Chesapeake Energy Corporation Reports Financial and Operational Results for the 2011 First Quarter
02.05.2011 | Business Wire
Company Reports 2011 First Quarter Net Loss to Common Stockholders
of $205 Million, or $0.32 per Fully Diluted Common Share, on Revenue of
$1.6 Billion; Company Reports Adjusted Net Income Available to Common
Stockholders of $518 Million, or $0.75 per Fully Diluted Common Share,
Adjusted Ebitda of $1.3 Billion and Operating Cash Flow of $1.4 Billion
2011 First Quarter Production Averages 3.107 Bcfe per Day, an
Increase of 20% over 2010 First Quarter Production and 6% over 2010
Fourth Quarter Production; 2011 First Quarter Liquids Production
Increases 56% Compared to the 2010 First Quarter and 9% Compared to the
2010 Fourth Quarter; 2011 First Quarter Liquids Production Accounts for
13% of Total Production and 23% of Realized Natural Gas and Oil Revenue
Proved Reserves Total 15.6 Tcfe Following the Sale of 2.5 Tcfe of
Proved Reserves; Company Adds New Net Proved Reserves of 1.3 Tcfe
Through the Drillbit at a Drilling and Completion Cost of $1.25 per Mcfe
Company′s Leasehold Reaches 1.2 Million Net Acres in the Utica
Shale Play in the Appalachian Basin and 1.1 MillionNet
Acres in the Mississippian Carbonate Play in Northern Oklahoma and
Southern Kansas; JV Process is Expected to Commence for Each Play in the
2011 Second Half
Company Highlights its Oilfield Service Vertical Integration
Strategy and Estimates that its Oilfield Service Assets Are Worth
Approximately $7.0 Billion
Chesapeake Energy Corporation (NYSE:CHK) today announced its 2011 first
quarter financial and operational results. For the quarter, Chesapeake
reported a net loss to common stockholders of $205 million ($0.32 per
fully diluted common share), operating cash flow of $1.404 billion
(defined as cash flow from operating activities before changes in assets
and liabilities) and ebitda of $167 million (defined as net income
before income taxes, interest expense, and depreciation, depletion and
amortization) on revenue of $1.612 billion and production of 280 billion
cubic feet of natural gas equivalent (bcfe).
The company′s 2011 first 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 first quarter, Chesapeake reported adjusted net
income to common stockholders of $518 million ($0.75 per fully diluted
common share) and adjusted ebitda of $1.346 billion. The excluded items
and their effects on the 2011 first quarter reported results are
detailed as follows:
a net unrealized after-tax mark-to-market loss of $725 million
resulting from the company′s natural gas, oil and interest rate
hedging programs;
a net after-tax gain of $3 million related to the sale of certain of
the company′s fixed assets; and
an after-tax loss of $1 million related to the redemption of certain
of the company's senior notes.
The various items described above do not materially affect the
calculation of operating cash flow. A reconciliation of operating cash
flow, ebitda, adjusted ebitda and adjusted net income to comparable
financial measures calculated in accordance with generally accepted
accounting principles is presented on pages 18 ? 20 of this release.
Key Operational and Financial Statistics Summarized
The table below summarizes Chesapeake′s key results during the 2011
first quarter and compares them to results during the 2010 fourth
quarter and the 2010 first quarter.
| Three Months Ended | |||||||||||
| 3/31/11 | 12/31/10 | 3/31/10 | |||||||||
Average daily production (in mmcfe) | 3,107 | 2,920 | 2,586 | ||||||||
Natural gas as % of total production | 87 | 88 | 90 | ||||||||
Natural gas production (in bcf) | 243.3 | 235.3 | 209.6 | ||||||||
Average realized natural gas price ($/mcf)(a) | 5.31 | 5.22 | 6.31 | ||||||||
Oil and NGL production (in mbbls) | 6,048 | 5,562 | 3,871 | ||||||||
Average realized oil and NGL price ($/bbl)(a) | 63.20 | 62.62 | 67.70 | ||||||||
Natural gas equivalent production (in bcfe) | 279.6 | 268.7 | 232.8 | ||||||||
Natural gas equivalent realized price ($/mcfe)(a) | 5.99 | 5.87 | 6.80 | ||||||||
Marketing, gathering and compression net margin ($/mcfe)(b) | .11 | .13 | .12 | ||||||||
| .09 | .05 | .03 | ||||||||
Production expenses ($/mcfe) | (.85 | ) | (.90 | ) | (.89 | ) | |||||
Production taxes ($/mcfe) | (.16 | ) | (.14 | ) | (.21 | ) | |||||
General and administrative costs ($/mcfe)(c) | (.38 | ) | (.34 | ) | (.38 | ) | |||||
Stock-based compensation ($/mcfe) | (.08 | ) | (.08 | ) | (.09 | ) | |||||
DD&A of natural gas and oil properties ($/mcfe) | (1.28 | ) | (1.37 | ) | (1.32 | ) | |||||
D&A of other assets ($/mcfe) | (.24 | ) | (.23 | ) | (.21 | ) | |||||
Interest (expense) income ($/mcfe)(a) | .00 | .01 | (.22 | ) | |||||||
Operating cash flow ($ in millions)(d) | 1,404 | 1,370 | 1,261 | ||||||||
Operating cash flow ($/mcfe) | 5.02 | 5.10 | 5.42 | ||||||||
Adjusted ebitda ($ in millions)(e) | 1,346 | 1,274 | 1,270 | ||||||||
Adjusted ebitda ($/mcfe) | 4.81 | 4.75 | 5.46 | ||||||||
Net income (loss) to common stockholders ($ in millions) | (205 | ) | 180 | 732 | |||||||
Earnings (loss) per share ? assuming dilution ($) | (.32 | ) | .28 | 1.14 | |||||||
Adjusted net income to common stockholders ($ in millions)(f) | 518 | 478 | 524 | ||||||||
Adjusted earnings per share ? assuming dilution ($) | .75 | .70 | .82 | ||||||||
(a) | Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging. | |
(b) |
| |
(c) | Excludes expenses associated with noncash stock-based compensation. | |
(d) | Defined as cash flow provided by operating activities before changes in assets and liabilities. | |
(e) | 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. | |
(f) | Defined as net income (loss) available to common stockholders, as adjusted to remove the effects of certain items detailed on page 20. | |
2011 First Quarter Average Daily Production of 3.107 Bcfe per Day
Increases 20% over 2010 First Quarter Production and 6% over 2010 Fourth
Quarter Production; 2011 First Quarter Liquids Production Increases 56%
Compared to the 2010 First Quarter and 9% Compared to the 2010 Fourth
Quarter; 2011 First Quarter Liquids Production Accounts for 13% of Total
Production and 23% of Realized Natural Gas and Oil Revenue
Chesapeake′s daily production for the 2011 first quarter averaged 3.107
bcfe, an increase of 521 million cubic feet of natural gas equivalent
(mmcfe), or 20%, over the 2.586 bcfe produced per day in the 2010 first
quarter and an increase of 187 mmcfe, or 6%, over the 2.920 bcfe
produced per day in the 2010 fourth quarter.
