1
--------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the Fiscal Year Ended December 31, 2000
[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
COMMISSION FILE NO. 1-13726
CHESAPEAKE ENERGY CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
OKLAHOMA 73-1395733
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6100 NORTH WESTERN AVENUE 73118
OKLAHOMA CITY, OKLAHOMA (Zip Code)
(Address of principal executive offices)
(405) 848-8000
Registrant's telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- -----------------------
Common Stock, par value $.01 New York Stock Exchange
7.875% Senior Notes due 2004 New York Stock Exchange
9.625% Senior Notes due 2005 New York Stock Exchange
9.125% Senior Notes due 2006 New York Stock Exchange
8.5% Senior Notes due 2012 New York Stock Exchange
7% Cumulative Convertible Preferred Stock, par value $.01 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of Common Stock held by non-affiliates on March
23, 2001 was $1,191,694,668. At such date, there were 158,023,477 shares of
Common Stock issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
PORTIONS OF THE REGISTRANT'S DEFINITIVE PROXY STATEMENT FOR THE 2001
ANNUAL MEETING OF SHAREHOLDERS ARE INCORPORATED BY REFERENCE IN PART III
--------------------------------------------------------------------------------
2
PART I
ITEM 1. BUSINESS
GENERAL
We are among the ten largest independent natural gas producers in the
United States. Chesapeake began operations in 1989 and completed its initial
public offering in 1993. Our common stock trades on the New York Stock Exchange
under the symbol CHK. Our principal executive offices are located at 6100 North
Western Avenue, Oklahoma City, Oklahoma 73118, and our main telephone number at
that location is (405) 848-8000. Chesapeake maintains a website at
www.chkenergy.com. Information contained on our website is not part of this
report.
At the end of 2000, we owned interests in approximately 6,000 producing oil
and gas wells. Our primary operating area is the Mid-Continent region of the
United States, which includes Oklahoma, western Arkansas, southwestern Kansas
and the Texas Panhandle. Other core operating areas include: the Deep Giddings
field in Texas, which includes the Austin Chalk and Georgetown formations; the
Helmet area of northeastern British Columbia; and the Permian Basin region of
southeastern New Mexico. The following table highlights our growth since 1995:
FIVE-YEAR
ANNUAL
YEARS ENDED DECEMBER 31, AVERAGE
---------------------------------------------------------------------- GROWTH
1995 1996 1997 1998 1999 2000 RATE
-------- -------- --------- ---------- ---------- ---------- ---------
Production (mmcfe)..... 80,857 69,867 80,302 130,277 133,492 134,179 13%
Proved reserves
(mmcfe).............. 457,851 494,000 448,474 1,091,348 1,205,595 1,656,328(a) 38%
EBITDA ($ in 000's).... $ 73,600 $144,340 $ 256,421 $ 183,449 $ 218,936 $ 391,190 49%
Operating cash flow ($
in 000's)............ $ 63,366 $130,989 $ 226,639 $ 115,200 $ 137,884 $ 304,934 54%
Net income (loss) ($ in
000's)............... $ 14,451 $ 39,902 $(233,429) $ (933,854) $ 33,266 $ 455,570 191%
---------------
(a) These reserves reflect Chesapeake and Gothic on a combined basis at December
31, 2000.
BUSINESS STRATEGY
From inception in 1989, our business strategy has been to aggressively
build and develop one of the largest onshore natural gas resource bases in the
United States. We are executing our strategy by:
- continuing to grow through the drillbit by conducting what we
believe is currently one of the five most active drilling programs
in the United States. We currently have 24 rigs drilling on
Chesapeake-operated prospects and we are participating in 27 wells
being drilled by others;
- continuing to make small acquisitions of strategically located
natural gas properties that provide high quality production and
significant drilling opportunities. In 2000, we acquired
approximately $75 million of such producing properties in 97
separate transactions. Each of these acquisitions either increased
our working interest in existing wells or added additional drilling
locations in our core areas. In 2001, we have budgeted $140 million
for similar acquisitions. In our experience, smaller acquisitions
generally provide better economics than larger corporate
acquisitions;
- funding our $450 million 2001 capital expenditure plan with
operating cash flow and further reducing our debt with our projected
excess cash flow; and
- maintaining a low operating cost structure so that we can deliver
attractive financial returns from our assets in all phases of the
commodity price cycle.
Based on our view that natural gas has become the fuel of choice to meet
growing power demand and increasing environmental concerns, we believe our
strategy should provide substantial growth opportunities in the years ahead.
-1-
3
COMPANY STRENGTHS
We believe our past performance and future growth potential are primarily
attributable to five characteristics that distinguish us from other independent
oil and natural gas producers:
High-Quality Asset Base. Our properties are characterized by
long-lived reserves, established production profiles and an emphasis on
natural gas. Based upon 2000 production and our year-end reserves, our
proved reserves-to-production ratio, or reserve life, is more than ten
years. In each of our four core operating areas, our properties are
concentrated in locations that enable us to establish substantial economies
of scale in drilling and production operations and facilitate the
application of more effective reservoir management practices. We intend to
continue concentrating our acquisition and drilling efforts in our four
core operating areas, with particular emphasis on the Mid-Continent region
where approximately 74% of our proved reserves, including Gothic's
reserves, are located.
Low-Cost Producer. Our high-quality asset base has enabled us to
achieve a low operating cost structure. During 2000, our cash operating
costs per unit of production, which consist of general and administrative
expenses and production expenses and taxes, were $0.66 per mcfe. We believe
this is one of the lowest operating cost structures among publicly-traded
independent oil and natural gas producers. We operate approximately 71% of
our proved reserves, including Gothic's reserves, providing a high degree
of operating flexibility and cost control.
Successful Acquisition Program. Our acquisition program is focused
primarily in the Mid-Continent region. This region is characterized by
long-lived natural gas reserves, low lifting costs, multiple geological
targets that provide substantial drilling potential, favorable basis
differentials to benchmark commodity prices, a well-developed oil and gas
transportation infrastructure and considerable potential for further
consolidation of assets. Since 1998, we have successfully completed $1.2
billion in acquisitions at an average cost of $0.98 per mcfe. We believe we
are well positioned to continue this consolidation as a result of our large
existing asset base, our corporate presence in Oklahoma City and our
knowledge and expertise in the Mid-Continent.
Large Inventory of Drilling Projects. During the past 12 years, we
believe we have been one of the ten most active drillers in the United
States, especially of deep vertical and horizontal wells in challenging
reservoir conditions. As a result of our land acquisition strategy, we have
developed an onshore leasehold position of approximately 2.5 million net
acres. In addition, our technical teams have identified over 1,500
exploratory and developmental drillsites, representing more than five years
of future drilling opportunities at our current rate of drilling.
Entrepreneurial Management. Our management team formed Chesapeake in
1989 with an initial capitalization of $50,000. Through the following
years, our management team has guided the company through operational
challenges and extremes of oil and gas prices to create one of the ten
largest independent natural gas producers in the United States with
enterprise value at March 15, 2001 of $2.7 billion. In addition, through
its ownership of approximately 23 million shares of our common stock, our
management has a strong interest in increasing shareholder value.
2000 HIGHLIGHTS
Chesapeake's operating results for the year ended December 31, 2000
established several records for our company:
- net income of $456 million (including a $265 million reversal of a tax
valuation allowance), compared to net income of $33 million in 1999,
- operating cash flow of $305 million, compared to operating cash flow
of $138 million in 1999,
- production of 134 bcfe, of which 86% was natural gas, and
- proved oil and gas reserves of 1,656 bcfe pro forma for the Gothic
acquisition, an increase of 37% from the year ended December 31, 1999.
During 2000, we also replaced 585 bcfe of proved reserves at a replacement
cost of $1.07 per mcfe, pro forma for the Gothic acquisition.
-2-
4
GOTHIC ACQUISITION
On January 16, 2001, we completed the acquisition of Gothic with the
issuance of four million of our common shares to Gothic shareholders. Prior to
the completion of the acquisition, we purchased substantially all of Gothic
Production's 14.125% senior secured discount notes and $32 million of Gothic
Production's 11.125% senior secured notes for total consideration of $116
million in cash and our common stock. At the time of the acquisition, Gothic
Production had $235 million of 11.125% senior secured notes due in 2005
including the notes purchased by Chesapeake.
As of December 31, 2000, Gothic had proved reserves of 291 bcf of natural
gas and 1.8 mmbbls of oil (a total of 302 bcfe) with a pre-tax present value
(calculated as described in the glossary using weighted average gas and oil
prices of $10.17 per mcf and $26.57 per barrel) of approximately $1.3 billion.
These reserves, of which 85% were classified as proved developed, had an
estimated average reserve life of approximately 11 years and 96% of these
reserves were natural gas. Gothic's natural gas reserves and acreage, most of
which were acquired from Amoco Production Company, are principally located in
the Anadarko and Arkoma basins of the Mid-Continent, have low operating costs
per mcfe and are an excellent fit with our existing reserve base.
At December 31, 2000, Gothic held an interest in approximately 480,000
(229,000 net) acres and had an interest in 903 (481 net) producing wells. For
the year ended December 31, 2000, Gothic had revenues of $86 million, EBITDA of
$68 million, operating cash flow of $29 million and net income of $6 million.
Gothic's consolidated financial statements and the pro forma combined financial
statements are included in Item 8 -- Financial Statements and Supplementary
Data.
IMPROVING OUR CAPITALIZATION
We made significant progress in improving our balance sheet during 2000,
increasing common shareholders' equity by over $725 million in a combination of
preferred stock exchanges, equity issuances and earnings. Total debt obligations
and preferred stock outstanding were $1.2 billion, or $0.99 per mcfe of proved
reserves, at the beginning of 2000. These fixed obligations were reduced to $976
million, or $0.72 per mcfe of proved reserves, by the end of 2000.
We have called for redemption on May 1, 2001 all of the outstanding 624,037
shares of our 7% cumulative convertible preferred stock, which are convertible
into common stock at a conversion price of $6.95 per share. We intend to use our
common stock (other than for the redemption premium) to redeem any shares of the
outstanding preferred stock that are not converted into common stock prior to
the redemption date.
On March 29, 2001, we announced a proposed private offering to sell $800
million of senior notes due 2011 in order to lower the interest rate and extend
the maturity of approximately 74% of our senior notes. If the offering is
successfully completed, the proceeds from the proposed offering, together with
available cash and bank borrowings, would be used to redeem Chesapeake's
existing $120 million principal amount of 9.125% senior notes due 2006, $500
million principal amount of 9.625% senior notes due 2005 and $202.5 million
principal amount of 11.125% senior secured notes due 2005 of Gothic Production
Corporation, a Chesapeake subsidiary. Redemption of these notes will include
payment of aggregate make-whole and redemption premiums estimated at
approximately $74 million. The notes to be offered by Chesapeake would not be
initially registered under the Securities Act of 1933, as amended, and will not
be offered or sold in the United States absent registration or an applicable
exemption from registration requirements.
-3-
5
2001 OUTLOOK
At the present time, we believe the outlook for Chesapeake is favorable
because of our large base of high quality natural gas properties, our geological
and operational expertise and very strong natural gas and oil prices. Our goals
and the strategy to obtain those goals remain unchanged for 2001:
- replace production by more than 200% at low reserve replacement cost,
- execute a capital expenditure plan balanced between drilling and
acquisitions, funded with operating cash flow,
- maintain a superior operating cost structure,
- utilize excess cash flow above budgeted expenditures to reduce debt
both relatively and absolutely, and
- deliver attractive financial returns from our assets in all phases of
our energy cycle.
DRILLING ACTIVITY
The following table sets forth the wells we drilled during the periods
indicated. In the table, "gross" refers to the total wells in which we had a
working interest and "net" refers to gross wells multiplied by our working
interest.
YEARS ENDED DECEMBER 31,
-------------------------------------------------
1998 1999 2000
------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ----- ----- -----
United States
Development:
Productive................................... 158 93.9 167 93.3 291 142.7
Non-productive............................... 9 4.7 17 10.6 12 5.3
--- ---- --- ----- --- -----
Total........................................ 167 98.6 184 103.9 303 148.0
=== ==== === ===== === =====
Exploratory:
Productive................................... 46 23.4 9 3.7 32 17.0
Non-productive............................... 9 6.8 6 4.6 11 5.4
--- ---- --- ----- --- -----
Total........................................ 55 30.2 15 8.3 43 22.4
=== ==== === ===== === =====
Canada
Development:
Productive................................... 11 3.6 11 7.3 12 6.1
Non-productive............................... 1 0.4 1 0.2 2 .8
--- ---- --- ----- --- -----
Total........................................ 12 4.0 12 7.5 14 6.9
=== ==== === ===== === =====
Exploratory:
Productive................................... 1 0.3 -- -- -- --
Non-productive............................... 7 2.1 -- -- -- --
--- ---- --- ----- --- -----
Total........................................ 8 2.4 -- -- -- --
=== ==== === ===== === =====
At December 31, 2000, we had 46 (22.2 net) wells in process.
WELL DATA
At December 31, 2000, we had interests in approximately 6,000 (2,675 net)
producing wells, of which 270 (125 net) were classified as primarily oil
producing wells and 5,730 (2,550 net) were classified as primarily gas producing
wells. Chesapeake operates approximately 4,000 of the total 6,000 producing
wells.
Including Gothic's wells as of December 31, 2000, our producing well count
increases to approximately 6,700 (3,200 net) wells, of which Chesapeake operates
4,300.
-4-
6
PRODUCTION, SALES, PRICES AND EXPENSES
The following table sets forth information regarding the production
volumes, oil and gas sales, average sales prices received and expenses for the
periods indicated:
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------------------------------------
1998 1999 2000
---------------------------- ----------------------------- -----------------------------
U.S. CANADA COMBINED U.S. CANADA COMBINED U.S. CANADA COMBINED
-------- ------ -------- -------- ------- -------- -------- ------- --------
NET PRODUCTION:
Oil (mbbl).................... 5,975 1 5,976 4,147 -- 4,147 3,068 -- 3,068
Gas (mmcf).................... 86,681 7,740 94,421 96,873 11,737 108,610 103,694 12,077 115,771
Gas equivalent (mmcfe)........ 122,531 7,746 130,277 121,755 11,737 133,492 122,102 12,077 134,179
OIL AND GAS SALES ($ IN THOUSANDS):
Oil........................... $ 75,867 $ 10 $75,877 $ 66,413 $ -- $66,413 $ 80,953 $ -- $ 80,953
Gas........................... 173,042 7,968 181,010 200,055 13,977 214,032 355,391 33,826 389,217
-------- ------ -------- -------- ------- -------- -------- ------- --------
Total oil and gas
sales................. $248,909 $7,978 $256,887 $266,468 $13,977 $280,445 $436,344 $33,826 $470,170
======== ====== ======== ======== ======= ======== ======== ======= ========
AVERAGE SALES PRICE:
Oil ($ per bbl)............... $ 12.70 $10.00 $ 12.70 $ 16.01 $ -- $ 16.01 $ 26.39 $ -- $ 26.39
Gas ($ per mcf)............... $ 2.00 $1.03 $ 1.92 $ 2.07 $ 1.19 $ 1.97 $ 3.43 $ 2.80 $ 3.36
Gas equivalent ($ per mcfe)... $ 2.03 $1.03 $ 1.97 $ 2.19 $ 1.19 $ 2.10 $ 3.57 $ 2.80 $ 3.50
EXPENSES ($ PER mcfe):
Production expenses........... $ 0.40 $0.24 $ 0.39 $ 0.36 $ 0.18 $ 0.35 $ 0.38 $ 0.32 $ 0.37
Production taxes.............. $ 0.07 $ -- $ 0.06 $ 0.11 $ -- $ 0.10 $ 0.20 $ -- $ 0.19
General and administrative.... $ 0.16 $0.06 $ 0.15 $ 0.10 $ 0.08 $ 0.10 $ 0.09 $ 0.17 $ 0.10
Depreciation, depletion and
amortization................ $ 1.17 $0.43 $ 1.13 $ 0.73 $ 0.52 $ 0.71 $ 0.76 $ 0.71 $ 0.75
Our hedging activities resulted in an increase in oil and gas revenues of
$11.3 million in 1998, a decrease of $1.7 million in 1999, and a decrease of
$30.6 million in 2000.
In January 2001, Chesapeake acquired Gothic with properties primarily
located in the Mid-Continent. For the year ended December 31, 2000, Gothic
reported $83 million of oil and gas sales and 27 bcfe of production.
PROVED RESERVES
The following table sets forth our estimated proved reserves and the
present value of the proved reserves, based on our weighted average prices at
December 31, 2000 of $26.41 per barrel of oil and $10.12 per mcf of gas. These
prices were based on the adjusted cash spot prices for oil and natural gas at
December 31, 2000.
PERCENT
GAS OF PRESENT
OIL GAS EQUIVALENT PROVED VALUE
(MBBL) (MMCF) (MMCFE) RESERVES ($ IN THOUSANDS)
------ --------- ---------- -------- ----------------
Mid-Continent....................... 13,944 883,221 966,887 71% $4,293,715
Gulf Coast.......................... 4,010 133,661 157,719 12 825,891
Canada.............................. -- 158,964 158,964 12 680,800
Permian Basin....................... 873 16,209 21,445 2 117,190
Other areas......................... 4,970 19,978 49,798 3 128,432
------ --------- --------- --- ----------
Total....................... 23,797 1,212,033 1,354,813 100% $6,046,028
====== ========= ========= === ==========
During 2000, we increased the present value of our proved developed
reserves to 69% and increased the volume of our proved developed reserves to 70%
of total proved reserves. Natural gas reserves accounted for 89% of proved
reserves at December 31, 2000.
As a result of the January 2001 acquisition of Gothic, Chesapeake acquired
total proved reserves of 302 bcfe at December 31, 2000, with an associated
present value of proved reserves of $1.3 billion based on Gothic's weighted
average prices at December 31, 2000 of $26.57 per barrel of oil and $10.17 per
mcf of gas. The following reserve data show the pro forma combined proved
reserves of Chesapeake and Gothic as of
-5-
7
December 31, 2000 based on combined weighted average prices of $26.42 per barrel
of oil and $10.13 per mcf of gas:
PERCENT
GAS OF PRESENT
OIL GAS EQUIVALENT PROVED VALUE
(MBBL) (MMCF) (MMCFE) RESERVES ($ IN THOUSANDS)
------ --------- ---------- -------- ----------------
Mid-Continent....................... 15,049 1,140,801 1,231,097 74% $5,425,407
Gulf Coast.......................... 4,010 133,661 157,719 9 825,891
Canada.............................. -- 158,964 158,964 10 680,800
Permian Basin....................... 1,536 49,536 58,750 4 252,001
Other areas......................... 4,970 19,978 49,798 3 128,432
------ --------- --------- --- ----------
Total....................... 25,565 1,502,940 1,656,328 100% $7,312,531
====== ========= ========= === ==========
Actual future prices and costs may be materially higher or lower than the
prices and costs as of the date of any estimate. A change in price of $0.10 per
mcf for natural gas and $1.00 per barrel for oil would result in:
- a change in our December 31, 2000 present value of proved reserve of
$62 million and $13 million, respectively;
- a change in the December 31, 2000 present value of proved reserves for
us and Gothic combined of $75 million and $14 million, respectively.
If the present value of our combined pro forma proved reserves were
calculated using a more recent approximation of NYMEX spot prices of $24.00 per
barrel of oil and $5.00 per mcf of gas, adjusted for our price differentials,
the present value of our combined pro forma proved reserves at December 31, 2000
would have been $3.2 billion.
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table sets forth information regarding the costs we have
incurred in our development, exploration and acquisition activities during the
periods indicated:
YEARS ENDED DECEMBER 31,
--------------------------------
1998 1999 2000
-------- -------- --------
($ IN THOUSANDS)
Development and leasehold costs............................. $150,241 $124,118 $151,844
Exploration costs........................................... 68,672 23,693 24,658
Acquisition costs:
Proved properties......................................... 740,280 52,093 75,285
Unproved properties....................................... 26,369 2,747 3,625
Sales of oil and gas properties............................. (15,712) (45,635) (1,529)
Capitalized internal costs.................................. 5,262 2,710 6,958
-------- -------- --------
Total............................................... $975,112 $159,726 $260,841
======== ======== ========
-6-
8
ACREAGE
The following table sets forth as of December 31, 2000 the gross and net
acres of both developed and undeveloped oil and gas leases which we hold.
"Gross" acres are the total number of acres in which we own a working interest.
"Net" acres refer to gross acres multiplied by our fractional working interest.
