011 through 2017:
Call Options (mbbls) | Avg. NYMEX
| Forecasted
| Call Options
| |||||||
Q3 2011 | 1,840 | $ | 110.00 | |||||||
Q4 2011 | 1,840 | $ | 110.00 | |||||||
Total 2011 | 3,680 | $ | 110.00 | 19,000 | 19 | % | ||||
Total 2012 | 22,139 | $ | 87.93 | 55,000 | 40 | % | ||||
Total 2013 | 14,564 | $ | 87.20 | |||||||
Total 2014 | 8,707 | $ | 87.72 | |||||||
Total 2015 | 11,226 | $ | 92.00 | |||||||
Total 2016 ? 2017 | 14,424 | $ | 89.75 | |||||||
SCHEDULE 'B?
CHESAPEAKE′S OUTLOOK AS OF MAY 2, 2011
(PROVIDED
FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF JULY 28,
2011
Years Ending December 31, 2011 and 2012
Our policy is to periodically provide guidance on certain factors that
affect our future financial performance. As of May 2, 2011, we are using
the following key assumptions in our projections for 2011 and 2012.
The primary changes from our February 22, 2011 Outlook are in italicized
bold and are explained as follows:
1) Projected effects of changes in our hedging positions have been
updated;
2) Our NYMEX oil price assumptions for
gathering/marketing/transportation differentials have been updated;
3) Certain cost assumptions have been updated; and
4) Our cash flow projections have been updated, including increased
drilling and completion costs.
Note: Projected production volumes have incorporated the loss of
production volumes from the closed divestiture of the Fayetteville
assets and the anticipated closing of VPP #9 in the 2011 second quarter.
| Year Ending | Year Ending | |||
| 12/31/2011 | 12/31/2012 | |||
Estimated Production: | ||||
Natural gas ? bcf | 900 ? 930 | 960 ? 1,000 | ||
Oil ? mbbls | 32,000 ? 36,000 | 51,000 ? 57,000 | ||
Natural gas equivalent ? bcfe | 1,092 ? 1,146 | 1,266 ? 1,342 | ||
Daily natural gas equivalent midpoint ? mmcfe | 3,065 | 3,560 | ||
Year over year (YOY) estimated production increase | 6 ? 11% | 13 - 20% | ||
YOY estimated production increase excluding asset sales | 17 ? 22% | 17 - 24% | ||
NYMEX Price(a) (for calculation of realized hedging effects only): | ||||
Natural gas - $/mcf | $4.38 | $5.50 | ||
Oil - $/bbl | $98.53 | $100.00 | ||
Estimated Realized Hedging Effects (based on assumed NYMEX prices above): | ||||
Natural gas - $/mcf | $1.60 | $0.10 | ||
Oil - $/bbl | $(2.31) | $(4.20) | ||
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices: | ||||
Natural gas - $/mcf | $0.90 ? $1.10 | $0.90 ? $1.10 | ||
Oil - $/bbl(b) | $30.00 ? $35.00 | $30.00 ? $35.00 | ||
Operating Costs per Mcfe of Projected Production: | ||||
Production expense | $0.90 ? 1.00 | $0.90 ? 1.00 | ||
Production taxes (~ 5% of O&G revenues) | $0.25 ? 0.30 | $0.25 ? 0.30 | ||
General and administrative(c) | $0.34 ? 0.39 | $0.34 ? 0.39 | ||
Stock-based compensation (non-cash) | $0.07 ? 0.09 | $0.07 ? 0.09 | ||
DD&A of natural gas and oil assets | $1.15 ? 1.30 | $1.15 ? 1.30 | ||
Depreciation of other assets | $0.20 ? 0.25 | $0.20 ? 0.25 | ||
Interest expense(d) | $0.05 ? 0.10 | $0.05 ? 0.10 | ||
Other Income per Mcfe: | ||||
Marketing, gathering and compression net margin | $0.09 ? 0.11 | $0.09 ? 0.11 | ||
Service operations net margin | $0.06 ? 0.08 | $0.08 ? 0.10 | ||
Other income (including equity investments) | $0.06 ? 0.08 | $0.06 ? 0.08 | ||
Book Tax Rate | 39% | 39% | ||
| ||||
Equivalent Shares Outstanding (in millions): | ||||
Basic | 640 ? 645 | 647 ? 652 | ||
Diluted | 750 ? 755 | 760 ? 765 | ||
Operating cash flow before changes in assets and liabilities(e)(f) | $5,000 ? 5,100 | $5,500 ? 6,200 | ||
Drilling and completion costs, net of joint venture carries | ($5,500 ? 6,000) | ($5,500 ? 6,000) | ||
Note: please refer to footnotes on following page
a) NYMEX natural gas prices have been updated for actual contract prices
through April 2011 and NYMEX oil prices have been updated for actual
contract prices through March 2011.