Chesapeake′s average daily production of 3.107 bcfe for the 2011 first
quarter consisted of 2.704 billion cubic feet of natural gas (bcf) and
67,200 barrels (bbls) of oil and natural gas liquids (NGLs). The
company′s 2011 first quarter production of 279.6 bcfe was comprised of
243.3 bcf (87% on a natural gas equivalent basis) and 6.0 million bbls
of oil and NGLs (liquids) (13% on a natural gas equivalent basis). The
company′s year-over-year growth rate of natural gas production was 16%
and its year-over-year growth rate of liquids production was 56%.
Sequential quarterly production growth was 3% for natural gas and 9% for
liquids. The company′s percentage of revenue from liquids in the 2011
first quarter was 23% of realized natural gas and oil revenue compared
to 17% in the 2010 first quarter. In affirmation of its 25/25 Plan
discussed on page 8 of this release, Chesapeake anticipates delivering
production growth of 25% for the two-year period ending December 31,
2012, net of property divestitures.
Chesapeake′s Proved Natural Gas and Oil Reserves Decrease by 1.5
Tcfe, or 9%, in the 2011 First Quarter to 15.6 Tcfe Following the Sale
of 2.5 Tcfe of Proved Reserves; Company Adds New Net Proved Reserves of
1.3 Tcfe through the Drillbit at a Drilling and Completion Cost of $1.25
per Mcfe
During the 2011 first quarter, Chesapeake continued the industry′s most
active drilling program, drilling 375 gross operated wells (234 net
wells with an average working interest of 62%) and participating in
another 430 gross non-operated wells (60 net wells with an average
working interest of 14%). The company′s drilling success rate was 98%
for company-operated wells and 99% for non-operated wells. During the
2011 first quarter, Chesapeake′s drilling and completion costs of $1.664
billion included the benefit of approximately $527 million of drilling
and completion carries from its joint venture partners.
The following table compares Chesapeake′s March 31, 2011 proved
reserves, the decrease versus its year-end 2010 proved reserves,
estimated future net cash flows from proved reserves (discounted at an
annual rate of 10% before income taxes (PV-10)), and proved developed
percentage based on the trailing 12-month average price required by the
reserve reporting rules of the Securities and Exchange Commission (SEC)
and the 10-year average NYMEX strip prices at March 31, 2011.
| Pricing Method | Natural ($/mcf) |
Oil Price ($/bbl) | Proved Reserves (tcfe)(a) | Proved Reserves Decrease (tcfe)(b) | Proved Reserves Decrease %(b) | PV-10 (billions) | Proved Developed Percentage | |||||||
Trailing 12-month average (SEC)(c) | $4.10 | $83.34 | 15.6 | 1.5 | 9% | $14.3 | 55% | |||||||
3/31/11 10-year average NYMEX strip(d) | $6.17 | $103.13 | 16.5 | 1.1 | 7% | $28.1 | 55% | |||||||
(a) | After sales of proved reserves of approximately 2.5 tcfe during the 2011 first quarter. | |
(b) | Compares proved reserve growth for the 2011 first quarter under comparable pricing methods. At year-end 2010, Chesapeake′s proved reserves were 17.1 tcfe using trailing 12-month average prices, which are required by SEC reporting rules, and 17.6 tcfe using the 10-year average NYMEX strip prices at December 31, 2010. | |
(c) | Reserve volumes estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of March 31, 2011. This pricing yields estimated 'proved reserves' for SEC reporting purposes. Natural gas and oil volumes estimated under any alternative pricing scenario reflect the sensitivity of proved reserves to a different pricing assumption. | |
(d) | Futures prices represent an unbiased consensus estimate by market participants about the likely prices to be received for future production. Management believes that 10-year average NYMEX strip prices provide a better indicator of the likely economic producibility of the company′s proved reserves than the historical 12-month average price. | |
The following table summarizes Chesapeake′s development costs for the
2011 first quarter using the two pricing methods described above.
| Development Cost Category | Trailing 12-Month Average (SEC) Pricing ($/mcfe) | 3/31/11 10-year Average Pricing ($/mcfe) | ||
Drilling and completion costs(a) | $1.25 | $1.16 | ||
Drilling and completion costs, net of proved property divestitures(a) | $0.08 | $0.08 | ||
(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 14 and 15 of this release.
At the end of the 2011 first quarter, Chesapeake closed the sale of its
upstream and midstream assets in the Fayetteville Shale to BHP Billiton
Petroleum, a wholly owned subsidiary of BHP Billiton Limited (NYSE:BHP;
ASX:BHP), for net proceeds of approximately $4.65 billion in cash. The
sale included approximately 2.4 trillion cubic feet of natural gas
equivalent (tcfe) of proved reserves, which resulted in the decline in
proved reserves for the 2011 first quarter. Excluding this sale,
Chesapeake′s proved reserves would have been 18.0 tcfe, an increase of
0.9 tcfe, or 5%, over the 2010 year-end proved reserves of 17.1 tcfe.
In addition to the PV-10 value of its proved reserves, the company also
has substantial value in its undeveloped leasehold, particularly its
unconventional natural gas shale plays in the Marcellus, Haynesville,
Bossier, Pearsall and Barnett and its unconventional liquids-rich plays
in the Granite Wash, Cleveland, Tonkawa and Mississippian plays of the
Anadarko Basin; the Eagle Ford Shale in South Texas; the Niobrara Shale
in the Powder River and DJ basins; the Bone Spring, Avalon, Wolfcamp and
Wolfberry plays of the Permian Basin; the Three Forks/Bakken play in the
Williston Basin; and the Utica Shale in the Appalachian Basin.
Additionally, the net book value of the company′s other assets
(including gathering systems, compressors, land and buildings,
investments and other non-current assets) was $6.1 billion as of March
31, 2011 and December 31, 2010.