Acreage numbers are stated in thousands and do not include our options to
acquire additional leasehold which have not been exercised.
TOTAL DEVELOPED
DEVELOPED UNDEVELOPED AND UNDEVELOPED
-------------------- ---------------------- ----------------------
GROSS NET GROSS NET GROSS NET
--------- ------- --------- --------- --------- ---------
Mid-Continent................................. 1,748,880 676,237 427,289 231,293 2,176,169 907,530
Gulf Coast.................................... 225,182 133,595 485,331 436,132 710,513 569,727
Canada........................................ 102,838 51,328 638,125 308,719 740,963 360,047
Permian Basin................................. 7,307 4,582 33,717 16,731 41,024 21,313
Other Areas................................... 41,049 13,036 607,185 382,738 648,234 395,774
--------- ------- --------- --------- --------- ---------
Total................................. 2,125,256 878,778 2,191,647 1,375,613 4,316,903 2,254,391
========= ======= ========= ========= ========= =========
As of December 31, 2000, Gothic held an interest in approximately 480,000
(229,000 net) acres, almost all of which was in the Mid-Continent.
MARKETING
Chesapeake's oil production is sold under market sensitive or spot price
contracts. Our natural gas production is sold to purchasers under
percentage-of-proceeds and percentage-of-index contracts or by direct marketing
to end users or aggregators. By the terms of the percentage-of-proceeds
contracts, we receive a percentage of the resale price received by the purchaser
for sales of residue gas and natural gas liquids recovered after gathering and
processing our gas. The residue gas and natural gas liquids sold by these
purchasers are sold primarily based on spot market prices. The revenue we
receive from the sale of natural gas liquids is included in natural gas sales.
Under percentage-of-index contracts, the price per mmbtu we receive for our gas
at the wellhead is tied to indexes published in Inside FERC or Gas Daily. During
2000, sales to Aquila Southwest Pipeline Corporation of $54.9 million accounted
for 12% of our total oil and gas sales. Management believes that the loss of
this customer would not have a material adverse effect on our results of
operations or our financial position. No other customer accounted for more than
10% of total oil and gas sales in 2000.
Chesapeake Energy Marketing, Inc., a wholly-owned subsidiary, provides
marketing services including commodity price structuring, contract
administration and nomination services for Chesapeake, its partners and other
oil and natural gas producers in certain geographical areas in which we are
active. CEMI is a reportable segment under SFAS No. 131 "Disclosure about
Segments of an Enterprise and Related Information." See note 8 of notes to
consolidated financial statements in Item 8.
HEDGING ACTIVITIES
We utilize hedging strategies to hedge the price of a portion of our future
oil and gas production and to manage fixed interest rate exposure. See Item
7A -- Quantitative and Qualitative Disclosures About Market Risk.
RISK FACTORS
You should carefully consider the following risk factors in addition to the
other information included in this report. Each of these risk factors could
adversely affect our business, operating results and financial condition, as
well as adversely affect the value of an investment in our common stock or other
securities.
-7-
9
Oil and gas prices are volatile. A decline in prices could adversely affect our
financial results, cash flows, access to capital and ability to grow.
Our revenues, operating results, profitability, future rate of growth and
the carrying value of our oil and gas properties depend primarily upon the
prices we receive for our oil and gas. Prices also affect the amount of cash
flow available for capital expenditures and our ability to borrow money or raise
additional capital. The amount we can borrow from banks is subject to
semi-annual redeterminations based on current prices at the time of
redetermination. In addition, we may have ceiling test writedowns if prices
decline significantly from present levels.
Historically, the markets for oil and gas have been volatile and they are
likely to continue to be volatile. The prices we are currently receiving for our
production are near or at historic highs. Wide fluctuations in oil and gas
prices may result from relatively minor changes in the supply of and demand for
oil and natural gas, market uncertainty and other factors that are beyond our
control, including:
- worldwide and domestic supplies of oil and gas,
- weather conditions,
- the level of consumer demand,
- the price and availability of alternative fuels,
- the availability of pipeline capacity,
- the price and level of foreign imports,
- domestic and foreign governmental regulations and taxes,
- the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls,
- political instability or armed conflict in oil-producing regions, and
- the overall economic environment.
These factors and the volatility of the energy markets make it extremely
difficult to predict future oil and gas price movements with any certainty.
Declines in oil and gas prices would not only reduce revenue, but could reduce
the amount of oil and gas that we can produce economically and, as a result,
could have a material adverse effect on our financial condition, results of
operations and reserves. Further, oil and gas prices do not necessarily move in
tandem. Because approximately 91% of our proved reserves are currently natural
gas reserves, we are more susceptible to movements in natural gas prices.
Our level of indebtedness may adversely affect operations, and we may have
difficulty repaying long-term indebtedness as it matures.
As of December 31, 2000, we had long-term indebtedness of $945 million,
which included bank indebtedness of $25 million. Our long-term indebtedness
represented 75% of our total capitalization at December 31, 2000. If the Gothic
merger had been completed as of December 31, 2000, our long-term indebtedness,
on a pro forma basis, would have been $1.16 billion.
Our level of indebtedness affects our operations in several ways, including
the following:
- a portion of our cash flows must be used to service our indebtedness;
for example, for the year ended December 31, 2000, approximately 22%
of EBITDA (23% of EBITDA on a pro forma basis for the Gothic
acquisition) was used to pay interest on our borrowings,
- the covenants contained in the agreements governing our outstanding
indebtedness limit our ability to borrow additional funds, dispose of
assets, pay dividends and make certain investments,
- our debt covenants may also affect our flexibility in planning for,
and reacting to, changes in the economy and in our industry, and
- a high level of debt may impair our ability to obtain additional
financing in the future for working capital, capital expenditures,
acquisitions, general corporate or other purposes.
We may incur additional debt, including significant secured indebtedness,
in order to make future acquisitions or to develop our properties. A higher
level of indebtedness increases the risk that we may default
-8-
10
on our debt obligations. Our ability to meet our debt obligations and to reduce
our level of debt depends on our future performance. General economic
conditions, oil and gas prices and financial, business and other factors affect
our operations and our future performance. Many of these factors are beyond our
control. We cannot assure you that we will be able to generate sufficient cash
flow to pay the interest on our debt or that future working capital, borrowings
or equity financing will be available to pay or refinance such debt. Factors
that will affect our ability to raise cash through an offering of our capital
stock or a refinancing of our debt include financial market conditions and the
value of our assets and our performance at the time we need capital.
In addition, our bank borrowing base is subject to semi-annual
redeterminations. We could be forced to repay a portion of our bank borrowings
due to redeterminations of our borrowing base. We cannot assure you that we will
have sufficient funds to make such repayments. If we do not have sufficient
funds and are otherwise unable to negotiate renewals of our borrowings or
arrange new financing, we may have to sell significant assets. Any such sale
could have a material adverse effect on our business and financial results.
Higher oil and gas prices adversely affect the cost and availability of drilling
and production services.
Higher oil and gas prices, such as those we are currently experiencing,
generally stimulate increased demand and result in increased prices for drilling
rigs, crews and associated supplies, equipment and services. We have recently
experienced significantly higher costs for drilling rigs and other related
services and expect such costs to continue to escalate in 2001.
Our industry is extremely competitive.
The energy industry is extremely competitive. This is especially true with
regard to exploration for, and development and production of, new sources of oil
and natural gas. As an independent producer of oil and natural gas, we
frequently compete against companies that are larger and financially stronger in
acquiring properties suitable for exploration, in contracting for drilling
equipment and other services and in securing trained personnel.
Our commodity price risk management activities have reduced the realized prices
received for our oil and gas sales and these transactions may limit our realized
oil and gas sales prices in the future.
In order to manage our exposure to price volatility in marketing our oil
and gas, we enter into oil and gas price risk management arrangements for a
portion of our expected production. These transactions are limited in life.
While intended to reduce the effects of volatile oil and gas prices, commodity
price risk management transactions may limit the prices we actually realize. In
2000, we recorded reductions to oil and gas revenues of $30.6 million related to
commodity price risk management activities. We cannot assure you that we will
not experience additional reductions to oil and gas revenues from our commodity
price risk management. If the hedges in existence at December 31, 2000 had been
settled on that date, based upon futures prices as of that date, we would have
incurred a loss of $89.3 million, which would have been recognized as price
adjustments during the related months of future production. In addition, our
commodity price risk management transactions may expose us to the risk of
financial loss in certain circumstances, including instances in which:
- our production is less than expected,
- there is a widening of price differentials between delivery points for
our production and the delivery point assumed in the hedge
arrangement, or
- the counterparties to our contracts fail to perform the contracts.
Some of our commodity price risk management arrangements require us to
deliver cash collateral or other assurances of performance to the counterparties
in the event that our payment obligations with respect to our commodity price
risk management transactions exceed certain levels. Our collateral requirement
for these activities at December 31, 2000 was $35 million, consisting of $31.5
million in letters of credit and $3.5 million in cash deposits. Future
collateral requirements are uncertain, but will depend on arrangements with our
counterparties and highly volatile natural gas and oil prices.
-9-
11
Estimates of oil and gas reserves are uncertain and inherently imprecise.
This report contains estimates of our proved reserves and the estimated
future net revenues from our proved reserves, including those acquired in the
Gothic acquisition. These estimates are based upon various assumptions,
including assumptions required by the SEC relating to oil and gas prices,
drilling and operating expenses, capital expenditures, taxes and availability of
funds. The process of estimating oil and gas reserves is complex. The process
involves significant decisions and assumptions in the evaluation of available
geological, geophysical, engineering and economic data for each reservoir.
Therefore, these estimates are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves most likely will vary from these estimates. Such variations may be
significant and could materially affect the estimated quantities and present
value of our proved reserves. In addition, we may adjust estimates of proved
reserves to reflect production history, results of exploration and development
drilling, prevailing oil and gas prices and other factors, many of which are
beyond our control. Our properties may also be susceptible to hydrocarbon
drainage from production by operators on adjacent properties.
At December 31, 2000, approximately 30% (27% on a pro forma basis for the
Gothic acquisition) by volume of our estimated proved reserves were undeveloped.
Recovery of undeveloped reserves requires significant capital expenditures and
successful drilling operations. The estimates of these reserves include the
assumption that we will make significant capital expenditures to develop the
reserves, including $216 million ($235 million on a pro forma basis for the
Gothic acquisition) in 2001. Although we have prepared estimates of our oil and
gas reserves and the costs associated with these reserves in accordance with
industry standards, we cannot assure you that the estimated costs are accurate,
that development will occur as scheduled or that the results will be as
estimated.
You should not assume that the present values referred to in this report
represent the current market value of our estimated oil and gas reserves. In
accordance with SEC requirements, the estimates of our present values are based
on prices and costs as of the date of the estimates. The combined December 31,
2000 present values pro forma for Gothic are based on combined weighted average
oil and gas prices of $26.42 per barrel of oil and $10.13 per mcf of natural
gas, compared to our weighted average prices of $24.72 per barrel of oil and
$2.25 per mcf of natural gas used in computing Chesapeake's December 31, 1999
present value. Actual future prices and costs may be materially higher or lower
than the prices and costs as of the date of an estimate. A change in price of
$0.10 per mcf and $1.00 per barrel would result in:
- a change in our December 31, 2000 present value of proved reserves of
$62 million and $13 million, respectively; and
- a change in the December 31, 2000 present value of proved reserves for
us and Gothic combined of $75 million and $14 million, respectively.
If the present value of our combined pro forma proved reserves were
calculated using a more recent approximation of NYMEX spot prices of $24.00 per
barrel of oil and $5.00 per mcf of gas, adjusted for our price differentials,
the present value of our combined pro forma proved reserves at December 31, 2000
would have been $3.2 billion.
Any changes in consumption by oil and gas purchasers or in governmental
regulations or taxation will also affect actual future net cash flows.
The timing of both the production and the expenses from the development and
production of oil and gas properties will affect both the timing of actual
future net cash flows from proved reserves and their present value. In addition,
the 10% discount factor, which is required by the SEC to be used in calculating
discounted future net cash flows for reporting purposes, is not necessarily the
most accurate discount factor. The effective interest rate at various times and
the risks associated with our business or the oil and gas industry in general
will affect the accuracy of the 10% discount factor.
-10-
12
If we are not able to replace reserves, we may not be able to sustain
production.
Our future success depends largely upon our ability to find, develop or
acquire additional oil and gas reserves that are economically recoverable.
Unless we replace the reserves we produce through successful development,
exploration or acquisition, our proved reserves will decline over time. In
addition, approximately 30% (27% on a pro forma basis for the Gothic
acquisition) of our total estimated proved reserves at December 31, 2000 were
undeveloped. By their nature, undeveloped reserves are less certain. Recovery of
such reserves will require significant capital expenditures and successful
drilling operations. We cannot assure you that we can successfully find and
produce reserves economically in the future. In addition, we may not be able to
acquire proved reserves at acceptable costs.
If we do not make significant capital expenditures, we may not be able to
replace reserves.
Our exploration, development and acquisition activities require substantial
capital expenditures. Historically, we have funded our capital expenditures
through a combination of cash flows from operations, our bank credit facility,
debt and equity issuances and the sale of non-core assets. Future cash flows are
subject to a number of variables, such as the level of production from existing
wells, prices of oil and gas, and our success in developing and producing new
reserves. If revenue were to decrease as a result of lower oil and gas prices or
decreased production, and our access to capital were limited, we would have a
reduced ability to replace our reserves. If our cash flow from operations is not
sufficient to fund our capital expenditure budget, there can be no assurance
that additional bank debt, debt or equity issuances or other methods of
financing will be available to meet these requirements.
Acquisitions are subject to the uncertainties of evaluating recoverable reserves
and potential liabilities.
Our recent growth is due in part to acquisitions of exploration and
production companies and producing properties. We expect acquisitions will also
contribute to our future growth. Successful acquisitions require an assessment
of a number of factors, many of which are beyond our control. These factors
include recoverable reserves, exploration potential, future oil and gas prices,
operating costs and potential environmental and other liabilities. Such
assessments are inexact and their accuracy is inherently uncertain. In
connection with our assessments, we perform a review of the acquired properties,
which we believe is generally consistent with industry practices. However, such
a review will not reveal all existing or potential problems. In addition, our
review may not permit us to become sufficiently familiar with the properties to
fully assess their deficiencies and capabilities. We do not inspect every well.
Even when we inspect a well, we do not always discover structural, subsurface
and environmental problems that may exist or arise.
We are generally not entitled to contractual indemnification for preclosing
liabilities, including environmental liabilities. Normally, we acquire interests
in properties on an "as is" basis with limited remedies for breaches of
representations and warranties. In addition, competition for producing oil and
gas properties is intense and many of our competitors have financial and other
resources which are substantially greater than those available to us. Therefore,
we cannot assure you that we will be able to acquire oil and gas properties that
contain economically recoverable reserves or that we will complete such
acquisitions on acceptable terms.
Additionally, significant acquisitions can change the nature of our
operations and business depending upon the character of the acquired properties,
which may have substantially different operating and geological characteristics
or be in different geographic locations than our existing properties. While it
is our current intention to continue to concentrate on acquiring properties with
development and exploration potential located in the Mid-Continent region, there
can be no assurance that in the future we will not decide to pursue acquisitions
or properties located in other geographic regions. To the extent that such
acquired properties are substantially different than our existing properties,
our ability to efficiently realize the economic benefits of such transactions
may be limited.
Oil and gas drilling and producing operations are hazardous and expose us to
environmental liabilities.
Oil and gas operations are subject to many risks, including well blowouts,
cratering and explosions, pipe failure, fires, formations with abnormal
pressures, uncontrollable flows of oil, natural gas, brine or well fluids,
-11-
13
and other environmental hazards and risks. Our drilling operations involve risks
from high pressures and from mechanical difficulties such as stuck pipes,
collapsed casings and separated cables. If any of these risks occurs, we could
sustain substantial losses as a result of:
- injury or loss of life,
- severe damage to or destruction of property, natural resources and
equipment,
- pollution or other environmental damage,
- clean-up responsibilities,
- regulatory investigations and penalties, and
- suspension of operations.
Our liability for environmental hazards includes those created either by
the previous owners of properties that we purchase or lease or by acquired
companies prior to the date we acquire them. In accordance with industry
practice, we maintain insurance against some, but not all, of the risks
described above. We cannot assure you that our insurance will be adequate to
cover casualty losses or liabilities. Also, we cannot predict the continued
availability of insurance at premium levels that justify its purchase.
Exploration and development drilling may not result in commercially productive
reserves.
We do not always encounter commercially productive reservoirs through our
drilling operations. We cannot assure you that the new wells we drill or
participate in will be productive or that we will recover all or any portion of
our investment in wells drilled. The seismic data and other technologies we use
do not allow us to know conclusively prior to drilling a well that oil or gas is
present or may be produced economically. The cost of drilling, completing and
operating a well is often uncertain, and cost factors can adversely affect the
economics of a project. Our efforts will be unprofitable if we drill dry wells
or wells that are productive but do not produce enough reserves to return a
profit after drilling, operating and other costs. Further, our drilling
operations may be curtailed, delayed or canceled as a result of a variety of
factors, including:
- unexpected drilling conditions,
- title problems,
- pressure or irregularities in formations,
- equipment failures or accidents,
- adverse weather conditions,
- compliance with environmental and other governmental requirements, and
- cost of, or shortages or delays in the availability of, drilling rigs
and equipment.
Canadian operations present the risks associated with conducting business
outside the United States.
Our operations in Canada are subject to the risks associated with operating
outside of the U.S. These risks include the following:
- adverse local political or economic developments,
- exchange controls,
- currency fluctuations,
- royalty and tax increases,
- retroactive tax claims,
- negotiations of contracts with governmental entities, and
- import and export regulations.
In addition, in the event of a dispute, we may be required to litigate the
dispute in Canadian courts since we may not be able to sue foreign persons in a
U.S. court.
The loss of key personnel could adversely affect our ability to operate.
We depend, and will continue to depend in the foreseeable future, on the
services of our officers and key employees with extensive experience and
expertise in evaluating and analyzing producing oil and gas
-12-
14
properties and drilling prospects, maximizing production from oil and gas
properties and marketing oil and gas production. Our ability to retain our
officers and key employees is important to our continued success and growth. The
unexpected loss of the services of one or more of these individuals could have a
detrimental effect on our business. We have maintained $20 million key man life
insurance policies on each of our chief executive officer and chief operating
officer but do not intend to renew these policies when they expire on June 1,
2001.
Transactions with executive officers may create conflicts of interest.
Our chief executive officer and chief operating officer, Aubrey K.
McClendon and Tom L. Ward, have the right to participate in wells we drill
subject to limitations in their employment contracts. As a result of their
participation, they routinely have significant accounts payable to us for joint
interest billings and other related advances. As of December 31, 2000, Messrs.
McClendon and Ward had payables to us of $2.0 million and $2.3 million,
respectively, in connection with such participation.
REGULATION
General. Numerous departments and agencies, foreign, federal, state and
local, issue rules and regulations binding on the oil and gas industry, some of
which carry substantial penalties for failure to comply. This regulatory burden
increases our cost of doing business and, consequently, affects our
profitability.
Exploration and Production. Our domestic operations are subject to various
types of regulation at the federal, state and local levels. Such regulation
includes requirements for permits to drill and to conduct other operations, and
for provision of financial assurances (such as bonds) covering drilling and well
operations. Other domestic activities subject to regulation are:
- the location of wells,
- the method of drilling and completing wells,
- the surface use and restoration of properties upon which wells are
drilled,
- the plugging and abandoning of wells,
- the disposal of fluids used or other wastes obtained in connection
with operations,
- the marketing, transportation and reporting of production, and
- the valuation and payment of royalties.
Our Canadian operations are subject to similar regulations.
Our operations are also subject to various conservation regulations. These
include the regulation of the size of drilling and spacing units (regarding the
density of wells which may be drilled in a particular area), and the unitization
or pooling of oil and gas properties. In this regard, some states, such as
Oklahoma, allow the forced pooling or integration of tracts to facilitate
exploration, while other states, such as Texas, rely on voluntary pooling of
lands and leases. In areas where pooling is voluntary, it may be more difficult
to form units and, therefore, more difficult to fully develop a project if the
operator owns less than 100% of the leasehold. In addition, state conservation
laws establish maximum rates of production from oil and gas wells, generally
prohibit the venting or flaring of gas and impose certain requirements regarding
the ratability of production. The effect of these regulations is to limit the
amount of oil and gas we can produce and to limit the number of wells or the
locations at which we can drill.