b) Differentials include effects of natural gas liquids.
c) Excludes expenses associated with noncash stock compensation.
d) Does not include gains or losses on interest rate derivatives.
e) A non-GAAP financial measure. We are unable to provide a
reconciliation to projected cash provided by operating activities, the
most comparable GAAP measure, because of uncertainties associated with
projecting future changes in assets and liabilities.
f) Assumes NYMEX prices of $4.00 to $5.00 per mcf and $100.00 per bbl in
2011 and $5.00 to $6.00 per mcf and $100.00 per bbl in 2012.
Commodity Hedging Activities
The company utilizes hedging strategies to hedge the price of a portion
of its future natural gas and oil production. These strategies include:
1) | Swaps: Chesapeake receives a fixed | |
2) | Call options: Chesapeake sells call | |
3) | Put options: Chesapeake receives a | |
4) | Knockout swaps: Chesapeake receives a | |
5) | Basis protection swaps: These |
All of our derivative instruments are net settled based on the
difference between the fixed-price payment and the floating-price
payment, resulting in a net amount due to or from the counterparty.
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. Since the latter half of
2009 through May 2, 2011, the company has taken advantage of attractive
strip prices in 2012 through 2017 and sold natural gas and oil call
options to its counterparties in exchange for 2010, 2011 and 2012
natural gas swaps with strike prices above the then current market
price. This effectively allowed the company to sell out-year volatility
through call options at terms acceptable to Chesapeake in exchange for
straight natural gas swaps with strike prices in excess of the market
price for natural gas at that time.
Chesapeake enters into natural gas and oil derivative transactions in
order to mitigate a portion of its exposure to adverse market changes in
natural gas and oil prices. Accordingly, associated gains or losses from
the derivative transactions are reflected as adjustments to natural gas
and oil sales. All realized gains and losses from natural gas and oil
derivatives are included in natural gas and oil sales in the month of
related production. In accordance with generally accepted accounting
principles, changes in the fair value of derivative instruments
designated as cash flow hedges, to the extent they are effective in
offsetting cash flows attributable to the hedged risk, are recorded in
accumulated other comprehensive income until the hedged item is
recognized in earnings as the physical transactions being hedged occur.
Any change in fair value resulting from ineffectiveness is currently
recognized in natural gas and oil sales as unrealized gains (losses).
Realized gains (losses) are comprised of settled trades related to the
production periods being reported. Unrealized gains (losses) are
comprised of both temporary fluctuations in the mark-to-market values of
nonqualifying trades and settled values of nonqualifying derivatives
related to future production periods.
At May 2, 2011, the company has the following open natural gas swaps in
place for 2011 and 2012, excluding contracts that will be novated with
VPP #9. In addition, the company currently has $593 million of net
hedging gains related to closed natural gas contracts and premiums
collected on call options for future production periods.