Chesapeake′s Leasehold and 3-D Seismic Inventories Total 14.3 Million
Net Acres and 28.3 Million Acres, Respectively; Risked Unproved
Resources in the Company′s Inventory Total 107 Tcfe;Company′s
Leasehold Reaches 1.2 Million Net Acres in the Utica Shale Play in the
Appalachian Basin and 1.1 Million Net Acres in the Mississippian
Carbonate Play in Northern Oklahoma and Southern Kansas; Company Expects
to Commence JV Process for Each Play in the 2011 Second Half
Since 2000, Chesapeake has built the largest combined inventories of
onshore leasehold (14.3 million net acres) and 3-D seismic (28.3 million
acres) in the U.S. The company has 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 the Top 13 unconventional liquids-rich
plays in the U.S. ? the Granite Wash, Cleveland, Tonkawa and
Mississippian plays of the Anadarko Basin; the Avalon, Bone Spring,
Wolfcamp and Wolfberry plays of the Permian Basin; the Eagle Ford Shale
of South Texas; the Niobrara Shale in the Powder River and DJ basins;
the Three Forks/Bakken in the Williston Basin; and the Utica Shale of
the Appalachian Basin.
On its total leasehold inventory, Chesapeake has identified an estimated
16.5 tcfe of proved reserves (using volume estimates based on the
10-year average NYMEX strip prices at March 31, 2011), 107 tcfe of
risked unproved resources and 289 tcfe of unrisked unproved resources.
The company is currently using 156 operated drilling rigs to further
develop its inventory of approximately 39,000 net drillsites. Of
Chesapeake′s 156 operated rigs, 88 are drilling wells primarily focused
on unconventional natural gas plays (including 53 operated rigs
utilizing drilling carries) and 65 are drilling wells primarily focused
on unconventional liquids-rich plays (including 23 operated rigs
utilizing drilling carries). In addition, 151 of the company′s 156
operated rigs are drilling horizontal wells.
In recognition of the value gap between oil and natural gas prices,
Chesapeake has directed a significant portion of its technological and
leasehold acquisition expertise during the past two 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 5.1 million net leasehold
acres with 5.6 billion bbls of oil equivalent (bboe) (34 tcfe) of risked
unproved resources and 17.5 bboe (105 tcfe) of unrisked unproved
resources. As a result of its success to date, Chesapeake expects to
increase its oil and natural gas 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, through organic growth 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 | Apr-11 | Apr-11 | ||||||||||||
| 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 | 1,730,000 | 80 | 60% | 8,610 | 956 | 38,100 | 95,900 | 290 | 33 | |||||||||
Haynesville | 515,000 | 80 | 30% | 4,280 | 3,987 | 18,000 | 26,900 | 1,000 | 33 | |||||||||
Bossier(3) | 200,000 | 80 | 60% | 970 | 14 | 4,000 | 10,000 | 15 | 2 | |||||||||
Barnett | 220,000 | 60 | 25% | 1,700 | 3,469 | 3,100 | 4,100 | 370 | 18 | |||||||||
Pearsall(4) | 350,000 | 160 | 75% | 550 | 2 | 2,500 | 9,800 | ND | 2 | |||||||||
| Subtotal | 2,465,000 | 16,110 | 8,428 | 65,700 | 146,700 | 1,675 | 88 | |||||||||||
Unconventional Liquids Plays: | ||||||||||||||||||
Anadarko Basin(5) | 1,990,000 | 155 | 70% | 4,240 | 2,184 | 12,900 | 33,500 | 505 | 31 | |||||||||
Eagle Ford | 450,000 | 80 | 50% | 2,810 | 203 | 9,000 | 18,100 | 25 | 17 | |||||||||
Permian Basin(6) | 670,000 | 160 | 67% | 1,360 | 262 | 3,200 | 9,900 | 95 | 8 | |||||||||
Powder River and DJ Basins(7) | 570,000 | ND | ND | ND | ND | ND | ND | ND | 6 | |||||||||
Utica | 1,200,000 | ND | ND | ND | ND | ND | ND | ND | 3 | |||||||||
Other | 190,000 | ND | ND | ND | ND | ND | ND | ND | 0 | |||||||||
| Subtotal | 5,070,000 | 12,780 | 2,662 | 33,900 | 104,800 | 625 | 65 | |||||||||||
| Other Conventional and | ||||||||||||||||||
| Unconventional Plays: | 6,745,000 | Various | Various | 10,110 | 5,369 | 7,300 | 37,400 | 720 | 3 | |||||||||
| Total | 14,280,000 | 39,000 | 16,459 | 106,900 | 288,900 | 3,020 | 156 | |||||||||||
Note: ND denotes 'not disclosed? | ||
(1) | As of March 31, 2011, pro forma for recent leasehold transactions | |
(2) | Based on 10-year average NYMEX strip prices at March 31, 2011 | |
(3) | Bossier Shale acreage overlaps with Haynesville Shale acreage and is excluded from the play sub-total to avoid double counting of acreage | |
(4) | Pearsall Shale acreage overlaps with Eagle Ford Shale acreage and is excluded from the play sub-total to avoid double counting of acreage | |
(5) | Includes Granite Wash, Cleveland, Tonkawa and Mississippian plays | |
(6) | Includes only Delaware and Midland Basin plays | |
(7) | Includes Niobrara, Frontier and Codell plays | |
In 2007, the company was the first to initiate large-scale horizontal
drilling in the Mississippian Carbonate play in northern Oklahoma and
southern Kansas. To date, Chesapeake has drilled 53 operated
Mississippian horizontal wells and has participated in the drilling of
36 non-operated Mississippian horizontal wells on its inventory of
approximately 1.1 million net acres. Chesapeake is currently drilling
with five operated rigs in the Mississippian play and plans to increase
its operated drilling activity in the Mississippian to seven rigs by the
2011 fourth quarter.
In 2010, the company was the first to identify the potential of the
Utica Shale and to initiate large scale leasing efforts in Ohio and
western Pennsylvania for the Utica. To date, the company has drilled
nine operated Utica wells and is currently drilling with three operated
rigs. Chesapeake plans to increase its operated drilling activity in the
Utica to six rigs by the end of the 2011 third quarter. The company
expects to initiate a joint venture process in the 2011 second half for
both the Mississippian and Utica plays.
2011 First Quarter Average Realized Prices Benefit from Realized
Hedging Gains of $488 Million, or $1.74 per Mcfe; Company Provides
Update on Hedging Positions
Average prices realized during the 2011 first quarter (including
realized gains or losses from natural gas and oil derivatives, but
excluding unrealized gains or losses on such derivatives) were $5.31 per
thousand cubic feet (mcf) and $63.20 per bbl, for a realized natural gas
equivalent price of $5.99 per thousand cubic feet of natural gas
equivalent (mcfe). Realized gains from natural gas hedging activities
during the 2011 first quarter generated a $2.07 gain per mcf, while
realized losses from oil hedging activities generated a $2.88 loss per
bbl, for 2011 first quarter net realized hedging gains of $488 million,
or $1.74 per mcfe.