We do not anticipate that compliance with existing laws and regulations
governing exploration and production will have a significantly adverse effect
upon our capital expenditures, earnings or competitive position.
-13-
15
Environmental Regulation. Various federal, foreign, state and local laws
and regulations concerning the discharge of contaminants into the environment,
the generation, storage, transportation and disposal of contaminants, and the
protection of public health, natural resources, wildlife and the environment
affect our exploration, development and production operations. Such regulation
has increased the cost of planning, designing, drilling, operating and
abandoning wells. In most instances, the regulatory requirements relate to the
handling and disposal of drilling and production waste products, water and air
pollution control procedures, and the remediation of petroleum-product
contamination. In addition, our operations require us to obtain permits for,
among other things,
- discharges into surface waters,
- discharges of storm water runoff,
- the construction of facilities in wetland areas, and
- the construction and operation of underground injection wells or
surface pits to dispose of produced saltwater and other nonhazardous
oilfield wastes.
Under state and federal laws, we could be required to remove or remediate
previously disposed wastes, including wastes disposed of or released by us or
prior owners or operators, to suspend or cease operations in contaminated areas,
or to perform remedial plugging operations to prevent future contamination. The
Environmental Protection Agency and various state agencies have limited the
disposal options for hazardous and nonhazardous wastes. The owner and operator
of a site, and persons that treated, disposed of or arranged for the disposal of
hazardous substances found at a site, may be liable, without regard to fault or
the legality of the original conduct, for the release of a hazardous substance
into the environment. The Environmental Protection Agency, state environmental
agencies and, in some cases, third parties are authorized to take actions in
response to threats to human health or the environment and to seek to recover
from responsible classes of persons the costs of such action. Furthermore,
certain wastes generated by our oil and natural gas operations that are
currently exempt from treatment as hazardous wastes may in the future be
designated as hazardous wastes, and therefore be subject to considerably more
rigorous and costly operating and disposal requirements.
Federal and state occupational safety and health laws require us to
organize information about hazardous materials used, released or produced in our
operations. Certain portions of this information must be provided to employees,
state and local governmental authorities and local citizens. We are also subject
to the requirements and reporting set forth in federal workplace standards.
We have made and will continue to make expenditures to comply with
environmental regulations and requirements. These are necessary business costs
in the oil and gas industry. We maintain insurance coverage which we believe is
customary in the industry, although we are not fully insured against all
environmental risks. Moreover, it is possible that other developments, such as
stricter and more comprehensive environmental laws and regulations, as well as
claims for damages to property or persons resulting from company operations,
could result in substantial costs and liabilities, including civil and criminal
penalties, to Chesapeake. We believe we are in substantial compliance with
existing environmental regulations, and that, absent the occurrence of an
extraordinary event the effect of which cannot be predicted, any noncompliance
will not have a material adverse effect on our operations or earnings.
INCOME TAXES
At December 31, 2000, Chesapeake had federal and state income tax net
operating loss (NOL) carryforwards of approximately $567 million. Additionally,
we had approximately $301 million of alternative minimum tax (AMT) NOL
carryforwards available as a deduction against future AMT income and
approximately $5 million of percentage depletion carryforwards. The NOL
carryforwards expire from 2009 through 2019. The value of these carryforwards
depends on the ability of Chesapeake to generate taxable income. In addition,
for AMT purposes, only 90% of AMT income in any given year may be offset by AMT
NOLs.
-14-
16
The ability of Chesapeake to utilize NOL carryforwards to reduce future
federal taxable income and federal income tax of Chesapeake is subject to
various limitations under the Internal Revenue Code of 1986, as amended. The
utilization of such carryforwards may be limited upon the occurrence of certain
ownership changes, including the issuance or exercise of rights to acquire
stock, the purchase or sale of stock by 5% stockholders, as defined in the
Treasury regulations, and the offering of stock by us during any three-year
period resulting in an aggregate change of more than 50% in the beneficial
ownership of Chesapeake.
In the event of an ownership change, Section 382 of the Code imposes an
annual limitation on the amount of a corporation's taxable income that can be
offset by these carryforwards. The limitation is generally equal to the product
of (i) the fair market value of the equity of the company multiplied by (ii) a
percentage approximately equivalent to the yield on long-term tax exempt bonds
during the month in which an ownership change occurs. In addition, the
limitation is increased if there are recognized built-in gains during any post-
change year, but only to the extent of any net unrealized built-in gains (as
defined in the Code) inherent in the assets sold. Chesapeake had ownership
changes in January 1995 and March 1998 which triggered the limitations. Of the
$567 million NOLs and $301 million AMT NOLs, $254 million and $25 million,
respectively, are limited under Section 382. Therefore, $313 million of the NOLs
and $276 million of the AMT NOLs are not subject to the limitation. The
utilization of $254 million of the NOLs and the utilization of $25 million of
the AMT NOLs subject to the Section 382 limitation are both limited to
approximately $26 million each taxable year. Although no assurances can be made,
we do not believe that an additional ownership change has occurred as of
December 31, 2000, or will occur as a result of the issuance of the common stock
in 2001 related to the acquisition of Gothic. Equity transactions after the date
hereof by Chesapeake or by 5% stockholders (including relatively small
transactions and transactions beyond our control) could cause an ownership
change and therefore a limitation on the annual utilization of NOLs.
In the event of another ownership change, the amount of Chesapeake's NOLs
available for use each year will depend upon future events that cannot currently
be predicted and upon interpretation of complex rules under Treasury
regulations. If less than the full amount of the annual limitation is utilized
in any given year, the unused portion may be carried forward and may be used in
addition to successive years' annual limitation.
We expect to utilize our NOL carryforwards and other tax deductions and
credits to offset taxable income in the near future. However, there is no
assurance that the Internal Revenue Service will not challenge these
carryforwards or their utilization.
TITLE TO PROPERTIES
Our title to properties is subject to royalty, overriding royalty, carried,
net profits, working and other similar interests and contractual arrangements
customary in the oil and gas industry, to liens for current taxes not yet due
and to other encumbrances. As is customary in the industry in the case of
undeveloped properties, only cursory investigation of record title is made at
the time of acquisition. Drilling title opinions are usually prepared before
commencement of drilling operations. From time to time, Chesapeake's title to
oil and gas properties is challenged through legal proceedings. We are routinely
involved in litigation involving title to certain of our oil and gas properties,
some of which management believes could be adverse to us, individually or in the
aggregate. See Item 3 -- Legal Proceedings.
OPERATING HAZARDS AND INSURANCE
The oil and gas business involves a variety of operating risks, including
the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured
formations and environmental hazards such as oil spills, gas leaks, ruptures or
discharges of toxic gases, the occurrence of any of which could result in
substantial losses to Chesapeake due to injury or loss of life, severe damage to
or destruction of property, natural resources and equipment, pollution or other
environmental damage, clean-up responsibilities, regulatory investigation and
penalties and suspension of operations. Our horizontal and deep drilling
activities involve greater risk of mechanical problems than vertical and shallow
drilling operations.
Chesapeake maintains a $50 million oil and gas lease operator policy that
insures against certain sudden and accidental risks associated with drilling,
completing and operating our wells. There can be no assurance
-15-
17
that this insurance will be adequate to cover any losses or exposure to
liability. We also carry comprehensive general liability policies and a $75
million umbrella policy. Chesapeake and our subsidiaries carry workers'
compensation insurance in all states in which we operate and a $1 million
employment practice liability policy. While we believe these policies are
customary in the industry, they do not provide complete coverage against all
operating risks.
EMPLOYEES
Chesapeake had 462 full-time employees as of December 31, 2000. No
employees are represented by organized labor unions. We believe our employee
relations are good.
FACILITIES
Chesapeake owns an office building complex in Oklahoma City and field
offices in Lindsay and Waynoka, Oklahoma; Garden City, Kansas; and Borger,
Texas. Chesapeake leases office space in Oklahoma City, Watonga and Weatherford,
Oklahoma; Navasota, Texas; and Dickinson, North Dakota.
-16-
18
GLOSSARY
The terms defined in this section are used throughout this Form 10-K.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet of gas equivalent.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Commercial Well; Commercially Productive Well. An oil and gas well which
produces oil and gas in sufficient quantities such that proceeds from the sale
of such production exceed production expenses and taxes.
Developed Acreage. The number of acres which are allocated or assignable
to producing wells or wells capable of production.
Development Well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Hole; Dry Well. A well found to be incapable of producing either oil
or gas in sufficient quantities to justify completion as an oil or gas well.
EBITDA. Net income (loss) before interest expense, income taxes,
depreciation, depletion and amortization, impairments of oil and gas properties
and other assets, extraordinary items, and certain other non-cash charges.
EBITDA is not a measure of cash flow as determined by generally accepted
accounting principles. EBITDA information has been included in this report
because EBITDA is a measure used by some investors in determining historical
ability to service indebtedness. EBITDA should not be considered as an
alternative to, or more meaningful than, net income or cash flows as determined
in accordance with generally accepted accounting principles as an indicator of
operating performance or liquidity.
Exploratory Well. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir or to extend a known reservoir.
Farmout. An assignment of an interest in a drilling location and related
acreage conditional upon the drilling of a well on that location.
Formation. A succession of sedimentary beds that were deposited under the
same general geologic conditions.
Full-Cost Pool. The full-cost pool consists of all costs associated with
property acquisition, exploration, and development activities for a company
using the full-cost method of accounting. Additionally, any internal costs that
can be directly identified with acquisition, exploration and development
activities are included. Any costs related to production, general corporate
overhead or similar activities are not included.
Gross Acres or Gross Wells. The total acres or wells, as the case may be,
in which a working interest is owned.
Horizontal Wells. Wells which are drilled at angles greater than 70
degrees from vertical.
Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.
Mbtu. One thousand btus.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet of gas equivalent.
-17-
19
Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.
Mmbtu. One million btus.
Mmcf. One million cubic feet.
Mmcfe. One million cubic feet of gas equivalent.
Net Acres or Net Wells. The sum of the fractional working interest owned
in gross acres or gross wells.
NYMEX. New York Mercantile Exchange.
Present Value or PV-10. When used with respect to oil and gas reserves,
present value or PV-10 means the estimated future gross revenue to be generated
from the production of proved reserves, net of estimated production and future
development costs, using prices and costs in effect at the determination date,
without giving effect to non-property related expenses such as general and
administrative expenses, debt service and future income tax expense or to
depreciation, depletion and amortization, discounted using an annual discount
rate of 10%.
Productive Well. A well that is producing oil or gas or that is capable of
production.
Proved Developed Reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved Undeveloped Location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved Undeveloped Reserves. Reserves that are expected to be recovered
from new wells drilled to known reservoir on undrilled acreage or from existing
wells where a relatively major expenditure is required for recompletion.
Royalty Interest. An interest in an oil and gas property entitling the
owner to a share of oil or gas production free of costs of production.
Tcf. One trillion cubic feet.
Tcfe. One trillion cubic feet of gas equivalent.
Undeveloped Acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.
Working Interest. The operating interest which gives the owner the right
to drill, produce and conduct operating activities on the property and a share
of production.
-18-
20
ITEM 2. PROPERTIES
Chesapeake focuses its natural gas exploration, development and acquisition
efforts in four areas: (i) the Mid-Continent (consisting of Oklahoma, western
Arkansas, southwestern Kansas and the Texas Panhandle), representing 71% of our
proved reserves, (ii) the Gulf Coast region consisting primarily of the Deep
Giddings Field in Texas and the Austin Chalk and Tuscaloosa Trends in Louisiana,
representing 12% of our proved reserves, (iii) the Helmet area in northeastern
British Columbia, representing 12% of our proved reserves, and (iv) the Permian
Basin region of southeastern New Mexico, representing 2% of our proved reserves.
In addition, we have oil exploration and development programs in portions of
North Dakota, Montana, and Saskatchewan, Canada that comprise the Williston
Basin.
During the year ended December 31, 2000, we participated in 360 gross
(177.3 net) wells, 175 of which we operated. A summary of our drilling
activities, capital expenditures and property sales by primary operating area is
as follows:
CAPITAL EXPENDITURES -- OIL AND GAS PROPERTIES
GROSS NET -----------------------------------------------------------------------
WELLS WELLS SALE OF
DRILLED DRILLED DRILLING LEASEHOLD SUB-TOTAL ACQUISITIONS PROPERTIES TOTAL
------- ------- -------- --------- --------- ------------ ---------- --------
($ IN THOUSANDS)
Mid-Continent................ 311 149.8 $ 92,087 $17,034 $109,121 $74,320 $(1,239) $182,202
Gulf Coast................... 12 6.4 16,982 4,490 21,472 4,590 -- 26,062
Canada....................... 14 6.9 11,905 1,664 13,569 -- -- 13,569
Permian Basin................ 13 8.8 10,230 3,398 13,628 -- -- 13,628
Other areas.................. 10 5.4 24,960 710 25,670 -- (290) 25,380
--- ----- -------- ------- -------- ------- ------- --------
Total................ 360 177.3 $156,164 $27,296 $183,460 $78,910 $(1,529) $260,841
=== ===== ======== ======= ======== ======= ======= ========
Chesapeake's proved reserves increased 12% during 2000 to an estimated
1,355 bcfe at December 31, 2000, compared to 1,206 bcfe of estimated proved
reserves at December 31, 1999 (see note 11 of notes to consolidated financial
statements in Item 8).
Chesapeake's strategy for 2001 is to continue developing our natural gas
assets through exploratory and developmental drilling and by selectively
acquiring strategic properties in our core operating areas. We have budgeted
approximately $310 million for drilling, acreage acquisition, seismic and
related capitalized internal costs, and based on our cash flow assumptions, we
will have $250 to $325 million available for acquisitions, debt repayment and
general corporate purposes. Our budget is frequently adjusted based on changes
in oil and gas prices, drilling results, drilling costs and other factors.
PRIMARY OPERATING AREAS
Mid-Continent. Chesapeake's Mid-Continent proved reserves of 967 bcfe
represented 71% of our total proved reserves as of December 31, 2000, and this
area produced 78.3 bcfe, or 58% of our 2000 production. During 2000, we invested
approximately $109.1 million to drill 311 (149.8 net) wells in the
Mid-Continent. We anticipate spending approximately 60% to 70% of our total
budget for exploration and development activities in the Mid-Continent region
during 2001. We anticipate the Mid-Continent will contribute approximately 116
bcfe of production during 2001, or 65% of expected total production.
Gulf Coast. Chesapeake's Gulf Coast proved reserves (consisting primarily
of the Deep Giddings Field in Texas and the Austin Chalk and Tuscaloosa Trends
in Louisiana) represented 158 bcfe, or 12% of our total proved reserves as of
December 31, 2000. During 2000, the Gulf Coast assets produced 35.2 bcfe, or 26%
of our total production. During 2000, we invested approximately $21.5 million to
drill 12 (6.4 net) wells in the Gulf Coast. In 2001, we anticipate the Gulf
Coast will contribute approximately 38 bcfe of production, or 21% of expected
total production. We anticipate spending approximately 15% to 20% of our total
budget for exploration and development activities in the Gulf Coast region
during 2001.
Helmet. Chesapeake's Canadian proved reserves of 159 bcfe represented 12%
of our total proved reserves at December 31, 2000. During 2000, production from
Canada was 12.1 bcfe, or 9% of our total production. During 2000, we invested
approximately $13.6 million to drill 14 (6.9 net) wells, install various
-19-
21
pipelines and compressors and to perform capital workovers in Canada. We
anticipate spending approximately 9% of our total budget for exploration and
development activities in Canada during 2001 and expect production of 15 bcfe in
Canada, or 8% of our estimated total production for 2001.
Permian Basin. Chesapeake's Permian Basin proved reserves, consisting
primarily of the Lovington area in New Mexico, represented 21 bcfe, or 2% of our
total proved reserves as of December 31, 2000. During 2000, the Permian assets
produced 6.2 bcfe, or 5% of our total production. We anticipate the Permian
Basin will contribute approximately 5 bcfe of production during 2001, or 3% of
expected total production. During 2000, we invested approximately $13.6 million
to drill 13 (8.8 net) wells in the Permian Basin. For 2001, we anticipate
spending approximately 3% to 4% of our total budget for exploration and
development activities in the Permian Basin.
OTHER OPERATING AREAS
In addition to the primary operating areas described above which consist
primarily of natural gas properties, Chesapeake maintains operations in the
Williston Basin in North Dakota, Montana, and Saskatchewan, Canada which are
focused on developing oil properties. In 2000, these areas contributed 2.4 bcfe,
or 2% of our total production. In 2001, production levels should increase to
approximately 4 bcfe as a result of allocating approximately 2% of our total
budget for exploration and development activities in these areas.
OIL AND GAS RESERVES
The tables below set forth information as of December 31, 2000 with respect
to our estimated proved reserves, and the associated estimated future net
revenue and the present value at such date. Williamson Petroleum Consultants,
Inc. evaluated 31%, Ryder Scott Company L.P. evaluated 25%, and Lee Keeling and
Associates evaluated 16% of our combined discounted future net revenues from our
estimated proved reserves at December 31, 2000. The remaining 28% was evaluated
internally by our engineers. All estimates were prepared based upon a review of
production histories and other geologic, economic, ownership and engineering
data we developed. The present value of estimated future net revenue shown is
not intended to represent the current market value of the estimated oil and gas
reserves we own.
ESTIMATED PROVED RESERVES OIL GAS TOTAL
AS OF DECEMBER 31, 2000 (MBBL) (MMCF) (MMCFE)
------------------------- ---------- ----------- -----------
Proved developed............................................ 15,445 858,463 951,133
Proved undeveloped.......................................... 8,352 353,570 403,680
---------- ---------- -----------
Total proved................................................ 23,797 1,212,033 1,354,813
========== ========== ===========
ESTIMATED FUTURE
NET REVENUE PROVED PROVED TOTAL
AS OF DECEMBER 31, 2000(A) DEVELOPED UNDEVELOPED PROVED
-------------------------- ---------- ----------- -----------
($ IN THOUSANDS)
Estimated future net revenue................................ $7,611,441 $3,091,533 $10,702,974
Present value of future net revenue......................... $4,184,271 $1,861,757 $ 6,046,028
---------------
(a) Estimated future net revenue represents estimated future gross revenue to be
generated from the production of proved reserves, net of estimated
production and future development costs, using prices and costs in effect at
December 31, 2000. The amounts shown do not give effect to non-property
related expenses, such as general and administrative expenses, debt service
and future income tax expense or to depreciation, depletion and
amortization. The prices used in the external and internal reports yield
weighted average prices of $26.41 per barrel of oil and $10.12 per mcf of
gas.
The future net revenue attributable to our estimated proved undeveloped
reserves of $3.1 billion at December 31, 2000, and the $1.9 billion present
value thereof, have been calculated assuming that we will expend approximately
$300 million to develop these reserves. The amount and timing of these
expenditures will depend on a number of factors, including actual drilling
results, product prices and the availability of capital.
-20-
22
No estimates of proved reserves comparable to those included herein have
been included in reports to any federal agency other than the Securities and
Exchange Commission.
Chesapeake's ownership interest used in calculating proved reserves and the
associated estimated future net revenue was determined after giving effect to
the assumed maximum participation by other parties to our farmout and
participation agreements. The prices used in calculating the estimated future
net revenue attributable to proved reserves do not reflect market prices for oil
and gas production sold subsequent to December 31, 2000. There can be no
assurance that all of the estimated proved reserves will be produced and sold at
the assumed prices or that existing contracts will be honored or judicially
enforced.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond Chesapeake's control.
The reserve data represents only estimates. Reserve engineering is a subjective
process of estimating underground accumulations of oil and gas that cannot be
measured in an exact way, and the accuracy of any reserve estimate is a function
of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates made by different engineers
often vary. In addition, results of drilling, testing and production subsequent
to the date of an estimate may justify revision of such estimates, and such
revisions may be material. Accordingly, reserve estimates are often different
from the actual quantities of oil and gas that are ultimately recovered.
Furthermore, the estimated future net revenue from proved reserves and the
associated present value are based upon certain assumptions, including prices,
future production levels and cost, that may not prove correct. Predictions about
prices and future production levels are subject to great uncertainty, and the
foregoing uncertainties are particularly true as to proved undeveloped reserves,
which are inherently less certain than proved developed reserves and which
comprise a significant portion of our proved reserves.
See Item 1 and note 11 of notes to consolidated financial statements
included in Item 8 for a description of drilling, production and other
information regarding our oil and gas properties.