| Open Swaps (Bcf) | Avg. NYMEX
| Forecasted
| Open Swap
| Total Gains
| Total Gains
| ||||||||||||
Q2 2011 | 203 | $ | 5.20 | $ | 276 | |||||||||||||
Q3 2011 | 195 | $ | 4.92 | $ | 226 | |||||||||||||
Q4 2011 | 198 | $ | 4.97 | $ | 185 | |||||||||||||
Total 2011 | 596 | $ | 5.03 | 675 | 88 | % | $ | 687 | $ | 1.02 | ||||||||
Total 2012 | 188 | $ | 6.17 | 980 | 19 | % | $ | (9 | ) | $ | (0.01 | ) | ||||||
Total 2013 | $ | 11 | ||||||||||||||||
Total 2014 | $ | (38 | ) | |||||||||||||||
Total 2015 | $ | (43 | ) | |||||||||||||||
Total 2016 ? 2020 | $ | (15 | ) | |||||||||||||||
The company currently has the following natural gas written call options
in place for 2011 through 2020:
Call Options (Bcf) | Avg. NYMEX
| Forecasted
| Call Options
| |||||||
Total 2011 | ? | ? | 675 | 0 | % | |||||
Total 2012 | 161 | $ | 6.54 | 980 | 16 | % | ||||
Total 2013 | 436 | $ | 6.44 | |||||||
Total 2014 | 330 | $ | 6.43 | |||||||
Total 2015 | 226 | $ | 6.31 | |||||||
Total 2016 ? 2020 | 324 | $ | 8.13 | |||||||
The company has the following natural gas basis protection swaps in
place for 2011 through 2022:
Non-Appalachia | Appalachia | |||||||||
Volume (Bcf) | Avg. NYMEX less | Volume (Bcf) | Avg. NYMEX plus | |||||||
2011 | 45 | $ | 0.82 | 49 | $ | 0.14 | ||||
2012 | 51 | $ | 0.78 | ? | $ | ? | ||||
2013 - 2022 | 29 | $ | 0.69 | ? | $ | ? | ||||
Totals | 125 | $ | 0.77 | 49 | $ | 0.14 | ||||
At May 2, 2011, the company has the following open crude oil swaps in
place for 2011 and 2012, excluding contracts that will be novated with
VPP #9. In addition, the company has $4 million of net hedging losses
related to closed crude oil contracts and premiums collected on call
options for future production periods.
Open
| Avg. NYMEX
| Forecasted
| Open Swap
| Total Gains
| Total Gains from
| ||||||||||||
Q2 2011 | 1638 | $ | 102.96 | ? | ? | $ | 13 | ||||||||||
Q3 2011 | 1656 | $ | 102.96 | ? | ? | $ | 13 | ||||||||||
Q4 2011 | 1656 | $ | 102.96 | ? | ? | $ | 13 | ||||||||||
Total 2011(a) | 4,950 | $ | 102.96 | 28,000 | 18 | % | $ | 39 | $ | 1.37 | |||||||
Total 2012(a) | 5,490 | $ | 104.78 | 54,000 | 10 | % | $ | 51 | $ | 0.94 | |||||||
Total 2013 | $ | 6 | |||||||||||||||
Total 2014 | $ | (198 | ) | ||||||||||||||
Total 2015 | $ | 94 | |||||||||||||||
Total 2016 ? 2020 | $ | 4 | |||||||||||||||
(a) | Certain hedging contracts include knockout swaps with provisions limiting the counterparty′s exposure below prices of $60.00 covering 1 mmbbls in each of 2011 and 2012. |
The company currently has the following crude oil written call options
in place for 2011 through 2017:
Call Options (mbbls) | Avg. NYMEX
| Forecasted
| Call Options
| |||||||
Q2 2011 | 1,820 | $ | 85.44 | |||||||
Q3 2011 | 1,840 | $ | 87.50 | |||||||
Q4 2011 | 1,840 | $ | 87.50 | |||||||
Total 2011 | 5,500 | $ | 86.82 | 28,000 | 20 | % | ||||
Total 2012 | 22,139 | $ | 87.93 | 54,000 | 41 | % | ||||
Total 2013 | 14,564 | $ | 87.20 | |||||||
Total 2014 | 8,707 | $ | 87.72 | |||||||
Total 2015 | 8,233 | $ | 87.27 | |||||||
Total 2016 ? 2017 | 11,423 | $ | 85.75 | |||||||
Chesapeake Energy Corporation
Jeffrey L. Mobley, CFA, 405-767-4763
jeff.mobley@chk.com
or
John
J. Kilgallon, 405-935-4441
john.kilgallon@chk.com
or
Media
Contacts:
Michael Kehs, 405-935-2560
michael.kehs@chk.com
or
Jim
Gipson, 405-935-1310
jim.gipson@chk.com