By comparison, average prices realized during the 2010 first quarter
(including realized gains or losses from natural gas and oil
derivatives, but excluding unrealized gains or losses on such
derivatives) were $6.31 per mcf and $67.70 per bbl, for a realized
natural gas equivalent price of $6.80 per mcfe. Realized gains from
natural gas and oil hedging activities during the 2010 first quarter
generated a $1.81 gain per mcf and a $5.11 gain per bbl, for 2010 first
quarter realized hedging gains of $399 million, or $1.71 per mcfe. The
company′s realized cash hedging gains since January 1, 2001 have been
$7.0 billion, or $1.20 per mcfe, on average, for every mcfe produced
during the past ten years.
To provide protection against potentially weak natural gas prices in
2011 and the first half of 2012, Chesapeake has entered into hedges for
a portion of its production in those two years. 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. The following table summarizes Chesapeake′s 2011 and
2012 open swap positions as of May 2, 2011.
| Natural Gas | Oil | |||||||||||||
| Year | % of Forecasted | $ NYMEX | % of Forecasted | $ NYMEX | ||||||||||
2Q ? Q4 2011 | 88 | % | $5.03 | 18 | % | $102.96 | ||||||||
2012 | 19 | % | $6.17 | 10 | % | $104.78 | ||||||||
In addition to the open hedging positions disclosed above, as of May 2,
2011 (as detailed below), the company had an additional $725 million and
$42 million of net hedging gains on closed contracts and premiums
collected on call options that will be realized in 2011 and 2012,
respectively.
| Natural Gas | Oil | |||||||||||||||||
| Year | Forecasted | Gains (Losses) | Gains | Forecasted | Gains (Losses) | Gains | ||||||||||||
2Q ? Q4 2011 | 675 | $687 | $1.02 | 28,000 | $38 | $1.37 | ||||||||||||
2012 | 980 | $(9) | $(0.01) | 54,000 | $51 | $0.94 | ||||||||||||
Assuming future NYMEX natural gas settlement prices average $4.50 and
$5.50 per mcf for 2011 and 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 $5.98 and $5.60 per mcf for 2011 and 2012, respectively.
Additionally, assuming future NYMEX oil settlement prices average $100
per bbl for 2011 and 2012, the company estimates its average NYMEX oil
prices will be $96.22 and $95.80 per bbl for 2011 and 2012,
respectively. These estimates do not include the effect of gathering
costs and basis differentials, which include the effect of lower-priced
NGLs on the company′s reported realized liquids prices.
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 May 2,
2011, labeled as Schedule 'A,? which begins on page 21. The Outlook has
been changed from the Outlook dated February 22, 2011, attached as
Schedule 'B,? which begins on page 25, to reflect various updated
information.
Chesapeake Provides Update on 25/25 Plan; Company Agrees to Monetize
Certain Mid-Continent Assets through its Ninth Volumetric Production
Payment
On January 6, 2011, Chesapeake announced its 25/25 Plan, which outlined
the company′s plan to reduce its long-term debt by 25% during 2011-12
while also delivering natural gas and oil production growth of 25%
during these two years. The company expects to achieve the reduction in
debt primarily with proceeds from asset monetizations and from
substantially reduced leasehold spending during this period.
Two recent transactions reflect the company′s substantial progress
already made in implementing its 25/25 Plan. On February 11, 2011, the
company closed its Niobrara Shale cooperation agreement through which
CNOOC Limited (NYSE:CEO; SEHK:00883) purchased a 33.3% undivided
interest in Chesapeake′s 800,000 net natural gas and oil leasehold acres
in the DJ and Powder River Basins in Colorado and Wyoming for
approximately $4,750 per net acre. The company received approximately
$570 million in cash at closing, and CNOOC has agreed to fund 66.7% of
Chesapeake′s share of drilling and completion costs until an additional
$697 million has been paid, which Chesapeake expects to occur by
year-end 2014.
In addition, on March 31, 2011, Chesapeake closed the sale of its
upstream and midstream assets in the Fayetteville Shale to BHP Billiton,
for net proceeds of approximately $4.65 billion in cash.
Proceeds from the transactions above will fund the purchase of
approximately $1.865 billion of the company′s senior notes and
contingent convertible senior notes in May 2011 pursuant to company
tender offers for the notes. Combined with the $140 million of
contingent convertible senior notes purchased by Chesapeake in privately
negotiated transactions in the past 60 days, Chesapeake will have
retired an aggregate principal amount of approximately $2.005 billion of
senior notes and contingent convertible senior notes in 2011. The
company may negotiate or tender for the acquisition of additional senior
notes and contingent convertible senior notes later in 2011 or in 2012.
Moreover, through a recently disclosed planned recapitalization of Frac
Tech Services, LLC, Chesapeake anticipates receiving a cash distribution
of approximately $200 million and will increase its ownership of the
company′s equity from 26% to 30%. The Frac Tech recapitalization
transaction is expected to close in the 2011 second quarter and the
company believes that by year-end 2011, the value of its equity in Frac
Tech will be worth up to $1.5 billion.
Additionally, Chesapeake has agreed to monetize certain of its producing
assets in the Mid-Continent through a ten-year volumetric production
payment (VPP) to an affiliate of Barclays PLC (NYSE:BCS; LSE:BARC) for
proceeds of approximately $850 million. The transaction includes
approximately 180 bcfe of proved reserves and approximately 80 mmcfe per
day of current net production. Chesapeake has retained drilling rights
on the properties below currently producing intervals and outside of
existing producing wellbores and the production 'tail? beyond ten years.
The transaction will be Chesapeake′s ninth VPP and is expected to close
in the 2011 second quarter. Inclusive of the pending VPP sale and the
company′s eight previously closed VPPs, the company will have sold 1.215
tcfe of proved reserves for total proceeds of $5.619 billion, for an
average sales price of $4.62 per mcfe.
Chesapeake Highlights its Oilfield Service Vertical Integration
Strategy and Estimates that its Oilfield Service Assets Are Worth
Approximately $7.0 Billion
Chesapeake has built a large inventory of low-risk natural gas and oil
resources which the company plans to develop aggressively in the decades
ahead. As a result, the company will consistently utilize a large and
growing amount of oilfield services for this resource development. In
the next decade alone, Chesapeake′s gross drilling and completion
expenditures may reach $100 billion. This high level of planned drilling
activity will create considerable value for the providers of oilfield
services and Chesapeake′s strategy is to capture a portion of this value
for its shareholders rather than transfer it to third-party vendors. In
addition, the company utilizes its service company operations as a hedge
against oilfield service inflation.
To date, Chesapeake has invested in drilling rigs, compression
equipment, rental tools, water management equipment, trucking, midstream
services and most recently, fracture stimulation equipment. Chesapeake′s
industry-leading drilling and completion activities require a high level
of planning and project coordination that the company believes is best
accomplished through vertical integration and ownership of a significant
portion of the oilfield services it utilizes. This vertical integration
approach also creates a multitude of cost savings, an alignment of
interests, operational synergies, greater capacity of equipment,
increased safety and better coordinated logistics. In addition,
Chesapeake′s control of a large portion of the oilfield service
equipment it utilizes provides unique advantages in accelerating the
timing of its leasehold development and therefore accelerating the
creation of present value from its vast inventory of undeveloped
properties.