As a result of the January 2001 Gothic acquisition, Chesapeake acquired
total proved reserves of 302 bcfe, comprised of 255 bcfe of proved developed
reserves and 47 bcfe of proved undeveloped reserves. The associated present
value of future net revenues is $1.3 billion based on weighted average prices at
December 31, 2000 of $26.57 per barrel of oil and $10.17 per mcf of gas. The
tables below set forth estimated proved reserves, the associated estimated
future net revenue and the present value as of December 31, 2000 for Chesapeake
and Gothic combined.
ESTIMATED PROVED RESERVES OIL GAS TOTAL
AS OF DECEMBER 31, 2000 (MBBL) (MMCF) (MMCFE)
------------------------- ---------- ----------- -----------
Proved developed............................................ 17,012 1,103,935 1,206,007
Proved undeveloped.......................................... 8,553 399,005 450,321
---------- ---------- -----------
Total proved................................................ 25,565 1,502,940 1,656,328
========== ========== ===========
ESTIMATED FUTURE
NET REVENUE PROVED PROVED TOTAL
AS OF DECEMBER 31, 2000(A) DEVELOPED UNDEVELOPED PROVED
-------------------------- ---------- ----------- -----------
($ IN THOUSANDS)
Estimated future net revenue................................ $9,842,538 $3,473,241 $13,315,779
Present value of future net revenue......................... $5,228,249 $2,084,282 $ 7,312,531
---------------
(a) Estimated future net revenue represents estimated future gross revenue to be
generated from the production of proved reserves, net of estimated
production and future development costs, using prices and costs in effect at
December 31, 2000. The amounts shown do not give effect to non-property
related expenses, such as general and administrative expenses, debt service
and future income tax expense or to depreciation, depletion and
amortization. The prices used in the external and internal reports yield
weighted average prices of $26.42 per barrel of oil and $10.13 per mcf of
gas.
-21-
23
ITEM 3. LEGAL PROCEEDINGS
We are subject to ordinary routine litigation incidental to our business.
In addition, the following matters were recently terminated or are pending:
Securities Litigation. On March 3, 2000, the U.S. District Court for the
Western District of Oklahoma dismissed a consolidated class action complaint
styled In re Chesapeake Energy Corporation Securities Litigation. On March 21,
2001, the court denied the plaintiffs' motion to amend and supplement their
complaint, which had been filed 31 days after the judgment was issued. The
complaint, which consolidated 12 purported class action suits filed in August
and September 1997, alleged violations of Section 10(b) and Section 20(a) of the
Securities Exchange Act of 1934 by Chesapeake and certain of our officers and
directors. The action was brought on behalf of purchasers of our common stock
and common stock options between January 25, 1996 and June 27, 1997. The
complaint alleged that the defendants made material misrepresentations and
failed to disclose material facts about our exploration and drilling activities
in Louisiana.
Bayard Drilling Technologies, Inc. On July 30, 1998, the plaintiffs in
Yuan, et al. v. Bayard, et al. filed an amended class action complaint in the
U.S. District Court for the Western District of Oklahoma alleging violations of
Section 11 and Section 12 of the Securities Act of 1933 and Section 408 of the
Oklahoma Securities Act by Chesapeake and others. The action, originally filed
in February 1998, was brought purportedly on behalf of investors who purchased
Bayard common stock in connection with Bayard's November 1997 initial public
offering. The defendants included officers and directors of Bayard who signed
the registration statement, selling shareholders (including Chesapeake) and
underwriters of the offering. Total proceeds of the offering were $254 million,
of which we received net proceeds of $90 million.
The plaintiffs alleged that Chesapeake, a major customer of Bayard's
drilling services and the owner of 30.1% of Bayard's outstanding common stock
prior to the offering, was a controlling person of Bayard. The plaintiffs
asserted that the Bayard prospectus contained material omissions and
misstatements that resulted in a decline in Bayard's share price following the
public offering. The plaintiffs sought a determination that the suit is a proper
class action and damages in an unspecified amount or rescission, together with
interest and costs of litigation, including attorneys' fees.
On August 24, 1999, the District Court dismissed the plaintiffs' claims
that Chesapeake was a "controlling person" of Bayard under Section 15 of the
Securities Act of 1933. As of March 26, 2001, the parties have agreed to settle
the action, subject to drafting of documents and court approval after a fairness
hearing. Bayard, which was acquired by Nabors Industries, Inc. in April 1999,
has reimbursed us for all our costs of defense as incurred. We will have no
liability under the terms of the settlement agreement. The case has been
administratively closed pending the closing of the settlement.
Patent Litigation. In Union Pacific Resources Company v. Chesapeake, et
al., filed in October 1996 in the U.S. District Court for the Northern District
of Texas, Fort Worth Division, Union Pacific Resources Company asserted that we
had infringed UPRC's patent covering a "geosteering" method utilized in drilling
horizontal wells. Following a trial in June 1999, the court ruled on September
21, 1999 that the patent was invalid. Because the patent was declared invalid,
the court held that we could not have infringed the patent, dismissed all of
UPRC's claims with prejudice and assessed court costs against UPRC. The court
concluded that the UPRC patent was invalid for failure to describe definitively
the patented method in the patent and for failure to provide sufficient
disclosure in the patent to enable one of ordinary skill in the art to practice
the patented method. Appeals of the judgment by both Chesapeake and UPRC were
denied on January 5, 2001 by the Federal Circuit Court of Appeals. The mandate
issued on January 26, 2001. In February 2001, Chesapeake received $89,000 from
the plaintiff for reimbursement of court costs.
West Panhandle Field Cessation Cases. One of our subsidiaries, Chesapeake
Panhandle Limited Partnership ("CP") (f/k/a MC Panhandle, Inc.), and two
subsidiaries of Kinder Morgan, Inc. have been defendants in 13 lawsuits filed
between June 1997 and January 1999 by royalty owners seeking the cancellation of
oil and gas leases in the West Panhandle Field in Texas. MC Panhandle, Inc.,
which we acquired in April 1998, has owned the leases since January 1, 1997. The
co-defendants are prior lessees.
-22-
24
The plaintiffs in these cases have claimed the leases terminated upon the
cessation of production for various periods, primarily during the 1960s. In
addition, the plaintiffs have sought to recover conversion damages, exemplary
damages, attorneys' fees and interest. The defendants have asserted that any
cessation of production was excused and have pled affirmative defenses of
limitations, waiver, temporary estoppel, laches and title by adverse possession.
As previously reported, four of the 13 cases have been tried, and there have
been appellate decisions in three of them.
On January 12, 2001, CP and the other defendants entered into a settlement
agreement with the plaintiffs in eight of ten cases tried or pending in the U.S.
District Court of Moore County, Texas, 69th Judicial District. The terms of the
settlement are confidential but we have determined that our portion of the
settlement consideration is not material to our financial condition or results
of operations. Only the claims of certain involuntary plaintiffs joined in these
settled cases remain and we do not consider these claims to be material.
Related West Panhandle cessation cases which are pending are the following:
Lois Law, et al. v. NGPL, et al., U.S. District Court of Moore County,
Texas, 69th Judicial District, No. 97-70, filed December 22, 1997, jury trial in
June 1999, verdict for CP and co-defendants. The jury found plaintiffs' claims
were barred by adverse possession, laches and revivor. On January 19, 2000, the
court granted plaintiffs' motion for judgment notwithstanding verdict and
entered judgment in favor of plaintiffs. In addition to quieting title to the
lease (including existing gas wells and all attached equipment) in plaintiffs,
the court awarded actual damages against CP in the amount of $716,400 and
exemplary damages in the amount of $25,000. The court further awarded, jointly
and severally from all defendants, $160,000 in attorneys' fees and interest and
court costs. On March 28, 2001, the Amarillo Court of Appeals reversed and
rendered the judgement in favor of CP and the other defendants, finding that the
subject lease had been revived as a matter of law, making all other issues moot.
A.C. Smith, et al. v NGPL, et al., U.S. District Court of Moore County,
Texas, 69th Judicial District, No. 98-47, first filed January 26, 1998, refiled
May 29, 1998. On June 18, 1999, the court granted plaintiffs' motion for summary
judgment in part, finding that the lease had terminated due to the cessation of
production, subject to the defendants' affirmative defenses. On February 8,
2001, the court granted plaintiffs' motion for summary judgment on defendants'
affirmative defenses but reversed its ruling that the lease had terminated as a
matter of law. No trial date has been set.
Phillip Thompson, et al. v. NGPL, et al., U.S. District Court, Northern
District of Texas, Amarillo Division, Nos. 2:98-CV-012 and 2:98-CV-106, filed
January 8, 1998 and March 18, 1998, respectively (actions consolidated), jury
trial in May 1999, verdict for CP and co-defendants. The jury found plaintiffs'
claims were barred by the payment of shut-in royalties, laches and revivor.
Plaintiffs' motion for new trial pending.
Craig Fuller, et al. v. NGPL, et al., U.S. District Court of Carson County,
Texas, 100th Judicial District, No. 8456, filed June 23, 1997, cross motions for
summary judgment pending.
Pace v. NGPL, et al., U.S. District Court, Northern District of Texas,
Amarillo Division, filed January 29, 1999. Cross motions for summary judgment
pending.
We have previously established an accrued liability we believe will be
sufficient to cover the estimated costs of litigation for each of the pending
cases and the settlement consideration under the terms of the settlement
agreement mentioned above. Because of the inconsistent verdicts reached by the
juries in the four cases tried to date and because the amount of damages sought
is not specified in all of the pending cases, the outcome of any future trials
and the amount of damages that might ultimately be awarded could differ from
management's estimates. CP and the other defendants intend to vigorously defend
against the plaintiffs' claims.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
-23-
25
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK
Our common stock trades on the New York Stock Exchange under the symbol
"CHK." The following table sets forth, for the periods indicated, the high and
low sales prices per share of our common stock as reported by the New York Stock
Exchange:
COMMON STOCK
----------------
HIGH LOW
------ ------
YEAR ENDED DECEMBER 31, 1999:
First Quarter............................................. $ 1.50 $ 0.63
Second Quarter............................................ 2.94 1.31
Third Quarter............................................. 4.13 2.75
Fourth Quarter............................................ 3.88 2.13
YEAR ENDED DECEMBER 31, 2000:
First Quarter............................................. 3.31 1.94
Second Quarter............................................ 8.00 2.75
Third Quarter............................................. 8.25 5.31
Fourth Quarter............................................ 10.50 5.44
At March 26, 2001 there were 1,175 holders of record of our common stock
and approximately 37,600 beneficial owners.
DIVIDENDS
We did not pay dividends on our common stock in 1999 or 2000. The payment
of future cash dividends, if any, will depend upon, among other things, our
financial condition, funds from operations, the level of our capital and
development expenditures, our future business prospects and any contractual
restrictions Other than payments of dividends on preferred stock, our current
policy is to retain cash for the continued growth of our business.
Two of the indentures governing our outstanding senior notes contain
restrictions on our ability to declare and pay cash dividends. Under these
indentures, we may not pay any cash dividends on our common or preferred stock
if an event of default has occurred, if we have not met the debt incurrence
tests described in the indentures, or if immediately after giving effect to the
dividend payment, we have paid total dividends and made other restricted
payments in excess of the permitted amounts.
From December 31, 1998 through March 31, 2000, we did not meet the debt
incurrence test contained in one of our indentures that requires our coverage
ratio of adjusted consolidated EBITDA to adjusted consolidated interest expense
to be at least 2.5 to 1. As a result, we were unable to pay dividends on our
existing preferred stock. Beginning June 30, 2000, we met the debt incurrence
test, and resumed paying quarterly preferred stock dividends on November 1,
2000. As of December 31, 2000, our coverage ratio, as calculated in accordance
with our most restrictive senior indenture, was 4.4 to 1.
The indenture for Gothic Production's senior secured notes significantly
limits the transfer of funds held by Gothic to Chesapeake in the form of cash
dividends, loans or advances.
-24-
26
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data of
Chesapeake for the fiscal year ended June 30, 1997, the six months ended
December 31, 1996, the six month transition period ended December 31, 1997 and
the twelve months ended December 31, 1997, 1998, 1999 and 2000. The data are
derived from our audited consolidated financial statements, although the periods
for the six months ended December 31, 1996 and the twelve months ended December
31, 1997 have not been audited. Acquisitions we made during the first and second
quarters of 1998 materially affect the comparability of the selected financial
data for 1997 and 1998. Each of the acquisitions was accounted for using the
purchase method. The table should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
our consolidated financial statements, including the notes, appearing in Items 7
and 8 of this report.
-25-
27
YEAR
ENDED SIX MONTHS ENDED
JUNE 30, DECEMBER 31, YEARS ENDED DECEMBER 31,
--------- ----------------------- -------------------------------------------------
1997 1996 1997 1997 1998 1999 2000
--------- ----------- --------- ----------- ---------- --------- ----------
(UNAUDITED) (UNAUDITED)
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales................... $ 192,920 $ 90,167 $ 95,657 $ 198,410 $ 256,887 $ 280,445 $ 470,170
Oil and gas marketing sales......... 76,172 30,019 58,241 104,394 121,059 74,501 157,782
--------- --------- --------- --------- ---------- --------- ----------
Total revenues.................. 269,092 120,186 153,898 302,804 377,946 354,946 627,952
--------- --------- --------- --------- ---------- --------- ----------
Operating costs:
Production expenses................. 11,445 4,268 7,560 14,737 51,202 46,298 50,085
Production taxes.................... 3,662 1,606 2,534 4,590 8,295 13,264 24,840
General and administrative.......... 8,802 3,739 5,847 10,910 19,918 13,477 13,177
Oil and gas marketing expenses...... 75,140 29,548 58,227 103,819 119,008 71,533 152,309
Oil and gas depreciation, depletion
and amortization.................. 103,264 36,243 60,408 127,429 146,644 95,044 101,291
Depreciation and amortization of
other assets...................... 3,782 1,836 2,414 4,360 8,076 7,810 7,481
Impairment of oil and gas
properties........................ 236,000 -- 110,000 346,000 826,000 -- --
Impairment of other assets.......... -- -- -- -- 55,000 -- --
--------- --------- --------- --------- ---------- --------- ----------
Total operating costs........... 442,095 77,240 246,990 611,845 1,234,143 247,426 349,183
--------- --------- --------- --------- ---------- --------- ----------
Income (loss) from operations......... (173,003) 42,946 (93,092) (309,041) (856,197) 107,520 278,769
--------- --------- --------- --------- ---------- --------- ----------
Other income (expense):
Interest and other income........... 11,223 2,516 78,966 87,673 3,926 8,562 3,649
Interest expense.................... (18,550) (6,216) (17,448) (29,782) (68,249) (81,052) (86,256)
--------- --------- --------- --------- ---------- --------- ----------
Total other income (expense).... (7,327) (3,700) 61,518 57,891 (64,323) (72,490) (82,607)
--------- --------- --------- --------- ---------- --------- ----------
Income (loss) before income taxes and
extraordinary item.................. (180,330) 39,246 (31,574) (251,150) (920,520) 35,030 196,162
Provision (benefit) for income
taxes............................... (3,573) 14,325 -- (17,898) -- 1,764 (259,408)
--------- --------- --------- --------- ---------- --------- ----------
Income (loss) before extraordinary
item................................ (176,757) 24,921 (31,574) (233,252) (920,520) 33,266 455,570
Extraordinary item:
Loss on early extinguishment of
debt, net of applicable income
taxes............................. (6,620) (6,443) -- (177) (13,334) -- --
--------- --------- --------- --------- ---------- --------- ----------
Net income (loss)..................... (183,377) 18,478 (31,574) (233,429) (933,854) 33,266 455,570
Preferred stock dividends............. -- -- -- -- (12,077) (16,711) (8,484)
Gain on redemption of preferred
stock............................... -- -- -- -- -- -- 6,574
--------- --------- --------- --------- ---------- --------- ----------
Net income (loss) available to common
shareholders........................ $(183,377) $ 18,478 $ (31,574) $(233,429) $ (945,931) $ 16,555 $ 453,660
========= ========= ========= ========= ========== ========= ==========
Earnings (loss) per common
share -- basic:
Income (loss) before extraordinary
item.............................. $ (2.69) $ 0.40 $ (0.45) $ (3.30) $ (9.83) $ 0.17 $ 3.52
Extraordinary item.................. (0.10) (0.10) -- -- (0.14) -- --
--------- --------- --------- --------- ---------- --------- ----------
Net income (loss)................... $ (2.79) $ 0.30 $ (0.45) $ (3.30) $ (9.97) $ 0.17 $ 3.52
========= ========= ========= ========= ========== ========= ==========
Earnings (loss) per common
share -- assuming dilution:
Income (loss) before extraordinary
item.............................. $ (2.69) $ 0.38 $ (0.45) $ (3.30) $ (9.83) $ 0.16 $ 3.01
Extraordinary item.................. (0.10) (0.10) -- -- (0.14) -- --
--------- --------- --------- --------- ---------- --------- ----------
Net income (loss)................... $ (2.79) $ 0.28 $ (0.45) $ (3.30) $ (9.97) $ 0.16 $ 3.01
========= ========= ========= ========= ========== ========= ==========
Cash dividends declared per common
share............................... $ 0.02 $ -- $ 0.04 $ 0.06 $ 0.04 $ -- $ --
CASH FLOW DATA:
Cash provided by operating activities
before changes in working capital... $ 161,140 $ 76,816 $ 67,872 $ 152,196 $ 117,500 $ 138,727 $ 305,804
Cash provided by operating
activities.......................... 84,089 41,901 139,157 181,345 94,639 145,022 314,640
Cash used in investing activities..... 523,854 184,149 136,504 476,209 548,050 159,773 330,036
Cash provided by (used in) financing
activities.......................... 512,144 231,349 (2,810) 277,985 363,797 18,967 (22,933)
Effect of exchange rate changes on
cash................................ -- -- -- -- (4,726) 4,922 (329)
BALANCE SHEET DATA (at end of period):
Total assets.......................... $ 949,068 $ 860,597 $ 952,784 $ 952,784 $ 812,615 $ 850,533 $1,440,426
Long-term debt, net of current
maturities.......................... 508,950 220,149 508,992 508,992 919,076 964,097 944,845
Stockholders' equity (deficit)........ 286,889 484,062 280,206 280,206 (248,568) (217,544) 313,232
-26-
28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
OVERVIEW
The following table sets forth certain information regarding the production
volumes, sales, average sales prices received and expenses associated with our
sales of natural gas and oil for the periods indicated:
YEARS ENDED DECEMBER 31,
--------------------------------
1998 1999 2000
-------- -------- --------
NET PRODUCTION:
Oil (mbbl)................................................ 5,976 4,147 3,068
Gas (mmcf)................................................ 94,421 108,610 115,771
Gas equivalent (mmcfe).................................... 130,277 133,492 134,179
OIL AND GAS SALES ($ IN THOUSANDS):
Oil....................................................... $ 75,877 $ 66,413 $ 80,953
Gas....................................................... 181,010 214,032 389,217
-------- -------- --------
Total oil and gas sales............................. $256,887 $280,445 $470,170
======== ======== ========
AVERAGE SALES PRICE:
Oil ($ per bbl)........................................... $ 12.70 $ 16.01 $ 26.39
Gas ($ per mcf)........................................... $ 1.92 $ 1.97 $ 3.36
Gas equivalent ($ per mcfe)............................... $ 1.97 $ 2.10 $ 3.50
EXPENSES ($ PER MCFE):
Production expenses and taxes............................. $ .45 $ .45 $ .56
General and administrative................................ $ .15 $ .10 $ .10
Depreciation, depletion and amortization.................. $ 1.13 $ .71 $ .75
NET WELLS DRILLED:
Horizontal wells.......................................... 20 11 10
Vertical wells............................................ 116 109 167
NET WELLS AT END OF PERIOD.................................. 2,405 2,242 2,697
RESULTS OF OPERATIONS
Years Ended December 31, 1998, 1999 and 2000.
General. For the year ended December 31, 2000, Chesapeake had net income
of $456 million, or $3.01 per diluted common share, on total revenues of $628
million. This compares to net income of $33 million, or $0.16 per diluted common
share, on total revenues of $355 million during the year ended December 31,
1999, and a net loss of $934 million, or a loss of $9.97 per diluted common
share, on total revenues of $378 million during the year ended December 31,
1998. Net income in 2000 was significantly enhanced by the reversal of a
deferred tax valuation allowance in the amount of $265 million during the fourth
quarter. The reversal related to Chesapeake's ability to generate sufficient
future taxable income to utilize net operating losses prior to their expiration.