As an extension of this strategy, Chesapeake recently agreed to acquire
and has now commenced a cash tender offer to purchase all of the
outstanding shares of Bronco Drilling Company, Inc. (NASDAQ: BRNC) for
$315 million, or $11 a share. The cash tender offer will expire on May
23, 2011. The acquisition includes 22 high-quality drilling rigs
primarily operating in the Williston and Anadarko basins and has support
from Bronco′s two largest shareholders, who collectively own 32% of
Bronco′s stock.
Based on projected levels of Chesapeake′s oilfield service company
unconsolidated cash flow from operations of approximately $1.0 billion
in 2012, Chesapeake believes that the combined value of its oilfield
service company assets, including the value of its investment in Frac
Tech, is worth approximately $7.0 billion. The company is in the process
of evaluating various alternatives to partially monetize its oilfield
service assets and expects to achieve such a monetization in 2012.
Conference Call Information
A conference call to discuss this release has been scheduled for
Tuesday, May 3, 2011, at 9:00 a.m. EDT. The telephone number to access
the conference call is 913-981-5539 or toll-free 888-820-9417.
The passcode for the call is 8789033. 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 Tuesday, May 3, 2011 through midnight EDT on Tuesday, May
17, 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 8789033.
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 oil reserves and resources, expected natural gas and oil production
and future expenses, assumptions regarding future natural gas and oil
prices, planned drilling activity, drilling and completion costs,
anticipated asset sales, 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 oil 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
oil 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 oil 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 oil 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 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 oil 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 oil 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
oil 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, Three Forks/Bakken
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: | March 31, | March 31, | |||||||||||||||
| 2011 | 2010 | ||||||||||||||||
| $ | $/mcfe | $ | $/mcfe | ||||||||||||||
| REVENUES: | |||||||||||||||||
| Natural gas and oil sales | 494 | 1.77 | 1,898 | 8.16 | |||||||||||||
| Marketing, gathering and compression sales | 1,017 | 3.64 | 844 | 3.62 | |||||||||||||
| Service operations revenue | 101 | 0.36 | 56 | 0.24 | |||||||||||||
| Total Revenues | 1,612 | 5.77 | 2,798 | 12.02 | |||||||||||||
| OPERATING COSTS: | |||||||||||||||||
| Production expenses | 238 | 0.85 | 207 | 0.89 | |||||||||||||
| Production taxes | 45 | 0.16 | 48 | 0.21 | |||||||||||||
| General and administrative expenses | 130 | 0.46 | 109 | 0.47 | |||||||||||||
| Marketing, gathering and compression expenses | 985 | 3.53 | 815 | 3.50 | |||||||||||||
| Service operations expense | 77 | 0.28 | 49 | 0.21 | |||||||||||||
| Natural gas and oil depreciation, depletion and amortization | 358 | 1.28 | 308 | 1.32 | |||||||||||||
| Depreciation and amortization of other assets | 68 | 0.24 | 50 | 0.21 | |||||||||||||
| Gains on sales of other property and equipment | (5 | ) | (0.02 | ) | ? | ? | |||||||||||
| Total Operating Costs | 1,896 | 6.78 | 1,586 | 6.81 | |||||||||||||
| INCOME (LOSS) FROM OPERATIONS | (284 | ) | (1.01 | ) | 1,212 | 5.21 | |||||||||||
| OTHER INCOME (EXPENSE): | |||||||||||||||||
| Interest expense | (7 | ) | (0.03 | ) | (25 | ) | (0.11 | ) | |||||||||
| Earnings from equity investees | 25 | 0.09 | 13 | 0.06 | |||||||||||||
| Losses on redemptions or exchanges of debt | (2 | ) | (0.01 | ) | (2 | ) | (0.01 | ) | |||||||||
| Other income | 2 | 0.01 | 2 | 0.01 | |||||||||||||
| Total Other Income (Expense) | 18 | 0.06 | (12 | ) | (0.05 | ) | |||||||||||
| INCOME (LOSS) BEFORE INCOME TAXES | (266 | ) | (0.95 | ) | 1,200 | 5.16 | |||||||||||
| INCOME TAX EXPENSE (BENEFIT): | |||||||||||||||||
| Current income taxes | 6 | 0.02 | ? | ? | |||||||||||||
| Deferred income taxes | (110 | ) | (0.39 | ) | 462 | 1.99 | |||||||||||
| Total Income Tax Expense (Benefit) | (104 | ) | (0.37 | ) | 462 | 1.99 | |||||||||||
| NET INCOME (LOSS) | (162 | ) | (0.58 | ) | 738 | 3.17 | |||||||||||
| Preferred stock dividends | (43 | ) | (0.15 | ) | (6 | ) | (0.02 | ) | |||||||||
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS | (205 | ) | (0.73 | ) | 732 | 3.15 | |||||||||||
| EARNINGS (LOSS) PER COMMON SHARE: | |||||||||||||||||
| Basic | $ | (0.32 | ) | $ | 1.17 | ||||||||||||
| Diluted | $ | (0.32 | ) | $ | 1.14 | ||||||||||||
| WEIGHTED AVERAGE COMMON AND COMMON | |||||||||||||||||
| EQUIVALENT SHARES OUTSTANDING (in millions) | |||||||||||||||||
| Basic | 634 | 630 | |||||||||||||||
| Diluted | 634 | 647 | |||||||||||||||
CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS ($ in millions) (unaudited) | |||||||
| March 31, | December 31, | ||||||
| 2011 | 2010 | ||||||
| Cash and cash equivalents | $ | 849 | $ | 102 | |||
| Other current assets | 2,695 | 3,164 | |||||
| Total Current Assets | 3,544 | 3,266 | |||||
| Property and equipment (net) | 29,709 | 32,378 | |||||
| Other assets | 1,547 | 1,535 | |||||
| Total Assets | $ | 34,800 | $ | 37,179 | |||
| Current liabilities | $ | 4,669 | $ | 4,490 | |||
| Long-term debt, net of discounts (a) | 9,915 | 12,640 | |||||
| Asset retirement obligations | 302 | 301 | |||||
| Other long-term liabilities | 2,804 | 2,100 | |||||
| Deferred tax liability | 2,115 | 2,384 | |||||
| Total Liabilities | 19,805 | 21,915 | |||||
| Stockholders′ Equity | 14,995 | 15,264 | |||||
| Total Liabilities & Stockholders' Equity | $ | 34,800 | $ | 37,179 | |||
| Common Shares Outstanding (in millions) | 658 | 654 | |||||
CHESAPEAKE ENERGY CORPORATION CAPITALIZATION ($ in millions) (unaudited) | |||||||||||||||
| March 31, | % of Total Book | December 31, | % of Total Book | ||||||||||||
| 2011 | Capitalization | 2010 | Capitalization | ||||||||||||
| Total debt, net of cash(a) | $ | 9,066 | 38 | % | $ | 12,538 | 45 | % | |||||||
| Stockholders' equity | 14,995 | 62 | % | 15,264 | 55 | % | |||||||||
| Total | $ | 24,061 | 100 | % | $ | 27,802 | 100 | % | |||||||
(a) | At March 31, 2011, the company had no outstanding borrowings under its $4.0 billion corporate revolving bank credit facility and $300 million midstream revolving bank credit facility. At March 31, 2011, the company had $4.287 billion of borrowing capacity under these two revolving bank credit facilities. | |
CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF 2011 FIRST QUARTER ADDITIONS TO NATURAL GAS BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT ($ in millions, except per-unit data) (unaudited) | |||||||||||
| Proved Reserves | |||||||||||
| Cost | Bcfe(a) | $/Mcfe | |||||||||
| Drilling and completion costs(b) | $ | 1,664 | 1,334 | (c) | 1.25 | ||||||
| Acquisition of proved properties | 18 | 17 | 1.06 | ||||||||
| Sale of proved properties | (1,774 | ) | (2,536 | ) | 0.70 | ||||||
| Drilling and completion costs, net of proved property divestitures | (92 | ) | (1,185 | ) | 0.08 | ||||||
| Revisions ? price | ? | (33 | ) | ? | |||||||
| Acquisition of unproved properties | 883 | ? | ? | ||||||||
| Sale of unproved properties | (3,335 | ) | ? | ? | |||||||
| Net unproved properties acquisition | (2,452 | ) | ? | ? | |||||||
| Capitalized interest on unproved properties | 203 | ? | ? | ||||||||
| Geological and geophysical costs | 66 | ? | ? | ||||||||
| Capitalized interest and geological and geophysical costs | 269 | ? | ? | ||||||||
| Subtotal | (2,275 | ) | (1,218 | ) | 1.87 | ||||||
| Asset retirement obligations and other | (3 | ) | ? | ? | |||||||
| Total costs | $ | (2,278 | ) | (1,218 | ) | 1.87 | |||||
CHESAPEAKE ENERGY CORPORATION ROLL-FORWARD OF PROVED RESERVES THREE MONTHS ENDED MARCH 31, 2011 BASED ON SEC PRICING OF TRAILING 12-MONTH AVERAGE PRICES AT (unaudited) | |||||||
| Bcfe(a) | |||||||
| Beginning balance, 01/01/11 | 17,096 | ||||||
| Production | (280 | ) | |||||
| Acquisitions | 17 | ||||||
| Divestitures | (2,536 | ) | |||||
| Revisions ? changes to previous estimates | 322 | ||||||
| Revisions ? price | (33 | ) | |||||
| Extensions and discoveries | 1,012 | ||||||
| Ending balance, 03/31/11 | 15,598 | ||||||
| Proved reserves growth rate | (9 | )% | |||||
| Proved developed reserves | 8,601 | ||||||
| Proved developed reserves percentage | 55 | % | |||||
| PV10 ($ in billions)(a) | 14.3 | ||||||
(a) | Reserve volumes and PV10 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 March 31, 2011, of $4.10 per mcf of natural gas and $83.34 per bbl of oil, before field differential adjustments. | |
(b) | Net of drilling and completion carries of $527 million associated with the Statoil, Total, CNOOC-Eagle Ford and CNOOC-Niobrara industry participation agreements. | |
(c) | Includes 322 bcfe of positive revisions resulting from changes to previous estimates and excludes downward revisions of 33 bcfe resulting from lower natural gas prices using the average first-day-of-the-month price for the twelve months ended March 31, 2011, compared to the twelve months ended December 31, 2010. | |
CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF 2011 FIRST QUARTER ADDITIONS TO NATURAL GAS BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT MARCH 31, 2011 ($ in millions, except per-unit data) (unaudited) | ||||||||||||
| Proved Reserves | ||||||||||||
| Cost | Bcfe(a) | $/Mcfe | ||||||||||
| Drilling and completion costs(b) | $ | 1,664 | 1,429 | (c) | 1.16 | |||||||
| Acquisition of proved properties | 18 | 17 | 1.06 | |||||||||
| Sale of proved properties | (1,774 | ) | (2,536 | ) | 0.70 | |||||||
| Drilling and completion costs, net of proved property divestitures | (92 | ) | (1,090 | ) | 0.08 | |||||||
| Revisions ? price | ? | 224 | ? | |||||||||
| Acquisition of unproved properties | 883 | ? | ? | |||||||||
| Sale of unproved properties | (3,335 | ) | ? | ? | ||||||||
| Net unproved properties acquisition | (2,452 | ) | ? | ? | ||||||||
| Capitalized interest on unproved properties | 203 | ? | ? | |||||||||
| Geological and geophysical costs | 66 | ? | ? | |||||||||
| Capitalized interest and geological and geophysical costs | 269 | ? | ? | |||||||||
| Subtotal | (2,275 | ) | (866 | ) | 2.63 | |||||||
| Asset retirement obligations and other | (3 | ) | ? | ? | ||||||||
| Total costs | $ | (2,278 | ) | (866 | ) | 2.63 | ||||||
CHESAPEAKE ENERGY CORPORATION ROLL-FORWARD OF PROVED RESERVES THREE MONTHS ENDED MARCH 31, 2011 BASED ON 10-YEAR AVERAGE NYMEX STRIP PRICES AT MARCH 31, 2011 (unaudited) | |||||||
| Bcfe(a) | |||||||
| Beginning balance, 01/01/11 | 17,605 | ||||||
| Production | (280 | ) | |||||
| Acquisitions | 17 | ||||||
| Divestitures | (2,536 | ) | |||||
| Revisions ? changes to previous estimates | 333 | ||||||
| Revisions ? price | 224 | ||||||
| Extensions and discoveries | 1,096 | ||||||
| Ending balance, 03/31/11 | 16,459 | ||||||
| Proved reserves growth rate | (7 | )% | |||||
| Proved developed reserves | 9,088 | ||||||
| Proved developed reserves percentage | 55 | % | |||||
| PV10 ($ in billions)(a) | 28.1 | ||||||
| Reserve volumes and PV10 value estimated using SEC reserve recognition standards and 10-year average NYMEX strip prices as of March 31, 2011 of $6.17 per mcf of natural gas and $103.13 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 $527 million associated with the Statoil, Total, CNOOC-Eagle Ford and CNOOC-Niobrara industry participation agreements. | |
(c) | Includes 333 bcfe of positive revisions resulting from changes to previous estimates and excludes positive revisions of 224 bcfe resulting from higher natural gas and oil prices using 10-year average NYMEX strip prices as of March 31, 2011 compared to NYMEX strip prices as of December 31, 2010. | |
CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA ? NATURAL GAS AND OIL SALES AND INTEREST (unaudited) | |||||||||
| March 31, | March 31, | ||||||||
| 2011 | 2010 | ||||||||
| Natural Gas and Oil Sales ($ in millions): | |||||||||
Natural gas sales | $ | 788 | $ | 942 | |||||
Natural gas derivatives ? realized gains (losses) | 505 | 379 | |||||||