The loss in 1998 was caused primarily by an $826 million oil and gas property
writedown recorded under the full-cost method of accounting and a $55 million
writedown of other assets. See "Impairment of Oil and Gas Properties" and
"Impairment of Other Assets."
Oil and Gas Sales. During 2000, oil and gas sales increased to $470.2
million versus $280.4 million in 1999 and $256.9 million in 1998. In 2000,
Chesapeake produced 134.2 bcfe at a weighted average price of $3.50 per mcfe,
compared to 133.5 bcfe produced in 1999 at a weighted average price of $2.10 per
mcfe, and 130.3 bcfe produced in 1998 at a weighted average price of $1.97 per
mcfe.
-27-
29
The following table shows our production by region for 1998, 1999 and 2000:
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
1998 1999 2000
------------------ ------------------ ------------------
MMCFE PERCENT MMCFE PERCENT MMCFE PERCENT
------- ------- ------- ------- ------- -------
Mid-Continent................................. 61,930 48% 68,170 51% 78,342 58%
Gulf Coast.................................... 52,793 40 43,909 33 35,154 26
Canada........................................ 7,746 6 11,737 9 12,076 9
Permian Basin................................. 3,939 3 5,722 4 6,166 5
Other areas................................... 3,869 3 3,954 3 2,441 2
------- --- ------- --- ------- ---
Total production...................... 130,277 100% 133,492 100% 134,179 100%
======= === ======= === ======= ===
Natural gas production represented approximately 86% of our total
production volume on an equivalent basis in 2000, compared to 81% in 1999 and
72% in 1998. The decrease in oil production from 1998 through 2000 is the result
of divestitures that occurred primarily in 1999 and our increasing focus on
natural gas.
For 2000, we realized an average price per barrel of oil of $26.39,
compared to $16.01 in 1999 and $12.70 in 1998. Natural gas price realizations
fluctuated from an average of $1.92 per mcf in 1998 and $1.97 in 1999 to $3.36
per mcf in 2000. In 2000, our hedging activities resulted in a decrease in oil
and gas revenues of $30.6 million or $0.23 per mcfe, a decrease of $1.7 million
or $0.01 per mcfe in 1999, and an increase of $11.3 million or $0.09 per mcfe in
1998.
Oil and Gas Marketing Sales. Chesapeake realized $157.8 million in oil and
gas marketing sales for third parties in 2000, with corresponding oil and gas
marketing expenses of $152.3 million, for a net margin of $5.5 million. This
compares to sales of $74.5 million and $121.1 million, expenses of $71.5 million
and $119.0 million, and a margin of $3.0 million and $2.1 million in 1999 and
1998, respectively. The increase in marketing sales and cost of sales in 2000 as
compared to 1999 and 1998 was due primarily to higher oil and gas prices in 2000
and the fact that we began marketing oil in June 1999.
Production Expenses and Taxes. Production expenses and taxes, which
include lifting costs, production taxes and ad valorem taxes, were $74.9 million
in 2000, compared to $59.6 million and $59.5 million in 1999 and 1998,
respectively. On a unit of production basis, production expenses and taxes were
$0.56 per mcfe in 2000 and $0.45 per mcfe in 1999 and 1998. The increase in
costs on a per unit basis in 2000 is due primarily to higher production taxes
resulting from higher oil and gas prices. In general, production taxes are
calculated using value-based formulas that produce higher per unit costs when
oil and gas prices are higher. We expect that lease operating expenses per mcfe
will generally remain at current levels throughout 2001, although production
taxes will fluctuate with changes in oil and gas prices.
General and Administrative Expense. General and administrative expenses,
which are net of internal payroll and non-payroll costs capitalized in our oil
and gas properties (see note 11 of notes to consolidated financial statements),
were $13.2 million in 2000, $13.5 million in 1999 and $19.9 million in 1998. The
decrease in 1999 compared to 1998 was due primarily to various actions taken to
lower corporate overhead, including staff reductions and office closings which
occurred in late 1998 and early 1999. We capitalized $7.0 million, $2.7 million
and $5.3 million of internal costs in 2000, 1999 and 1998, respectively,
directly related to our oil and gas exploration and development efforts. We
anticipate that general and administrative expenses for 2001 per mcfe will
remain at approximately the same level as 2000.
Oil and Gas Depreciation, Depletion and Amortization. Depreciation,
depletion and amortization of oil and gas properties was $101.3 million, $95.0
million and $146.6 million during 2000, 1999 and 1998, respectively. The average
DD&A rate per mcfe, which is a function of capitalized costs, future development
costs, and the related underlying reserves in the periods presented, was $0.75
($0.76 in U.S. and $0.71 in Canada), $0.71 ($0.73 in U.S. and $0.52 in Canada),
and $1.13 ($1.17 in U.S. and $0.43 in Canada) in 2000, 1999 and 1998,
respectively. We expect the 2001 DD&A rate to be between $1.00 and $1.05 per
mcfe.
Depreciation and Amortization of Other Assets. Depreciation and
amortization of other assets was $7.5 million in 2000, compared to $7.8 million
in 1999 and $8.1 million in 1998.
-28-
30
Impairment of Oil and Gas Properties. We use the full-cost method to
account for our investment in oil and gas properties. Under this method, all
costs of acquisition, exploration and development of oil and gas reserves
(including such costs as leasehold acquisition costs, geological and geophysical
expenditures, certain capitalized internal costs, dry hole costs and tangible
and intangible development costs) are capitalized as incurred. These oil and gas
property costs, along with the estimated future capital expenditures to develop
proved undeveloped reserves, are depleted and charged to operations using the
unit-of-production method based on the ratio of current production to proved oil
and gas reserves as estimated by our independent engineering consultants and our
internal reservoir engineers. Costs directly associated with the acquisition and
evaluation of unproved properties are excluded from the amortization computation
until it is determined whether or not proved reserves can be assigned to the
property or whether impairment has occurred. The excess of capitalized costs of
oil and gas properties, net of accumulated depreciation, depletion and
amortization and related deferred income taxes, over the discounted future net
revenues of proved oil and gas properties is charged to operations.
We incurred an impairment of oil and gas properties charge of $826 million
in 1998. No such charge was incurred in 2000 or 1999. The 1998 writedown was
caused primarily by the significant decreases in oil and gas prices throughout
1998. Oil and gas prices used to value our proved reserves decreased from $17.62
per bbl of oil and $2.29 per mcf of gas at December 31, 1997, to $10.48 per bbl
of oil and $1.68 per mcf of gas at December 31, 1998. Higher drilling and
completion costs and the evaluation of certain leasehold, seismic and other
exploration-related costs that were previously unevaluated were additional
factors which contributed to the writedown in 1998.
Impairment of Other Assets. Chesapeake incurred a $55 million other asset
impairment charge during 1998. Of this amount, $30 million related to our
investment in preferred stock of Gothic Energy Corporation and the remainder was
related to certain of our gas processing and transportation assets located in
Louisiana. No such charge was recorded in 2000 or 1999.
Interest and Other Income. Interest and other income was $3.6 million,
$8.6 million and $3.9 million in 2000, 1999 and 1998, respectively. The increase
in 1999 was due primarily to gains on sales of various non-oil and gas assets
during 1999 which did not occur in 2000 and 1998.
Interest Expense. Interest expense increased to $86.3 million in 2000,
compared to $81.1 million in 1999 and $68.2 million in 1998. The increase in
2000 is due to additional borrowings under our bank credit facility. The
increase in 1999 compared to 1998 is due primarily to a full year of interest on
our $500 million senior notes issued in April 1998. In addition to the interest
expense reported, we capitalized $2.4 million of interest during 2000, compared
to $3.5 million capitalized in 1999, and $6.5 million capitalized in 1998. We
anticipate that capitalized interest for 2001 will be between $2.0 million and
$3.0 million.
Provision (Benefit) for Income Taxes. Chesapeake recorded an income tax
benefit of $259.4 million in 2000 compared to income tax expense of $1.8 million
in 1999 and none in 1998. The income tax benefit was comprised of $5.6 million
of income tax expense related to our Canadian operations and the reversal of a
$265 million deferred tax valuation allowance which was established in prior
years. The valuation allowance had been established due to uncertainty
surrounding our ability to utilize extensive regular tax NOLs prior to their
expiration. Based upon our recent results of operations, the improved outlook
for the natural gas industry and our projected results of future operations, we
believe it is more likely than not that Chesapeake will be able to generate
sufficient future taxable income to utilize our existing NOLs prior to their
expiration. Consequently, management has determined that a valuation allowance
is no longer required. The income tax expense recorded in 1999 is related
entirely to our Canadian operations.
LIQUIDITY AND CAPITAL RESOURCES
Years Ended December 31, 2000, 1999 and 1998
Cash Flows from Operating Activities. Cash provided by operating
activities (inclusive of changes in working capital) was $314.6 million in 2000,
compared to $145.0 million in 1999 and $94.6 million in 1998.
-29-
31
The $169.6 million increase from 1999 to 2000 and the $50.4 million increase
from 1998 to 1999 were due primarily to increased oil and gas revenues resulting
from higher prices.
Cash Flows from Investing Activities. Cash used in investing activities
increased to $330.0 million in 2000, compared to $159.8 million in 1999 and
$548.1 million in 1998. During 2000, Chesapeake invested $188.8 million for
exploration and development drilling, $78.9 million for the acquisition of oil
and gas properties, and received $1.5 million related to divestitures of oil and
gas properties. During 2000, we invested $36.7 million in the purchase of Gothic
notes and acquisition related costs. Also in 2000, we invested $7.9 million in
Advanced Drilling Technologies, L.L.C., a 50% owned drilling company joint
venture. Additionally in 2000, we invested $4.0 million to construct a new
building at our Oklahoma City complex. We anticipate the availability of this
additional office space will reduce our general and administrative costs in
future years. In 1999, we invested $153.3 million for exploration and
development drilling, $49.9 million for the acquisition of oil and gas
properties, and received $45.6 million related to divestitures of oil and gas
properties. During 1998, $279.9 million was used to acquire certain oil and gas
properties and companies with oil and gas reserves. During 1998, we invested
$259.7 million for exploratory and developmental drilling. Also during 1998, we
sold our 19.9% stake in Pan East Petroleum Corp. to Poco Petroleums, Ltd. for
approximately $21.2 million.
Cash Flows from Financing Activities. Cash used in financing activities
was $22.9 million in 2000, compared to cash provided of $19.0 million in 1999
and $363.8 million in 1998. During 2000, we made additional borrowings under our
bank credit facility of $244.0 million and made repayments under this facility
of $262.5 million. Also in 2000, we paid $8.3 million in connection with an
exchange of our preferred stock for our common stock and paid cash dividends of
$4.6 million on our preferred stock. In connection with our purchase of Gothic
notes, we received $7.1 million cash from the sellers of Gothic notes pursuant
to make-whole provisions included in the purchase agreements. These provisions
required payments to be made by the sellers to us or additional payments to be
made by us to the sellers, depending upon changes in market value of our common
stock during a specified period pending registration of our common stock issued
to the sellers of Gothic notes. During 1999, we made additional borrowings under
our bank credit facility of $116.5 million and made repayments under this
facility of $98.0 million. During 1998, we retired $85 million of debt assumed
at the completion of the DLB Oil & Gas, Inc. acquisition, $120 million of debt
assumed at the completion of the Hugoton Energy Corporation acquisition, $90
million of senior notes, and $170 million of borrowings made under our bank
credit facility. Also during 1998, we issued $500 million in senior notes and
$230 million in preferred stock. We also repurchased common stock and preferred
stock for $30 million.
Financial Flexibility and Liquidity
Chesapeake had working capital of $4.2 million at December 31, 2000
including a restricted cash balance of $3.5 million. We have a $100 million
revolving bank credit facility which matures in July 2002, with a committed
borrowing base of $100 million. As of December 31, 2000, we had borrowed $25
million under this facility and had $31.5 million of the facility securing
various letters of credit. Borrowings under the facility are secured by certain
producing oil and gas properties and bear interest at a variable rate, which was
9.3% per annum as of December 31, 2000. Interest is payable quarterly calculated
at .50% to 1.25%, depending on utilization, plus the higher of (a) the Union
Bank of California reference rate or (b) the federal funds rate plus .50% per
year. We may elect to convert a portion of our borrowings to interest calculated
under a London Interbank Offered Rate (LIBOR) plus 2.00% to 2.75%, depending on
utilization. We are required to pay a commitment fee on the unused portion of
the borrowing base equal to 0.375% per annum due quarterly.
During 2000, we obtained a standby commitment for a $275 million credit
facility, consisting of a $175 million term loan and a $100 million revolving
credit facility which, if needed, would have replaced our existing revolving
credit facility. The term loan was available to provide funds to repurchase any
of Gothic Production Corporation's 11.125% senior secured notes tendered
following the closing of the Gothic acquisition pursuant to a change-of-control
offer to purchase. In February 2001, we purchased $1.0 million of notes tendered
for 101% of such amount. We did not use the standby credit facility and the
commitment terminated on February 23, 2001. Chesapeake incurred $3.2 million of
costs for the standby facility.
-30-
32
At December 31, 2000, our senior notes represented $919 million of our $945
million of long-term debt. Debt ratings for the senior notes are B2 by Moody's
Investors Service and B+ by Standard & Poor's Ratings Services as of January
2001. There are no scheduled principal payments required on any of the senior
notes until 2004, 2005, and thereafter, when $150 million, $500 million and $269
million, respectively, are due.
As of March 28, 2001, Chesapeake has purchased and subsequently retired
$7.3 million of the $150 million 8.5% senior notes for total consideration of
$7.4 million, including accrued interest of $0.2 million.
Chesapeake's senior note indentures restrict the ability of Chesapeake and
our restricted subsidiaries to incur additional indebtedness. As of December 31,
2000, we estimate that secured commercial bank indebtedness of $681 million
could have been incurred within these restrictions. The Chesapeake indenture
restrictions do not apply to our unrestricted subsidiaries, Chesapeake Energy
Marketing, Inc. and Gothic Energy Corporation and its subsidiary.
Chesapeake's senior note indentures also limit our ability to make
restricted payments (as defined), including the payment of cash dividends,
unless certain tests are met. From December 31, 1998 through March 31, 2000, we
were unable to meet the requirements to incur additional unsecured indebtedness,
and consequently were restricted from paying cash dividends on our 7% cumulative
convertible preferred stock. On September 22, 2000, we declared a regular
quarterly dividend and a special dividend equal to all unpaid dividends on our
preferred stock both payable November 1, 2000 to shareholders of record on
October 16, 2000. A total combined dividend of $7.444 per outstanding preferred
share was paid November 1, 2000, eliminating the accumulated unpaid dividends.
During 2000, Chesapeake engaged in unsolicited transactions in which a
total of 43.4 million shares of Chesapeake common stock, plus a cash payment of
$8.3 million, were exchanged for 3,972,363 shares of Chesapeake preferred stock.
These transactions reduced the number of preferred shares outstanding from 4.6
million to 0.6 million, and reduced the liquidation value of shares of
outstanding preferred stock from $229.8 million to $31.2 million. In addition,
these transactions eliminated $22.9 million of dividends in arrears during 2000.
A gain on redemption of all preferred shares exchanged during 2000 of $6.6
million is reflected in net income available to common shareholders in
determining basic earnings per share for the year ended December 31, 2000.
Chesapeake has called for redemption all outstanding shares of preferred stock
for $52.45 per share, plus accumulated and unpaid dividends, on May 1, 2001
pursuant to the optional redemption provisions of the certificate of designation
for the preferred stock. We intend to use our common stock (other than for the
redemption premium) to redeem any shares of the outstanding preferred stock that
are not converted into common stock prior to the redemption date.
During 2000, Chesapeake Energy Marketing, Inc. purchased 99.8% of Gothic
Energy Corporation's $104 million 14.125% Series B senior secured discount notes
for total consideration of $80.8 million, comprised of $17.2 million in cash and
$63.6 million of Chesapeake common stock (8,875,775 shares valued at $7.16 per
share), as adjusted for make-whole provisions described above. Through the
make-whole provisions, Chesapeake Energy Marketing, Inc. received $6.1 million
in cash and $7.2 million of Chesapeake common stock (982,562 shares). Gothic
redeemed all remaining outstanding senior secured discount notes on March 12,
2001 for total cash consideration of $243,000 pursuant to the optional
make-whole redemption provisions of the indenture.
In 2000, Chesapeake purchased $31.6 million of the 11.125% senior secured
notes issued by Gothic Production Corporation for total consideration of $34.8
million, comprised of $11.5 million in cash and $23.3 million of Chesapeake
common stock (3,694,939 shares valued at $6.30 per share), as adjusted for make-
whole provisions described above. Through the make-whole provisions, Chesapeake
received $1.0 million in cash. In February 2001, Chesapeake purchased $1.0
million principal amount of Gothic senior secured notes tendered at 101%. The
notes purchased in 2000 and those tendered pursuant to the change-of-control
offer to purchase, representing a total of $32.7 million principal amount, were
retired and cancelled in February 2001.
We completed the acquisition of Gothic Energy Corporation on January 16,
2001 by merging a wholly-owned subsidiary into Gothic. We issued a total of 4.0
million common shares in the merger. Gothic shareholders (other than Chesapeake)
received 0.1908 of a share of Chesapeake common stock for each share
-31-
33
of Gothic common stock. In addition, outstanding warrants and options to
purchase Gothic common stock were converted to the right to purchase Chesapeake
common stock based on the merger exchange ratio. As of March 15, 2001, 1.1
million shares of Chesapeake common stock may be purchased upon the exercise of
such warrants and options at an average price of $12.28 per share.
Gothic Production Corporation's senior secured notes, of which $202.3
million principal amount remains presently outstanding, have been guaranteed by
its parent Gothic Energy Corporation. Chesapeake has not assumed any payment
obligations with respect to the notes. The notes are secured by Gothic
Production's oil and gas properties and mature on May 1, 2005. The notes may be
redeemed beginning May 1, 2002 at an initial redemption price of 105.563%. At
any time prior to May 1, 2002, Gothic may, at its option, redeem all or any
portion of the Senior Secured Notes at the Make-Whole Price (as defined in the
Senior Note Indenture) plus accrued or unpaid interest to the date of
redemption. The indenture for the notes contains covenants imposing restrictions
on the incurrence of additional indebtedness, the payment of dividends,
distributions and other restricted payments (including such payments to
Chesapeake), the sale of assets, the creation of liens and transactions with
affiliates, among other covenants. Gothic Production will continue to operate in
accordance with the terms of the senior secured note indenture. Gothic will
produce its existing oil and gas properties but will not add to its reserves
through drilling or acquisitions. As a result of the acquisition, Chesapeake
will develop all future wells. Chesapeake has assumed operations of all
properties formerly operated by Gothic Production.
We believe we have adequate resources, including budgeted cash flow from
operations, to fund our capital expenditure budget for exploration and
development activities during 2001, which are currently estimated to be
approximately $310 million. However, lower oil and gas prices, unfavorable
drilling results or other factors could cause us to reduce our drilling program,
which is largely discretionary. Based on our current cash flow assumptions, we
expect to have an additional $250 to $325 million available for acquisitions,
debt repayment and general corporate purposes in 2001. Additionally, we have
approximately $60 million available under our bank credit facility as of March
29, 2001.
We will have additional cash needs to fund our future operations. If we do
not have cash available, or borrowings under our credit facilities have been
utilized when our cash need arises, we would be forced to seek additional debt
or equity financing or to forego the opportunity. In the event that we determine
to seek additional debt or equity financing, there can be no assurance that any
such financing will be available, on commercially reasonable terms or at all, or
permitted by the terms of our existing indebtedness.
On March 29, 2001, we announced a proposed private offering to sell $800
million of senior notes due 2011 in order to lower the interest rate and extend
the maturity of approximately 74% of our senior notes. If the offering is
successfully completed, the proceeds from the proposed offering, together with
available cash and bank borrowings, would be used to redeem Chesapeake's
existing $120 million principal amount of 9.125% senior notes due 2006, $500
million principal amount of 9.625% senior notes due 2005 and $202.5 million
principal amount of 11.125% senior secured notes due 2005 of Gothic Production
Corporation, a Chesapeake subsidiary. Redemption of these notes will include
payment of aggregate make-whole and redemption premiums estimated at
approximately $74 million. The notes to be offered by Chesapeake would not be
initially registered under the Securities Act of 1933, as amended, and will not
be offered or sold in the United States absent registration or an applicable
exemption from registration requirements.
RECENTLY ISSUED ACCOUNTING STANDARDS
On June 15, 1998, the Financial Accounting Standards Board issued SFAS No.
133, Accounting for Derivative Instruments and Hedging Activities. SFAS 133
establishes a new model for accounting for derivatives and hedging activities
and supersedes and amends a number of existing standards. SFAS 133 (as amended
by SFAS 137 and SFAS 138) is effective for all fiscal quarters of fiscal years
beginning after June 15, 2000.
SFAS 133 standardizes the accounting for derivative instruments by
requiring that all derivatives be recognized as assets and liabilities and
measured at fair value. The accounting for changes in the fair value of
derivatives (gains and losses) depends on (i) whether the derivative is
designated and qualifies as a hedge, and
-32-
34
(ii) the type of hedging relationship that exists. Changes in the fair value of
derivatives that are not designated as hedges or that do not meet the hedge
accounting criteria in SFAS 133 are required to be reported in earnings. In
addition, all hedging relationships must be designated, reassessed and
documented pursuant to the provisions of SFAS 133. We will fully adopt SFAS 133
on January 1, 2001, the effective date as amended by SFAS 138. SFAS 133 is
expected to increase volatility of stockholders' equity, reported earnings
(losses) and other comprehensive income. If we had adopted SFAS 133 on December
31, 2000, Chesapeake would have recorded an additional $9.3 million in current
assets and $98.6 million in current liabilities related to our existing oil and
gas hedges based on the forward price curve in effect at December 31, 2000. The
net liability of $89.3 million related to qualifying hedge instruments would
have been charged to other comprehensive income which appears in the equity
section of the balance sheet. After adoption, Chesapeake will be required to
recognize any hedge ineffectiveness in the income statement each period.
FORWARD-LOOKING STATEMENTS
This report includes "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 statements regarding oil and gas
reserve estimates, planned capital expenditures, the drilling of oil and gas
wells and future acquisitions, expected oil and gas production, cash flow and
anticipated liquidity, business strategy and other plans and objectives for
future operations, expected future expenses and utilization of net operating
loss carryforwards.
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. Factors that could cause actual
results to differ materially from expected results are described under "Risk
Factors" in Item 1 and include:
- the volatility of oil and gas prices,
- our substantial indebtedness,
- our commodity price risk management activities,
- our ability to replace reserves,
- the availability of capital,
- uncertainties inherent in estimating quantities of oil and gas
reserves,
- projecting future rates of production and the timing of development
expenditures,
- uncertainties in evaluating oil and gas reserves of acquired
properties and associated potential liabilities,
- drilling and operating risks,
- our ability to generate future taxable income sufficient to utilize
our NOLs before expiration,
- future ownership changes which could result in additional limitations
to our NOLs,
- adverse effects of governmental and environmental regulation,
- losses possible from pending or future litigation,
- the strength and financial resources of our competitors,
- the loss of officers or key employees, and
- conflicts of interest our chief executive officer and chief operating
officer may have as a result of their participation in company wells
and their substantial stock ownership.
We caution you not to place undue reliance on these forward-looking
statements, which speak only as of the date of this report, and we undertake no
obligation to update this information. We urge you to carefully review and
consider the disclosures made in this and our other reports filed with the SEC
that attempt to advise interested parties of the risks and factors that may
affect our business.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK
Chesapeake's results of operations are highly dependent upon the prices
received for oil and natural gas production.
-33-
35
HEDGING ACTIVITIES
Periodically Chesapeake utilizes hedging strategies to hedge the price of a
portion of its future oil and gas production. These strategies include:
- swap arrangements that establish an index-related price above which we
pay the counterparty and below which we are paid by the counterparty
(counterparty payments in some contracts are subject to a cap),
- the purchase of index-related puts that provide for a "floor" price
below which the counterparty pays us the amount by which the price of
the commodity is below the contracted floor,
- the sale of index-related calls that provide for a "ceiling" price
above which we pay the counterparty the amount by which the price of
the commodity is above the contracted ceiling,
- basis protection swaps, which are arrangements that guarantee the
price differential of oil or gas from a specified delivery point or
points, and
- collar arrangements that establish an index-related price below which
the counterparty pays us and a separate index-related price above
which we pay the counterparty.
Commodity markets are volatile, and as a result, our hedging activity is
dynamic. As market conditions warrant, we may elect to settle a hedging
transaction prior to its scheduled maturity date and, as a result, realize a
gain or loss on the transaction.
Results from commodity hedging transactions are reflected in oil and gas
sales to the extent related to our oil and gas production. We only enter into
commodity hedging transactions related to our oil and gas production volumes or
physical purchase or sale commitments of our marketing subsidiary. Gains or
losses on crude oil and natural gas hedging transactions are recognized as price
adjustments in the months of related production.
As of December 31, 2000, we had the following open natural gas swap
arrangements designed to hedge a portion of our domestic gas production for
periods after December 2000:
NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
------ --------- ------------
January 2001................................................ 4,960,000 $6.03
February 2001............................................... 5,320,000 6.12
March 2001.................................................. 4,650,000 5.11
April 2001.................................................. 5,100,000 4.79
May 2001.................................................... 5,270,000 4.63
June 2001................................................... 3,900,000 4.61
July 2001................................................... 4,030,000 4.59
August 2001................................................. 4,030,000 4.58
September 2001.............................................. 3,900,000 4.57
October 2001................................................ 620,000 4.80
If the swap arrangements listed above had been settled on December 31,
2000, we would have incurred a loss of $80.1 million. Subsequent to December 31,
2000, we settled the natural gas swaps for January, February and March 2001. A
loss of $18.6 million and $4.4 million and a gain of $0.1 million will be
recognized as price adjustments in January, February and March, respectively. If
we had settled the remaining swaps (April through October) using March 21, 2001
prices, we would have incurred a loss of $13.5 million.
On June 2, 2000, we entered into a natural gas basis protection swap
transaction for 13,500,000 mmbtu for the period of January 2001 through March
2001. This transaction requires that the counterparty pay us if the NYMEX price
exceeds the Houston Ship Channel Beaumont/Texas Index by more than $0.0675 for
each of the related months of production. If the NYMEX price less $0.0675 does
not exceed the Houston Ship Channel Beaumont/Texas Index for each month, we will
pay the counterparty. Gains or losses on basis swap transactions are recognized
as price adjustments in the month of related production. Subsequent to December
31, 2000, we settled the natural gas basis protection swaps for January,
February and March 2001.
-34-
36
A gain of $0.3 million, a loss of $0.1 million and a loss of $0.5 million will
be recognized as price adjustments in January, February and March, respectively.
As of December 31, 2000, we had open natural gas collar transactions
designed to hedge 60,000 mmbtu per day throughout 2001 at an average
NYMEX-defined high strike price (cap) of $6.08 per mmbtu and an average
NYMEX-defined low strike price (floor) of $4.00 per mmbtu. If the collar
transactions had been settled on December 31, 2000, we would have incurred a
loss of $18.5 million. Subsequent to December 31, 2000, we settled the natural
gas collar transactions for January, February and March 2001. A loss of $6.9
million and $1.4 million will be recognized as price adjustments in January and
February, respectively. The March 2001 contract was settled for no gain or loss.
As of December 31, 2000, we had the following open crude oil swap
arrangements designed to hedge a portion of our domestic crude oil production
for periods after December 2000:
NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (BBLS) (PER BBL)
------ ------- ------------
January 2001................................................ 165,000 $29.97
February 2001............................................... 150,000 29.92
March 2001.................................................. 165,000 29.84
April 2001.................................................. 160,000 29.80
May 2001.................................................... 165,000 29.75
June 2001................................................... 160,000 29.71
July 2001................................................... 165,000 29.68
August 2001................................................. 165,000 29.65
September 2001.............................................. 160,000 29.62
October 2001................................................ 165,000 29.59
November 2001............................................... 160,000 29.56
December 2001............................................... 165,000 29.54
If the swap arrangements listed above had been settled on December 31,
2000, we would have realized a gain of $9.3 million. Subsequent to December 31,
2000, we settled the crude oil swap for January 2001 for a gain of $0.1 million
and February 2001 for a gain of $41,350, which will be recognized as a price
adjustment in January and February 2001.
Subsequent to December 31, 2000, we entered into the following natural gas
swap arrangements designed to hedge a portion of our domestic gas production for
periods after December 2000:
NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
------ --------- ------------
March 2001.................................................. 310,000 $5.93
April 2001.................................................. 300,000 5.66
May 2001.................................................... 930,000 5.34
June 2001................................................... 900,000 5.37
July 2001................................................... 930,000 5.40
August 2001................................................. 930,000 5.42
September 2001.............................................. 900,000 5.38
October 2001................................................ 1,240,000 5.40
The natural gas swap for March 2001 was settled for a gain of $0.3 million
which will be recognized as a price adjustment in March 2001. If we had settled
the remaining swaps (April through October) using March 21, 2001 prices, we
would have incurred a gain of $1.0 million.
Subsequent to December 31, 2000, we entered into the following natural gas
collar transactions designed to hedge a portion of our domestic gas production
for periods after December 2000:
-35-
37
NYMEX NYMEX
DEFINED DEFINED
HIGH LOW
VOLUME STRIKE PRICE STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU) (PER MMBTU)
------ --------- ------------ ------------
June 2001................................................... 600,000 $6.80 $5.00
July 2001................................................... 620,000 6.80 5.00
August 2001................................................. 620,000 6.80 5.00
September 2001.............................................. 600,000 6.80 5.00
January 2002 ............................................... 620,000 5.75 4.00
February 2002 .............................................. 560,000 5.75 4.00
March 2002.................................................. 620,000 5.75 4.00
April 2002.................................................. 1,200,000 5.38 4.00
May 2002.................................................... 1,240,000 5.38 4.00
June 2002................................................... 1,200,000 5.38 4.00
July 2002 .................................................. 1,240,000 5.38 4.00
August 2002................................................. 1,240,000 5.38 4.00
September 2002.............................................. 1,200,000 5.38 4.00
October 2002................................................ 1,240,000 5.38 4.00
November 2002............................................... 600,000 5.75 4.00
December 2002............................................... 620,000 5.75 4.00
Subsequent to December 31, 2000, we entered into natural gas cap-swaps
designed to hedge a portion of our domestic gas production for periods after
December 2000. This transaction requires that we pay the counterparty if the
NYMEX price exceeds an average Nymex defined strike price. If the NYMEX price is
less than the strike price, the counterparty pays us. However, the
counterparty's payment is capped.
NYMEX CAPPED
INDEX LOW
VOLUME STRIKE PRICE STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU) (PER MMBTU)
------ --------- ------------ ------------
May 2001.................................................... 1,860,000 5.77 4.60
June 2001................................................... 1,800,000 5.81 4.64
July 2001................................................... 1,860,000 5.85 4.68
August 2001................................................. 1,860,000 5.87 4.70
September 2001.............................................. 1,800,000 5.83 4.66
October 2001................................................ 1,860,000 5.83 4.66
November 2001............................................... 2,400,000 6.00 4.78
December 2001............................................... 2,480,000 6.10 4.88
January 2002................................................ 2,790,000 6.03 4.83
February 2002............................................... 2,520,000 5.82 4.62
March 2002.................................................. 2,790,000 5.48 4.28
April 2002.................................................. 5,700,000 4.85 3.85
May 2002.................................................... 5,890,000 4.81 3.81
June 2002................................................... 5,700,000 4.80 3.80
July 2002................................................... 5,890,000 4.81 3.81
August 2002................................................. 5,890,000 4.81 3.81
September 2002.............................................. 5,700,000 4.81 3.81
October 2002................................................ 5,890,000 4.80 3.80
November 2002............................................... 2,100,000 4.97 3.97
December 2002............................................... 2,170,000 5.06 4.06
In addition to commodity hedging transactions related to our oil and gas
production, our marketing subsidiary, CEMI, periodically enters into various
hedging transactions designed to hedge against physical purchase and sale
commitments it makes. Gains or losses on these transactions are recorded as
adjustments to oil and gas marketing sales in the consolidated statements of
operations and are not considered material by management.
INTEREST RATE RISK
Chesapeake also utilizes hedging strategies to manage fixed-interest rate
exposure. Through the use of a swap arrangement, we reduced our interest expense
by $2.6 million from May 1998 through December 2000.
-36-
38
During 2000, our interest rate swap resulted in a net $38,000 increase in
interest expense. The terms of the swap agreement are as follows:
Months Notional Amount Fixed Rate Floating Rate
------ --------------- ---------- -------------
May 1998 -- April
2001 $230,000,000 7% Average of three-month Swiss Franc
LIBOR, Deutsche Mark and Australian
Dollar plus 300 basis points
May 2001 -- April
2008 $230,000,000 7% U.S. three-month LIBOR plus 300
basis points
If the floating rate is less than the fixed rate, the counterparty will pay
us accordingly. If the floating rate exceeds the fixed rate, we will pay the
counterparty. The interest rate swap agreement contains a "knockout provision"
whereby the agreement will terminate on or after May 1, 2001 if the average
closing price for the previous twenty business days for shares of Chesapeake's
common stock is greater than or equal to $7.50 per share. The agreement also
provides for a maximum floating rate of 8.5% from May 2001 through April 2008.
Based on current market prices for Chesapeake common stock, we expect the
interest rate swap agreement will terminate in May 2001 under the knockout
provision of the agreement discussed above. The fair value of the swap agreement
at December 31, 2000 was not material. Results from interest rate hedging
transactions are reflected as adjustments to interest expense in the
corresponding months covered by the swap agreement.
The table below presents principal cash flows and related weighted average
interest rates by expected maturity dates. The fair value of the long-term debt
has been estimated based on quoted market prices.
DECEMBER 31, 2000
------------------------------------------------------------------------
YEARS OF MATURITY
------------------------------------------------------------------------
2001 2002 2003 2004 2005 THEREAFTER TOTAL FAIR VALUE
---- ----- ---- ------ ------ ---------- ------ ----------
($ IN MILLIONS)
LIABILITIES:
Long-term debt, including current
portion -- fixed rate.......... $0.8 $ 0.6 $-- $150.0 $500.0 $270.0 $921.4 $894.7
Average interest rate.......... 9.1% 9.1% -- 7.9% 9.6% 8.8% 9.1% --
Long-term debt -- variable
rate........................... $-- $25.0 $-- $ -- $ -- $ -- $ 25.0 $ 25.0
Average interest rate.......... -- 9.3% -- -- -- -- 9.3% --
-37-
39
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
CHESAPEAKE ENERGY CORPORATION
PAGE
----
Consolidated Financial Statements:
Report of Independent Accountants......................... 39
Consolidated Balance Sheets at December 31, 1999 and
2000................................................... 40
Consolidated Statements of Operations for the Years Ended
December 31, 1998, 1999 and 2000....................... 41
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1999 and 2000....................... 42
Consolidated Statements of Stockholders' Equity (Deficit)
and Comprehensive Income (Loss) for the Years Ended
December 31, 1998, 1999 and 2000....................... 44
Notes to Consolidated Financial Statements................ 45
Financial Statement Schedules:
Schedule II -- Valuation and Qualifying Accounts.......... 77
Pro Forma Combined Financial Statements:
Summary................................................... 78
Unaudited Pro Forma Combined Balance Sheet at December 31,
2000................................................... 79
Unaudited Pro Forma Combined Statement of Operations for
the Year Ended December 31, 2000....................... 80
Notes to Unaudited Pro Forma Combined Financial
Statements............................................. 81
GOTHIC ENERGY CORPORATION
Report of Independent Accountants........................... 83
Consolidated Balance Sheets, December 31, 1999 and 2000..... 84
Consolidated Statement of Operations, Years ended December
31, 1998, 1999 and 2000................................... 85
Consolidated Statement of Stockholders' Equity (Deficit),
Years ended December 31, 1998, 1999 and 2000.............. 86
Consolidated Statement of Cash Flows, Years ended December
31, 1998, 1999 and 2000................................... 87
Notes to Consolidated Financial Statements.................. 88
-38-
40
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders
of Chesapeake Energy Corporation
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Chesapeake Energy Corporation and its subsidiaries (the "Company")
at December 31, 1999 and 2000, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2000, in
conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement schedule listed in
the accompanying index presents fairly, in all material respects, the
information set forth therein when read in conjunction with the related
consolidated financial statements. These financial statements and financial
statement schedule are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements and
financial statement schedule based on our audits. We conducted our audits of
these financial statements in accordance with auditing standards generally
accepted in the United States of America, which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Oklahoma City, Oklahoma
March 28, 2001
-39-
41
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
--------------------------
1999 2000
----------- -----------
($ IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 38,658 $ --
Restricted cash........................................... 192 3,500
Accounts receivable:
Oil and gas sales....................................... 17,045 50,109
Oil and gas marketing sales............................. 18,199 46,953
Joint interest and other, net of allowances of
$3,218,000 and $1,085,000, respectively................ 11,247 15,998
Related parties......................................... 4,574 4,383
Deferred income tax asset................................. -- 40,819
Inventory................................................. 4,582 3,167
Other..................................................... 3,049 1,997
----------- -----------
Total Current Assets................................ 97,546 166,926
----------- -----------
PROPERTY AND EQUIPMENT:
Oil and gas properties, at cost based on full-cost
accounting:
Evaluated oil and gas properties........................ 2,315,348 2,590,512
Unevaluated properties.................................. 40,008 25,685
Less: accumulated depreciation, depletion and
amortization........................................... (1,670,542) (1,770,827)
----------- -----------
684,814 845,370
Other property and equipment.............................. 67,712 79,898
Less: accumulated depreciation and amortization........... (33,429) (37,034)
----------- -----------
Total Property and Equipment........................ 719,097 888,234
INVESTMENT IN GOTHIC ENERGY CORPORATION..................... 10,000 126,434
DEFERRED INCOME TAX ASSET................................... -- 229,823
OTHER ASSETS................................................ 23,890 29,009
----------- -----------
TOTAL ASSETS................................................ $ 850,533 $ 1,440,426
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Notes payable and current maturities of long-term debt.... $ 763 $ 836
Accounts payable.......................................... 24,822 62,940
Accrued property acquisitions............................. -- 22,530
Accrued interest.......................................... 17,807 17,537
Other accrued liabilities................................. 16,906 21,637
Revenues and royalties due others......................... 27,888 35,682
Income tax payable........................................ -- 1,539
----------- -----------
Total Current Liabilities........................... 88,186 162,701
----------- -----------
LONG-TERM DEBT, NET......................................... 964,097 944,845
----------- -----------
REVENUES AND ROYALTIES DUE OTHERS........................... 9,310 7,798
----------- -----------
DEFERRED INCOME TAX LIABILITY............................... 6,484 11,850
----------- -----------
CONTINGENCIES AND COMMITMENTS (NOTE 4)
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred Stock, $.01 par value, 10,000,000 shares
authorized; 4,596,400 and 624,037 shares of 7%
cumulative convertible stock issued and outstanding at
December 31, 1999 and 2000, respectively, entitled in
liquidation to $229.8 million and $31.2 million,
respectively............................................ 229,820 31,202
Common Stock, par value of $.01, 250,000,000 shares
authorized; 105,858,580 and 157,819,171 shares issued at
December 31, 1999 and 2000, respectively................ 1,059 1,578
Paid-in capital........................................... 682,905 963,584
Accumulated deficit....................................... (1,093,929) (659,286)
Accumulated other comprehensive income (loss)............. 196 (3,901)
Less: treasury stock, at cost; 10,856,185 and 4,788,747
common shares at December 31, 1999 and 2000,
respectively............................................ (37,595) (19,945)
----------- -----------
Total Stockholders' Equity (Deficit)................ (217,544) 313,232
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)........ $ 850,533 $ 1,440,426
=========== ===========
The accompanying notes are an integral part of these consolidated financial
statements.