Natural gas derivatives ? unrealized gains (losses) | (549 | ) | 415 | ||||||
Total Natural Gas Sales | 744 | 1,736 | |||||||
Oil sales(a) | 400 | 242 | |||||||
Oil derivatives ? realized gains (losses) | (17 | ) | 20 | ||||||
Oil derivatives ? unrealized gains (losses) | (633 | ) | (100 | ) | |||||
Total Oil Sales | (250 | ) | 162 | ||||||
Total Natural Gas and Oil Sales | $ | 494 | $ | 1,898 | |||||
| Average Sales Price ? excluding gains (losses) on derivatives: | |||||||||
Natural gas ($ per mcf) | $ | 3.24 | $ | 4.50 | |||||
Oil ($ per bbl) | $ | 66.08 | $ | 62.59 | |||||
Natural gas equivalent ($ per mcfe) | $ | 4.25 | $ | 5.09 | |||||
| Average Sales Price ? excluding unrealized gains (losses) on derivatives: | |||||||||
Natural gas ($ per mcf) | $ | 5.31 | $ | 6.31 | |||||
Oil ($ per bbl) | $ | 63.20 | $ | 67.70 | |||||
Natural gas equivalent ($ per mcfe) | $ | 5.99 | $ | 6.80 | |||||
| Interest Expense ($ in millions): | |||||||||
Interest(b) | $ | 8 | $ | 55 | |||||
Derivatives ? realized (gains) losses | (7 | ) | (3 | ) | |||||
Derivatives ? unrealized (gains) losses | 6 | (27 | ) | ||||||
Total Interest Expense (Income) | $ | 7 | $ | 25 | |||||
(a) | Includes NGLs. | |
(b) | Net of amounts capitalized. | |
CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED CASH FLOW DATA ($ in millions) (unaudited) | |||||||||
| THREE MONTHS ENDED: | March 31, | March 31, | |||||||
| 2011 | 2010 | ||||||||
| Beginning cash | $ | 102 | $ | 307 | |||||
| Cash provided by operating activities | $ | 741 | $ | 1,183 | |||||
| Cash provided by (used in) investing activities: | |||||||||
| Exploration and development of natural gas and oil properties | $ | (1,692 | ) | $ | (1,020 | ) | |||
Acquisitions of natural gas and oil proved and unproved | (1,281 | ) | (1,030 | ) | |||||
| Divestitures of proved and unproved properties | 5,182 | 1,224 | |||||||
| Other property and equipment, net | (3 | ) | (223 | ) | |||||
| Other | (3 | ) | 35 | ||||||
| Total cash provided by (used in) investing activities | $ | 2,203 | $ | (1,014 | ) | ||||
| Cash provided by (used in) financing activities | $ | (2,197 | ) | $ | 40 | ||||
| Ending cash | $ | 849 | $ | 516 | |||||
CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF OPERATING CASH FLOW AND EBITDA ($ in millions) (unaudited) | ||||||||||||||
| THREE MONTHS ENDED: | March 31, | December 31, | March 31, | |||||||||||
| 2011 | 2010 | 2010 | ||||||||||||
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 741 | $ | 1,145 | $ | 1,183 | ||||||||
| Changes in assets and liabilities | 663 | 225 | 78 | |||||||||||
| OPERATING CASH FLOW(a) | $ | 1,404 | $ | 1,370 | $ | 1,261 | ||||||||
| THREE MONTHS ENDED: | March 31, | December 31, | March 31, | |||||||||||
| 2011 | 2010 | 2010 | ||||||||||||
| NET INCOME (LOSS) | $ | (162 | ) | $ | 223 | $ | 738 | |||||||
| Income tax expense (benefit) | (104 | ) | 140 | 462 | ||||||||||
| Interest expense | 7 | 7 | 25 | |||||||||||
| Depreciation and amortization of other assets | 68 | 61 | 50 | |||||||||||
Natural gas and oil depreciation, depletion and amortization | 358 | 368 | 308 | |||||||||||
| EBITDA (b) | $ | 167 | $ | 799 | $ | 1,583 | ||||||||
| THREE MONTHS ENDED: | March 31, | December 31, | March 31, | |||||||||||
| 2011 | 2010 | 2010 | ||||||||||||
| CASH PROVIDED BY OPERATING ACTIVITIES | $ | 741 | $ | 1,145 | $ | 1,183 | ||||||||
| Changes in assets and liabilities | 663 | 225 | 78 | |||||||||||
| Interest expense | 7 | 7 | 25 | |||||||||||
| Unrealized gains (losses) on natural gas and oil derivatives | (1,182 | ) | (628 | ) | 315 | |||||||||
| Gains on sales of other property and equipment | 5 | 154 | ? | |||||||||||
| Gains (losses) on equity investments | 5 | (13 | ) | 13 | ||||||||||
| Stock-based compensation | (40 | ) | (36 | ) | (32 | ) | ||||||||
| Other items | (32 | ) | (55 | ) | 1 | |||||||||
| EBITDA(b) | $ | 167 | $ | 799 | $ | 1,583 | ||||||||
(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 ADJUSTED EBITDA ($ in millions) (unaudited) | ||||||||||||||
| March 31, | December 31, | March 31, | ||||||||||||
| THREE MONTHS ENDED: | 2011 | 2010 | 2010 | |||||||||||
| EBITDA | $ | 167 | $ | 799 | $ | 1,583 | ||||||||
| Adjustments: | ||||||||||||||
| Unrealized (gains) losses on natural gas and oil derivatives | 1,182 | 628 | (315 | ) | ||||||||||
| (Gains) losses on sales of other property and equipment | (5 | ) | (154 | ) | ? | |||||||||
| Other impairments | ? | 1 | ? | |||||||||||
| Losses on redemptions or exchanges of debt | 2 | ? | 2 | |||||||||||
| Adjusted EBITDA(a) | $ | 1,346 | $ | 1,274 | $ | 1,270 | ||||||||
(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 ($ in millions, except per-share data) (unaudited) | ||||||||||||||
| March 31, | December 31, | March 31, | ||||||||||||
| THREE MONTHS ENDED: | 2011 | 2010 | 2010 | |||||||||||
| Net income available to common stockholders | $ | (205 | ) | $ | 180 | $ | 732 | |||||||
| Adjustments: | ||||||||||||||
| Unrealized (gains) losses on derivatives, net of tax | 725 | 392 | (209 | ) | ||||||||||
| (Gain) losses on sales of other property and equipment, net of tax | (3 | ) | (95 | ) | ? | |||||||||
| Other impairments, net of tax | ? | 1 | ? | |||||||||||
| Losses on redemptions or exchanges of debt, net of tax | 1 | ? | 1 | |||||||||||
| Adjusted net income available to common stockholders (a) | 518 | 478 | 524 | |||||||||||
| Preferred stock dividends | 43 | 43 | 6 | |||||||||||
| Total adjusted net income | $ | 561 | $ | 521 | $ | 530 | ||||||||
| Weighted average fully diluted shares outstanding(b) | 750 | 746 | 647 | |||||||||||
| Adjusted earnings per share assuming dilution(a) | $ | 0.75 | $ | 0.70 | $ | 0.82 | ||||||||
(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 MAY 2, 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 12/31/2011 | Year Ending 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
non-qualifying trades and settled values of non-qualifying 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) |
|
|
|
|
| ||||||||||||
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) |
| 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.