-40-
42
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31,
----------------------------------------
1998 1999 2000
----------- --------- ----------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
REVENUES:
Oil and gas sales......................................... $ 256,887 $280,445 $ 470,170
Oil and gas marketing sales............................... 121,059 74,501 157,782
---------- -------- ---------
Total Revenues.......................................... 377,946 354,946 627,952
---------- -------- ---------
OPERATING COSTS:
Production expenses....................................... 51,202 46,298 50,085
Production taxes.......................................... 8,295 13,264 24,840
General and administrative................................ 19,918 13,477 13,177
Oil and gas marketing expenses............................ 119,008 71,533 152,309
Oil and gas depreciation, depletion and amortization...... 146,644 95,044 101,291
Depreciation and amortization of other assets............. 8,076 7,810 7,481
Impairment of oil and gas properties...................... 826,000 -- --
Impairment of other assets................................ 55,000 -- --
---------- -------- ---------
Total Operating Costs................................... 1,234,143 247,426 349,183
---------- -------- ---------
INCOME (LOSS) FROM OPERATIONS............................... (856,197) 107,520 278,769
---------- -------- ---------
OTHER INCOME (EXPENSE):
Interest and other income................................. 3,926 8,562 3,649
Interest expense.......................................... (68,249) (81,052) (86,256)
---------- -------- ---------
(64,323) (72,490) (82,607)
---------- -------- ---------
INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM.... (920,520) 35,030 196,162
PROVISION (BENEFIT) FOR INCOME TAXES........................ -- 1,764 (259,408)
---------- -------- ---------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM..................... (920,520) 33,266 455,570
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt, net of applicable
income tax of $0........................................ (13,334) -- --
---------- -------- ---------
NET INCOME (LOSS)........................................... (933,854) 33,266 455,570
PREFERRED STOCK DIVIDENDS................................... (12,077) (16,711) (8,484)
GAIN ON REDEMPTION OF PREFERRED STOCK....................... -- -- 6,574
---------- -------- ---------
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS.......... $ (945,931) $ 16,555 $ 453,660
========== ======== =========
EARNINGS (LOSS) PER COMMON SHARE:
EARNINGS (LOSS) PER COMMON SHARE -- BASIC:
Income (loss) before extraordinary item................. $ (9.83) $ 0.17 $ 3.52
Extraordinary item...................................... (0.14) -- --
---------- -------- ---------
Net income (loss)....................................... $ (9.97) $ 0.17 $ 3.52
========== ======== =========
EARNINGS (LOSS) PER COMMON SHARE-ASSUMING DILUTION:
Income (loss) before extraordinary item................. $ (9.83) $ 0.16 $ 3.01
Extraordinary item...................................... (0.14) -- --
---------- -------- ---------
Net income (loss)....................................... $ (9.97) $ 0.16 $ 3.01
========== ======== =========
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES
OUTSTANDING (IN THOUSANDS):
Basic................................................... 94,911 97,077 128,993
========== ======== =========
Assuming dilution....................................... 94,911 102,038 151,564
========== ======== =========
The accompanying notes are an integral part of these consolidated financial
statements.
-41-
43
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31,
---------------------------------
1998 1999 2000
--------- --------- ---------
($ IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)........................................... $(933,854) $ 33,266 $ 455,570
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED
BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization.................. 152,204 99,516 105,103
Provision (benefit) for deferred income taxes............. -- 1,764 (259,408)
Impairment of oil and gas assets.......................... 826,000 -- --
Impairment of other assets................................ 55,000 -- --
Amortization of loan costs................................ 2,516 3,338 3,669
Amortization of bond discount............................. 98 84 84
Bad debt expense.......................................... 1,589 9 256
Gain (loss) on sale of fixed assets....................... (90) (459) 8
Extraordinary loss........................................ 13,334 -- --
Equity in (earnings) losses from investments.............. 703 1,209 131
Other..................................................... -- -- 391
--------- --------- ---------
Cash provided by operating activities before changes in
current assets and liabilities.......................... 117,500 138,727 305,804
--------- --------- ---------
CHANGES IN ASSETS AND LIABILITIES:
(Increase) decrease in short-term investments............. 12,027 -- --
(Increase) decrease in accounts receivable................ 12,191 17,592 (66,706)
(Increase) decrease in inventory.......................... 168 743 1,415
(Increase) decrease in other current assets............... 7,637 3,614 2,884
Increase (decrease) in accounts payable, accrued
liabilities and other................................... (46,785) (23,891) 64,955
Increase (decrease) in current and non-current revenues
and royalties due others................................ (8,099) 3,517 6,282
Increase (decrease) in deferred income taxes.............. -- 4,720 6
--------- --------- ---------
Changes in assets and liabilities....................... (22,861) 6,295 8,836
--------- --------- ---------
Cash provided by operating activities................... 94,639 145,022 314,640
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development of oil and gas properties..... (259,710) (153,268) (188,778)
Acquisitions of oil and gas companies, proved properties
and unproved properties, net of cash acquired........... (279,924) (49,893) (78,910)
Divestitures of oil and gas properties.................... 15,712 45,635 1,529
Investment in preferred stock of Gothic Energy
Corporation............................................. (39,500) -- --
Investment in Gothic (notes and other costs).............. -- -- (36,693)
Repayment of note receivable.............................. 2,000 -- --
Proceeds from sale of investment in PanEast............... 21,245 -- --
Other proceeds from sales................................. 3,600 5,530 1,069
Increase in deferred charges.............................. -- (5,865) (4,807)
Other investments......................................... -- (730) (10,019)
Other property and equipment additions.................... (11,473) (1,182) (13,427)
--------- --------- ---------
Cash used in investing activities....................... (548,050) (159,773) (330,036)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings........................ 658,750 116,500 244,000
Payments on long-term borrowings.......................... (474,166) (98,000) (262,500)
Dividends paid on common stock............................ (5,592) -- --
Dividends paid on preferred stock......................... (8,050) -- (4,645)
Proceeds from issuance of preferred stock................. 222,663 -- --
Purchase of treasury stock and preferred stock............ (29,962) (53) --
Cash paid in connection with issuance of common stock for
preferred stock......................................... -- -- (8,269)
Cash received from previous Gothic noteholders in
settlement of make-whole provision...................... -- -- 7,083
Cash received from exercise of stock options.............. 154 520 1,398
--------- --------- ---------
Cash provided by (used in) financing activities......... 363,797 18,967 (22,933)
--------- --------- ---------
EFFECT OF EXCHANGE RATE CHANGES ON CASH..................... (4,726) 4,922 (329)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents........ (94,340) 9,138 (38,658)
Cash and cash equivalents, beginning of period.............. 123,860 29,520 38,658
--------- --------- ---------
Cash and cash equivalents, end of period.................... $ 29,520 $ 38,658 $ --
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
-42-
44
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS -- (CONTINUED)
YEARS ENDED DECEMBER 31,
-------------------------------
1998 1999 2000
--------- ------- -------
($ IN THOUSANDS)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAYMENTS FOR:
Interest, net of capitalized interest..................... $ 59,881 $80,684 $85,401
Income taxes.............................................. $ -- $ -- $ --
DETAILS OF ACQUISITION OF DLB OIL & GAS, INC.:
Fair value of assets acquired............................. $ 136,500 $ -- $ --
Cash consideration........................................ $ (17,500) $ -- $ --
Stock issued (5,000,000 shares)........................... $ (30,000) $ -- $ --
Debt assumed.............................................. $ (85,000) $ -- $ --
Acquisition costs paid.................................... $ (4,000) $ -- $ --
DETAILS OF ACQUISITION OF HUGOTON ENERGY CORPORATION:
Fair value of assets acquired............................. $ 343,371 $ -- $ --
Stock options granted..................................... $ (2,050) $ -- $ --
Stock issued (25,790,146 shares).......................... $(206,321) $ -- $ --
Debt assumed.............................................. $(120,000) $ -- $ --
Acquisition costs paid.................................... $ (15,000) $ -- $ --
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
In December 1997, we declared a dividend of $0.02 per common share, or
$1,486,000, which was paid in January 1998.
Proceeds from the issuance of $500 million of 9.625% senior notes in April
1998 are net of $11.7 million in offering fees and expenses which were deducted
from the actual cash received.
In 1999, the chief executive officer and chief operating officer of
Chesapeake tendered to Chesapeake Energy Marketing, Inc. 2,320,107 shares of
Chesapeake common stock in full satisfaction of two notes payable to CEMI with a
combined outstanding balance of $7.6 million.
During 1999, we issued a $2.2 million note payable as consideration for the
acquisition of certain oil and gas properties.
During 2000, Chesapeake engaged in unsolicited transactions in which a
total of 43.4 million shares of Chesapeake common stock, plus a cash payment of
$8.3 million, were exchanged for 3,972,363 shares of Chesapeake preferred stock.
During 2000, Chesapeake Energy Marketing, Inc. purchased 99.8% of Gothic
Energy Corporation's $104 million 14.125% Series B senior secured discount notes
for total consideration of $80.8 million, comprised of $17.2 million in cash and
$63.6 million of Chesapeake common stock (8,875,775 shares valued at $7.16 per
share), as adjusted for make-whole provisions. Through the make-whole
provisions, Chesapeake Energy Marketing, Inc. received $6.1 million in cash and
$7.2 million of Chesapeake common stock (982,562 shares).
In 2000, Chesapeake purchased $31.6 million of the $235 million of 11.125%
senior secured notes issued by Gothic Production Corporation for total
consideration of $34.8 million comprised of $11.5 million in cash and $23.3
million of Chesapeake common stock (3,694,939 shares valued at $6.30 per share),
as adjusted for make-whole provisions. Through the make-whole provisions,
Chesapeake received $1.0 million in cash.
The accompanying notes are an integral part of these consolidated financial
statements.
-43-
45
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) AND
COMPREHENSIVE INCOME (LOSS)
YEARS ENDED DECEMBER 31,
-----------------------------------------
1998 1999 2000
----------- ----------- -----------
($ IN THOUSANDS)
PREFERRED STOCK:
Balance, beginning of period.............................. $ -- $ 230,000 $ 229,820
Exchange of common stock and cash for 3,972,363 shares of
preferred stock......................................... -- -- (198,618)
Exchange of common stock for 3,600 shares of preferred
stock................................................... -- (180) --
Issuance of preferred stock............................... 230,000 -- --
----------- ----------- -----------
Balance, end of period.................................... 230,000 229,820 31,202
----------- ----------- -----------
COMMON STOCK:
Balance, beginning of period.............................. 743 1,052 1,059
Exercise of stock options and warrants.................... -- 6 20
Issuance of 25,790,146 shares of common stock to Hugoton
Energy Corporation...................................... 258 -- --
Issuance of 5,000,000 shares of common stock to DLB Oil
and Gas, Inc............................................ 50 -- --
Exchange of 36,366,915 shares of common stock for
preferred stock......................................... -- -- 363
Issuance of 13,553,302 shares of common stock to acquire
Gothic notes............................................ -- -- 136
Change in par value and other............................. 1 1 --
----------- ----------- -----------
Balance, end of period.................................... 1,052 1,059 1,578
----------- ----------- -----------
PAID-IN CAPITAL:
Balance, beginning of period.............................. 460,770 682,263 682,905
Exercise of stock options and warrants.................... 153 514 1,377
Issuance of common stock to acquire Gothic notes.......... -- -- 93,885
Issuance of common stock to acquire Hugoton Energy
Corporation............................................. 206,063 -- --
Issuance of common stock to acquire DLB Oil and Gas,
Inc. ................................................... 29,950 -- --
Offering expenses and other............................... (16,723) 1 --
Stock options issued in Hugoton purchase.................. 2,050 -- --
Exchange of 36,366,915 shares of common stock for
preferred stock......................................... -- 127 187,069
Exchange of 7,050,000 shares of treasury stock for
preferred stock......................................... -- -- (5,640)
Compensation related to stock options..................... -- -- 238
Tax benefit from exercise of stock options................ -- -- 3,750
----------- ----------- -----------
Balance, end of period.................................... 682,263 682,905 963,584
----------- ----------- -----------
ACCUMULATED DEFICIT:
Balance, beginning of period.............................. (181,270) (1,127,195) (1,093,929)
Net income (loss)......................................... (933,854) 33,266 455,570
Dividends on common stock................................. (4,021) -- --
Dividends on preferred stock.............................. (8,050) -- (4,645)
Fair value of common stock exchanged in excess of book
value of preferred stock................................ -- -- (8,013)
Cash paid in connection with issuance of common stock for
preferred stock......................................... -- -- (8,269)
----------- ----------- -----------
Balance, end of period.................................... (1,127,195) (1,093,929) (659,286)
----------- ----------- -----------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance, beginning of period.............................. (37) (4,726) 196
Foreign currency translation adjustments.................. (4,689) 4,922 (4,097)
----------- ----------- -----------
Balance, end of period.................................... (4,726) 196 (3,901)
----------- ----------- -----------
TREASURY STOCK -- COMMON:
Balance, beginning of period.............................. -- (29,962) (37,595)
Settlement of notes receivable for 2,320,107 shares of
common stock from related parties....................... -- (7,633) --
Purchase of 8,503,300 shares of treasury stock............ (29,962) -- --
Exchange of 7,050,000 shares of treasury stock for
preferred stock......................................... -- -- 24,841
Receipt of 982,562 shares of common stock from previous
Gothic note holders in settlement of make-whole
provision............................................... -- -- (7,191)
----------- ----------- -----------
Balance, end of period.................................... (29,962) (37,595) (19,945)
----------- ----------- -----------
TOTAL STOCKHOLDERS' EQUITY (DEFICIT)........................ $ (248,568) $ (217,544) $ 313,232
=========== =========== ===========
COMPREHENSIVE INCOME (LOSS):
Net income (loss)......................................... $ (933,854) $ 33,266 $ 455,570
Other comprehensive income (loss) -- foreign currency
translation adjustments................................. (4,689) 4,922 (4,097)
----------- ----------- -----------
Comprehensive income (loss)............................... $ (938,543) $ 38,188 $ 451,473
=========== =========== ===========
The accompanying notes are an integral part of these consolidated financial
statements.
-44-
46
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Company
Chesapeake Energy Corporation is an oil and natural gas exploration and
production company engaged in the acquisition, exploration, and development of
properties for the production of crude oil and natural gas from underground
reservoirs. Our properties are located in Oklahoma, Texas, Arkansas, Louisiana,
Kansas, Montana, Colorado, North Dakota, New Mexico and British Columbia and
Saskatchewan, Canada.
Principles of Consolidation
The accompanying consolidated financial statements of Chesapeake Energy
Corporation include the accounts of our direct and indirect wholly-owned
subsidiaries. All significant intercompany accounts and transactions have been
eliminated. Investments in companies and partnerships which give us significant
influence, but not control, over the investee are accounted for using the equity
method. Other investments are generally carried at cost.
Accounting Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the dates of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from those estimates.
Cash Equivalents
For purposes of the consolidated financial statements, Chesapeake considers
investments in all highly liquid debt instruments with maturities of three
months or less at date of purchase to be cash equivalents.
Inventory
Inventory consists primarily of tubular goods and other lease and well
equipment which we plan to utilize in our ongoing exploration and development
activities and is carried at the lower of cost or market using the specific
identification method.
Oil and Gas Properties
Chesapeake follows the full-cost method of accounting under which all costs
associated with property acquisition, exploration and development activities are
capitalized. We capitalize internal costs that can be directly identified with
our acquisition, exploration and development activities and do not include any
costs related to production, general corporate overhead or similar activities
(see note 11). Capitalized costs are amortized on a composite unit-of-production
method based on proved oil and gas reserves. As of December 31, 2000,
approximately 72% of our present value (discounted at 10%) of estimated future
net revenues of proved reserves was evaluated by independent petroleum
engineers, with the balance evaluated by our internal reservoir engineers. In
addition, our internal engineers evaluate all properties quarterly. The average
composite rates used for depreciation, depletion and amortization were $1.13
($1.17 in U.S. and $0.43 in Canada) per equivalent mcf in 1998, $0.71 ($0.73 in
U.S. and $0.52 in Canada) per equivalent mcf in 1999, and $0.75 ($0.76 in U.S.
and $0.71 in Canada) per equivalent mcf in 2000.
Proceeds from the sale of properties are accounted for as reductions to
capitalized costs unless such sales involve a significant change in the
relationship between costs and the value of proved reserves or the underlying
value of unproved properties, in which case a gain or loss is recognized. The
costs of unproved properties are excluded from amortization until the properties
are evaluated. We review all of our unevaluated properties quarterly to
determine whether or not and to what extent proved reserves have been assigned
to the properties, and otherwise
-45-
47
if impairment has occurred. Unevaluated properties are grouped by major
producing area where individual property costs are not significant, and assessed
individually when individual costs are significant.
We review the carrying value of our oil and gas properties under the
full-cost accounting rules of the Securities and Exchange Commission on a
quarterly basis. Under these rules, capitalized costs, less accumulated
amortization and related deferred income taxes, may not exceed an amount equal
to the sum of the present value of estimated future net revenues less estimated
future expenditures to be incurred in developing and producing the proved
reserves, less any related income tax effects. During 1998, capitalized costs of
oil and gas properties exceeded the estimated present value of future net
revenues from our proved reserves, net of related income tax considerations,
resulting in writedowns in the carrying value of oil and gas properties of $826
million.
Other Property and Equipment
Other property and equipment consists primarily of gas gathering and
processing facilities, vehicles, land, office buildings and equipment, and
software. Major renewals and betterments are capitalized while the costs of
repairs and maintenance are charged to expense as incurred. The costs of assets
retired or otherwise disposed of and the applicable accumulated depreciation are
removed from the accounts, and the resulting gain or loss is reflected in
operations. Other property and equipment costs are depreciated on both
straight-line and accelerated methods. Buildings are depreciated on a
straight-line basis over 31.5 years. All other property and equipment are
depreciated over the estimated useful lives of the assets, which range from five
to seven years.
Capitalized Interest
During 1998, 1999 and 2000, interest of approximately $6.5 million, $3.5
million and $2.4 million, respectively, was capitalized on significant
investments in unproved properties that were not being currently depreciated,
depleted, or amortized and on which exploration activities were in progress.
Income Taxes
Chesapeake has adopted Statement of Financial Accounting Standards No. 109,
Accounting for Income Taxes. SFAS 109 requires deferred tax liabilities or
assets to be recognized for the anticipated future tax effects of temporary
differences that arise as a result of the differences in the carrying amounts
and the tax bases of assets and liabilities.
Net Income (Loss) Per Share
Statement of Financial Accounting Standards No. 128, Earnings Per Share,
requires presentation of "basic" and "diluted" earnings per share, as defined,
on the face of the statements of operations for all entities with complex
capital structures. SFAS 128 requires a reconciliation of the numerator and
denominator of the basic and diluted EPS computations. For 1998, there was no
difference between actual weighted average shares outstanding, which are used in
computing basic EPS and diluted weighted average shares, which are used in
computing diluted EPS.
The following weighted securities were not included in the calculation of
diluted earnings per share, as the effect was antidilutive:
- For the year ended December 31, 1999 and 2000, outstanding options to
purchase 1.3 million and 1.1 million shares of common stock at a
weighted average exercise price of $7.14 and $8.73, respectively, were
antidilutive because the exercise prices of the options were greater
than the average market price of the common stock.
- For the year ended December 31, 1999, the assumed conversion of the
outstanding preferred stock (convertible into 33 million common
shares) was not included as the effect was antidilutive.
-46-
48
A reconciliation for the year ended December 31, 1999 and 2000 is as follows:
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
FOR THE YEAR ENDED DECEMBER 31, 1999:
BASIC EPS
Income available to common stockholders..................... $16,555 97,077 $0.17
=====
EFFECT OF DILUTIVE SECURITIES
Employee stock options...................................... -- 4,961
------- -------
DILUTED EPS
Income available to common stockholders and assumed
conversions............................................... $16,555 102,038 $0.16
======= ======= =====
FOR THE YEAR ENDED DECEMBER 31, 2000:
BASIC EPS
Income available to common stockholders..................... $453,660 128,993 $3.52
=====
EFFECT OF DILUTIVE SECURITIES
Assumed conversion at the beginning of the period of
preferred shares exchanged during the period:
Common shares assumed issued.............................. -- 11,440
Preferred stock dividends................................. 8,484 --
Gain on redemption of preferred stock..................... (6,574) --
Assumed conversion of 624,037 shares of preferred stock at
beginning of period....................................... -- 4,489
Employee stock options...................................... -- 6,642
-------- -------
DILUTED EPS
Income available to common stockholders and assumed
conversions............................................... $455,570 151,564 $3.01
======== ======= =====
During the year ended December 31, 2000, Chesapeake engaged in a number of
unsolicited stock exchange transactions with institutional investors. A total of
43.4 million shares of common stock, plus a cash payment of $8.3 million, were
exchanged for 3,972,363 shares of preferred stock. These transactions reduced
(i) the number of preferred shares from 4.6 million to 0.6 million, (ii) the
liquidation value of the preferred stock from $229.8 million to $31.2 million,
and (iii) dividends in arrears by $22.9 million. A gain on redemption of all
preferred shares exchanged during 2000 of $6.6 million is reflected in net
income available to common shareholders in determining basic earnings per share.