| Avg. NYMEX
| Forecasted
|
|
|
| ||||||||||||||
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) |
| 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 | ||||||||||
SCHEDULE 'B?
CHESAPEAKE′S OUTLOOK AS OF FEBRUARY 22, 2011
(PROVIDED
FOR REFERENCE ONLY)
NOW SUPERSEDED BY OUTLOOK AS OF MAY 2,
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 February 22, 2011, we are
using the following key assumptions in our projections for 2011 and 2012.
The primary changes from our November 3, 2010 Outlook are in italicized
bold and are explained as follows:
1) Our production
guidance has been updated and reflects anticipated asset sales;
2)
Projected effects of changes in our hedging positions have been updated;
3)
Our NYMEX natural gas and oil price assumptions for
gathering/marketing/transportation differentials have been updated;
4)
Certain cost assumptions have been updated; and
5) Our cash flow
projections have been updated, including increased drilling and
completion costs.
| Year Ending 12/31/2011 | Year Ending 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 | $4.46 | $5.50 | |||||
Oil - $/bbl | $89.96 | $90.00 | |||||
Estimated Realized Hedging Effects (based on assumed NYMEX prices above): | |||||||
Natural gas - $/mcf | $1.52 | $0.12 | |||||
Oil - $/bbl | $(0.68) | $(0.40) | |||||
Estimated Gathering/Marketing/Transportation Differentials to NYMEX Prices: | |||||||
Natural gas - $/mcf | $0.90 ? $1.10 | $0.90 ? $1.10 | |||||
Oil - $/bbl(b) | $20.00 ? $25.00 | $20.00 ? $25.00 | |||||
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 | $0.02 ? 0.04 | $0.02 ? 0.04 | |||||
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 | $5,600 ? 6,400 | |||||
Drilling and completion costs, net of joint venture carries | ($5,000 ? 5,400) | ($5,400 ? 5,800) | |||||
Note: please refer to footnotes on following page | ||
(a) | NYMEX natural gas prices have been updated for actual contract prices through February 2011 and NYMEX oil prices have been updated for actual contract prices through January 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 $90.00 per bbl in 2011 and $5.00 to $6.00 per mcf and $90.00 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 February 22, 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
non-qualifying trades and settled values of non-qualifying derivatives
related to future production periods.
The company currently has the following open natural gas swaps in place
for 2011 and 2012. In addition to the open swap positions disclosed
below, at February 22, 2011, the company had $687 million of net hedging
gains related to closed natural gas contracts and premiums collected on
call options for future production periods.
| Open Swaps (Bcf) |
|
|
|
|
| |||||||||||||
Q1 2011 | 226 | $ | 5.72 | $ | 155 | ||||||||||||||
Q2 2011 | 210 | $ | 5.27 | $ | 250 | ||||||||||||||
Q3 2011 | 205 | $ | 5.02 | $ | 200 | ||||||||||||||
Q4 2011 | 205 | $ | 5.02 | $ | 176 | ||||||||||||||
Total 2011 | 846 | $ | 5.27 | 915 | 92 | % | $ | 781 | $ | 0.85 | |||||||||
Total 2012 | 206 | $ | 6.20 | 980 | 21 | % | $ | (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) |
| Forecasted
| Call Options
| ||||||||||
Total 2011 | ? | ? | 915 | 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 | |||||||||||
The company has the following crude oil swaps in place for 2011 and
2012. In addition to the open swap positions disclosed below, at
February 22, 2011, the company had $8 million of net hedging gains
related to closed crude oil contracts and premiums collected on call
options for future production periods.
| Avg. NYMEX
|
|
|
|
| ||||||||||||||
Q1 2011 | 450 | $ | 99.39 | ? | ? | $ | 12 | ||||||||||||
Q2 2011 | 455 | $ | 99.39 | ? | ? | $ | 13 | ||||||||||||
Q3 2011 | 460 | $ | 99.39 | ? | ? | $ | 13 | ||||||||||||
Q4 2011 | 460 | $ | 99.39 | ? | ? | $ | 13 | ||||||||||||
Total 2011(a) | 1,825 | $ | 99.39 | 34,000 | 5 | % | $ | 51 | $ | 1.49 | |||||||||
Total 2012(a) | 732 | $ | 109.50 | 54,000 | 1 | % | $ | 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) |
| Forecasted
| Call Options
| ||||||||||
Q1 2011 | 1,800 | $ | 81.25 | ||||||||||
Q2 2011 | 1,820 | $ | 81.25 | ||||||||||
Q3 2011 | 1,840 | $ | 81.25 | ||||||||||
Q4 2011 | 1,840 | $ | 81.25 | ||||||||||
Total 2011 | 7,300 | $ | 81.25 | 34,000 | 21 | % | |||||||
Total 2012 | 22,139 | $ | 87.93 | 54,000 | 41 | % | |||||||
Total 2013 | 14,564 | $ | 87.20 | ||||||||||
Total 2014 | 8,707 | $ | 87.72 | ||||||||||
Total 2015 | 7,411 | $ | 85.31 | ||||||||||
Total 2016 ? 2017 | 10,600 | $ | 84.25 | ||||||||||
Chesapeake Energy Corporation
Investor Contacts:
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:
Jim Gipson, 405-935-1310
jim.gipson@chk.com