All preferred shares acquired in these transactions were cancelled and retired
and have the status of authorized but unissued shares of undesignated preferred
stock. The gain represented the excess of (i) the liquidation value of the
preferred shares that were retired plus dividends in arrears which had reduced
prior EPS over (ii) the market value of the common stock issued and cash paid in
exchange for the preferred shares.
Gas Imbalances -- Revenue Recognition
Revenues from the sale of oil and gas production are recognized when title
passes, net of royalties. We follow the "sales method" of accounting for our gas
revenue whereby we recognize sales revenue on all gas sold to our purchasers,
regardless of whether the sales are proportionate to our ownership in the
property. A liability is recognized only to the extent that we have a net
imbalance in excess of the remaining gas reserves on the underlying properties.
Our net imbalance positions at December 31, 1998, 1999 and 2000 were not
material.
Hedging
Chesapeake periodically uses commodity price risk management instruments to
hedge our exposure to price fluctuations on oil and natural gas transactions and
interest rates. Recognized gains and losses on hedge contracts are reported as a
component of the related transaction. Results of oil and gas hedging
transactions are reflected in oil and gas sales to the extent related to our oil
and gas production, in oil and gas marketing sales to the extent related to our
marketing activities, and in interest expense to the extent so related.
On June 15, 1998, the Financial Accounting Standards Board issued SFAS No.
133, Accounting for Derivative Instruments and Hedging Activities. SFAS 133
establishes a new model for accounting for derivatives and hedging
-47-
49
activities and supersedes and amends a number of existing standards. SFAS 133
(as amended by SFAS 137 and SFAS 138) is effective for all fiscal quarters of
fiscal years beginning after June 15, 2000.
SFAS 133 standardizes the accounting for derivative instruments by
requiring that all derivatives be recognized as assets and liabilities and
measured at fair value. The accounting for changes in the fair value of
derivatives (gains and losses) depends on (i) whether the derivative is
designated and qualifies as a hedge, and (ii) the type of hedging relationship
that exists. Changes in the fair value of derivatives that are not designated as
hedges or that do not meet the hedge accounting criteria in SFAS 133 are
required to be reported in earnings. In addition, all hedging relationships must
be designated, reassessed and documented pursuant to the provisions of SFAS 133.
We will fully adopt SFAS 133 on January 1, 2001, the effective date as amended
by SFAS 138. SFAS 133 is expected to increase volatility of stockholders'
equity, reported earnings (losses) and other comprehensive income. If we had
adopted SFAS 133 on December 31, 2000, Chesapeake would have recorded an
additional $9.3 million in current assets and $98.6 million in current
liabilities related to our existing oil and gas hedges based on the forward
price curve in effect at December 31, 2000. The net liability of $89.3 million
related to qualifying hedge instruments would have been charged to other
comprehensive income which appears in the equity section of the balance sheet.
After adoption, Chesapeake will be required to recognize any hedge
ineffectiveness in the income statement each period.
Debt Issue Costs
Included in other assets are costs associated with the issuance of our
senior notes. The remaining unamortized costs on these issuances of senior notes
at December 31, 1999 and 2000 totaled $16.6 million and $13.9 million,
respectively, and are being amortized over the life of the senior notes.
Currency Translation
The results of operations for non-U.S. subsidiaries are translated from
local currencies into U.S. dollars using average exchange rates during each
period; assets and liabilities are translated using exchange rates at the end of
each period. Adjustments resulting from the translation process are reported in
a separate component of stockholders' equity, and are not included in the
determination of the results of operations.
Reclassifications
Certain reclassifications have been made to the consolidated financial
statements for 1998 and 1999 to conform to the presentation used for the 2000
consolidated financial statements.
2. SENIOR NOTES
On April 22, 1998, we issued $500 million principal amount of 9.625% Senior
Notes due 2005. The 9.625% Senior Notes are redeemable at our option at any time
on or after May 1, 2002 at the redemption prices set forth in the indenture or
at the make-whole prices, as set forth in the indenture, if redeemed prior to
May 1, 2002. We may also redeem at our option up to $167 million of the 9.625%
Senior Notes at 109.625% of their principal amount with the proceeds of an
equity offering completed prior to May 1, 2001.
On March 17, 1997, we issued $150 million principal amount of 7.875% Senior
Notes due 2004. The 7.875% Senior Notes are redeemable at our option at any time
prior to March 15, 2004, at the make-whole prices determined in accordance with
the indenture.
Also on March 17, 1997, we issued $150 million principal amount of 8.5%
Senior Notes due 2012. The 8.5% Senior Notes are redeemable at our option at any
time prior to March 15, 2004, at the make-whole prices determined in accordance
with the indenture and, on or after March 15, 2004, at the redemption prices set
forth in the indenture. As of March 28, 2001, Chesapeake has purchased and
subsequently retired $7.3 million of these notes for total consideration of $7.4
million, including accrued interest of $0.2 million.
On April 9, 1996, we issued $120 million principal amount of 9.125% Senior
Notes due 2006. The 9.125% Senior Notes are redeemable at our option at any time
prior to April 15, 2001 at the make-whole prices determined in accordance with
the indenture and, on or after April 15, 2001, at the redemption prices set
forth in the indenture.
-48-
50
On May 25, 1995, we issued $90 million principal amount of 10.5% Senior
Notes due 2002. In April 1998, we purchased all of our 10.5% Senior Notes for
approximately $99 million. The early retirement of these notes resulted in an
extraordinary charge of $13.3 million.
Chesapeake is a holding company and owns no operating assets and has no
significant operations independent of its subsidiaries. Our obligations under
the 9.625% Senior Notes, the 9.125% Senior Notes, the 7.875% Senior Notes and
the 8.5% Senior Notes have been fully and unconditionally guaranteed, on a joint
and several basis, by each of our "Restricted Subsidiaries" (as defined in the
respective indentures governing the Senior Notes). Each guarantor subsidiary is
a direct or indirect wholly-owned subsidiary.
The senior note indentures contain certain covenants, including covenants
limiting us and the guarantor subsidiaries with respect to asset sales;
restricted payments; the incurrence of additional indebtedness and the issuance
of preferred stock; liens; sale and leaseback transactions; lines of business;
dividend and other payment restrictions affecting guarantor subsidiaries;
mergers or consolidations; and transactions with affiliates. We are obligated to
repurchase the 9.625% and 9.125% Senior Notes in the event of a change of
control or certain asset sales.
The senior note indentures also limit our ability to make restricted
payments (as defined), including the payment of cash dividends, unless certain
tests are met. From December 31, 1998 through March 31, 2000, we were unable to
meet the requirements to incur additional unsecured indebtedness, and
consequently were restricted from paying cash dividends on our 7% cumulative
convertible preferred stock. As a result of our failure to pay dividends for six
quarterly periods, the holders of preferred stock were entitled to elect two new
directors to the Chesapeake board after May 1, 2000. On September 22, 2000, we
declared a regular quarterly dividend and a special dividend equal to all unpaid
dividends on our preferred stock, both payable November 1, 2000 to shareholders
of record on October 16, 2000. A total combined dividend of $7.444 per
outstanding preferred share was paid November 1, 2000, eliminating the right of
preferred stockholders to elect directors.
Set forth below are condensed consolidating financial statements of the
guarantor subsidiaries and Chesapeake's subsidiaries which are not guarantors of
the Senior Notes. Chesapeake Energy Marketing, Inc. was a non-guarantor
subsidiary for all periods presented. All of our other subsidiaries were
guarantor subsidiaries during all periods presented.
-49-
51
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1999
($ IN THOUSANDS)
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ---------- ----------- ------------ ------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents............................... $ (7,156) $ 20,409 $ 25,405 $ -- $ 38,658
Restricted cash......................................... 192 -- -- -- 192
Accounts receivable..................................... 45,170 18,297 73 (12,475) 51,065
Inventory............................................... 4,183 399 -- -- 4,582
Other................................................... 1,997 700 352 -- 3,049
----------- -------- ----------- -------- -----------
Total Current Assets.............................. 44,386 39,805 25,830 (12,475) 97,546
----------- -------- ----------- -------- -----------
PROPERTY AND EQUIPMENT:
Oil and gas properties.................................. 2,311,633 3,715 -- -- 2,315,348
Unevaluated leasehold................................... 40,008 -- -- -- 40,008
Other property and equipment............................ 29,088 20,521 18,103 -- 67,712
Less: accumulated depreciation, depletion and
amortization.......................................... (1,683,890) (18,205) (1,876) -- (1,703,971)
----------- -------- ----------- -------- -----------
Net Property and Equipment........................ 696,839 6,031 16,227 -- 719,097
----------- -------- ----------- -------- -----------
INVESTMENTS IN SUBSIDIARIES AND INTERCOMPANY ADVANCES..... -- -- (686,097) 686,097 --
----------- -------- ----------- -------- -----------
INVESTMENT IN GOTHIC ENERGY CORPORATION................... 10,000 -- -- -- 10,000
----------- -------- ----------- -------- -----------
OTHER ASSETS.............................................. 6,402 8,409 16,765 (7,686) 23,890
----------- -------- ----------- -------- -----------
TOTAL ASSETS.............................................. $ 757,627 $ 54,245 $ (627,275) $665,936 $ 850,533
=========== ======== =========== ======== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Notes payable and current maturities of long-term
debt.................................................. $ -- $ 763 $ -- $ -- $ 763
Accounts payable and other.............................. 63,194 19,265 17,466 (12,502) 87,423
----------- -------- ----------- -------- -----------
Total Current Liabilities......................... 63,194 20,028 17,466 (12,502) 88,186
----------- -------- ----------- -------- -----------
LONG-TERM DEBT............................................ 43,500 1,437 919,160 -- 964,097
----------- -------- ----------- -------- -----------
REVENUES AND ROYALTIES DUE OTHERS......................... 9,310 -- -- -- 9,310
----------- -------- ----------- -------- -----------
DEFERRED INCOME TAX LIABILITY............................. 6,484 -- -- -- 6,484
----------- -------- ----------- -------- -----------
INTERCOMPANY PAYABLES..................................... 1,356,466 (2,450) (1,354,043) 27 --
----------- -------- ----------- -------- -----------
STOCKHOLDERS' EQUITY (DEFICIT):
Common Stock............................................ 27 1 1,048 (17) 1,059
Other................................................... (721,354) 35,229 (210,906) 678,428 (218,603)
----------- -------- ----------- -------- -----------
(721,327) 35,230 (209,858) 678,411 (217,544)
----------- -------- ----------- -------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)...... $ 757,627 $ 54,245 $ (627,275) $665,936 $ 850,533
=========== ======== =========== ======== ===========
-50-
52
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2000
($ IN THOUSANDS)
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ---------- ----------- ------------ ------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents............................... $ (19,868) $ 7,200 $ 12,668 $ -- $ --
Restricted cash......................................... 3,500 -- -- -- 3,500
Accounts receivable..................................... 91,903 46,903 -- (21,363) 117,443
Deferred income tax asset............................... -- -- 40,819 -- 40,819
Inventory............................................... 3,040 127 -- -- 3,167
Other................................................... 1,997 -- -- -- 1,997
----------- -------- ----------- -------- -----------
Total Current Assets.............................. 80,572 54,230 53,487 (21,363) 166,926
----------- -------- ----------- -------- -----------
PROPERTY AND EQUIPMENT:
Oil and gas properties.................................. 2,590,512 -- -- -- 2,590,512
Unevaluated leasehold................................... 25,685 -- -- -- 25,685
Other property and equipment............................ 30,670 23,246 25,982 -- 79,898
Less: accumulated depreciation, depletion and
amortization.......................................... (1,787,314) (18,153) (2,394) -- (1,807,861)
----------- -------- ----------- -------- -----------
Net Property and Equipment........................ 859,553 5,093 23,588 -- 888,234
----------- -------- ----------- -------- -----------
INVESTMENTS IN SUBSIDIARIES AND INTERCOMPANY ADVANCES..... -- -- (612,832) 612,832 --
----------- -------- ----------- -------- -----------
INVESTMENT IN GOTHIC ENERGY CORPORATION................... -- 9,732 116,702 -- 126,434
----------- -------- ----------- -------- -----------
DEFERRED TAX ASSET........................................ -- -- 229,823 -- 229,823
----------- -------- ----------- -------- -----------
OTHER ASSETS.............................................. 9,890 418 89,516 (70,815) 29,009
----------- -------- ----------- -------- -----------
TOTAL ASSETS.............................................. $ 950,015 $ 69,473 $ (99,716) $520,654 $ 1,440,426
=========== ======== =========== ======== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Notes payable and current maturities of long-term
debt.................................................. $ 836 $ -- $ -- $ -- $ 836
Accounts payable and other.............................. 118,620 49,613 19,090 (25,458) 161,865
----------- -------- ----------- -------- -----------
Total Current Liabilities......................... 119,456 49,613 19,090 (25,458) 162,701
----------- -------- ----------- -------- -----------
LONG-TERM DEBT............................................ 92,321 -- 919,244 (66,720) 944,845
----------- -------- ----------- -------- -----------
REVENUES AND ROYALTIES DUE OTHERS......................... 7,798 -- -- -- 7,798
----------- -------- ----------- -------- -----------
DEFERRED INCOME TAX LIABILITY............................. 11,850 -- -- -- 11,850
----------- -------- ----------- -------- -----------
INTERCOMPANY PAYABLES..................................... 1,351,144 138 (1,351,282) -- --
----------- -------- ----------- -------- -----------
STOCKHOLDERS' EQUITY (DEFICIT):
Common Stock............................................ 26 1 1,569 (18) 1,578
Other................................................... (632,580) 19,721 311,663 612,850 311,654
----------- -------- ----------- -------- -----------
(632,554) 19,722 313,232 612,832 313,232
----------- -------- ----------- -------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)...... $ 950,015 $ 69,473 $ (99,716) $520,654 $ 1,440,426
=========== ======== =========== ======== ===========
-51-
53
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ---------- --------- ------------ ------------
FOR THE YEAR ENDED DECEMBER 31, 1998:
REVENUES:
Oil and gas sales.................................... $ 256,887 $ -- $ -- $ -- $ 256,887
Oil and gas marketing sales.......................... -- 222,849 -- (101,790) 121,059
---------- -------- --------- --------- ----------
Total Revenues....................................... 256,887 222,849 -- (101,790) 377,946
---------- -------- --------- --------- ----------
OPERATING COSTS:
Production expenses and taxes........................ 59,497 -- -- -- 59,497
General and administrative........................... 18,081 1,766 71 -- 19,918
Oil and gas marketing expenses....................... -- 220,798 -- (101,790) 119,008
Impairment of oil and gas properties................. 826,000 -- -- -- 826,000
Impairment of other assets........................... 47,000 8,000 -- -- 55,000
Oil and gas depreciation, depletion and
amortization....................................... 146,644 -- -- -- 146,644
Other depreciation and amortization.................. 5,204 126 2,746 -- 8,076
---------- -------- --------- --------- ----------
Total Operating Costs................................ 1,102,426 230,690 2,817 (101,790) 1,234,143
---------- -------- --------- --------- ----------
INCOME (LOSS) FROM OPERATIONS........................ (845,539) (7,841) (2,817) -- (856,197)
---------- -------- --------- --------- ----------
OTHER INCOME (EXPENSE):
Interest and other income............................ 649 2,259 100,886 (99,868) 3,926
Interest expense..................................... (96,214) (382) (71,521) 99,868 (68,249)
Equity in net earnings of subsidiaries............... -- -- (949,232) 949,232 --
---------- -------- --------- --------- ----------
(95,565) 1,877 (919,867) 949,232 (64,323)
---------- -------- --------- --------- ----------
INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY
ITEM............................................... (941,104) (5,964) (922,684) 949,232 (920,520)
INCOME TAX EXPENSE (BENEFIT)......................... -- -- -- -- --
---------- -------- --------- --------- ----------
NET INCOME (LOSS) BEFORE EXTRAORDINARY ITEM.......... (941,104) (5,964) (922,684) 949,232 (920,520)
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt, net of
applicable income tax............................ (2,164) -- (11,170) -- (13,334)
---------- -------- --------- --------- ----------
NET INCOME (LOSS).................................... $ (943,268) $ (5,964) $(933,854) $ 949,232 $ (933,854)
========== ======== ========= ========= ==========
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ---------- -------- ------------ ------------
FOR THE YEAR ENDED DECEMBER 31, 1999:
REVENUES:
Oil and gas sales..................................... $280,445 $ -- $ -- $ -- $280,445
Oil and gas marketing sales........................... -- 193,900 -- (119,399) 74,501
-------- -------- -------- --------- --------
Total Revenues........................................ 280,445 193,900 -- (119,399) 354,946
-------- -------- -------- --------- --------
OPERATING COSTS:
Production expenses and taxes......................... 59,158 404 -- -- 59,562
General and administrative............................ 12,143 1,251 83 -- 13,477
Oil and gas marketing expenses........................ -- 190,932 -- (119,399) 71,533
Oil and gas depreciation, depletion and
amortization........................................ 94,649 395 -- -- 95,044
Other depreciation and amortization................... 4,474 80 3,256 -- 7,810
-------- -------- -------- --------- --------
Total Operating Costs................................. 170,424 193,062 3,339 (119,399) 247,426
-------- -------- -------- --------- --------
INCOME (LOSS) FROM OPERATIONS......................... 110,021 838 (3,339) -- 107,520
-------- -------- -------- --------- --------
OTHER INCOME (EXPENSE):
Interest and other income............................. 3,257 4,823 84,120 (83,638) 8,562
Interest expense...................................... (82,852) (96) (81,742) 83,638 (81,052)
Equity in net earnings of subsidiaries................ -- -- 34,227 (34,227) --
-------- -------- -------- --------- --------
(79,595) 4,727 36,605 (34,227) (72,490)
-------- -------- -------- --------- --------
INCOME (LOSS) BEFORE INCOME TAXES..................... 30,426 5,565 33,266 (34,227) 35,030
INCOME TAX EXPENSE (BENEFIT).......................... 1,764 -- -- -- 1,764
-------- -------- -------- --------- --------
NET INCOME (LOSS)..................................... $ 28,662 $ 5,565 $ 33,266 $ (34,227) $ 33,266
======== ======== ======== ========= ========
-52-
54
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ IN THOUSANDS)
NON-
GUARANTOR GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ---------- --------- ------------ ------------
FOR THE YEAR ENDED DECEMBER 31, 2000:
REVENUES:
Oil and gas sales.................................... $469,823 $ 347 $ -- $ -- $ 470,170
Oil and gas marketing sales.......................... -- 361,023 -- (203,241) 157,782
-------- -------- --------- --------- ---------
Total Revenues....................................... 469,823 361,370 -- (203,241) 627,952
-------- -------- --------- --------- ---------
OPERATING COSTS:
Production expenses and taxes........................ 74,845 80 -- -- 74,925
General and administrative........................... 11,635 1,218 324 -- 13,177
Oil and gas marketing expenses....................... -- 355,550 -- (203,241) 152,309
Oil and gas depreciation, depletion and
amortization....................................... 101,190 101 -- -- 101,291
Other depreciation and amortization.................. 4,082 80 3,319 -- 7,481
-------- -------- --------- --------- ---------
Total Operating Costs................................ 191,752 357,029 3,643 (203,241) 349,183
-------- -------- --------- --------- ---------
INCOME (LOSS) FROM OPERATIONS........................ 278,071 4,341 (3,643) -- 278,769
-------- -------- --------- --------- ---------
OTHER INCOME (EXPENSE):
Interest and other income............................ 2,736 883 87,910 (87,880) 3,649
Interest expense..................................... (90,170) (35) (83,931) 87,880 (86,256)
Equity in net earnings of subsidiaries............... -- -- 190,234 (190,234) --
-------- -------- --------- --------- ---------
(87,434) 848 194,213 (190,234) (82,607)
-------- -------- --------- --------- ---------
INCOME BEFORE INCOME TAXES........................... 190,637 5,189 190,570 (190,234) 196,162
INCOME TAX EXPENSE (BENEFIT)......................... 5,592 -- (265,000) -- (259,408)
-------- -------- --------- --------- ---------
NET INCOME........................................... $185,045 $ 5,189 $ 455,570 $(190,234) $ 455,570
======== ======== ========= ========= =========
-53-
55
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- --------- ------------ ------------
FOR THE YEAR ENDED DECEMBER 31, 1998:
CASH FLOWS FROM OPERATING
ACTIVITIES.................................... $ 66,960 $(13,137) $(908,416) $ 949,232 $ 94,639
--------- -------- --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties........................ (523,922) -- -- -- (523,922)
Proceeds from sale of assets.................. -- -- 3,600 -- 3,600
Investment in preferred stock of Gothic Energy
Corporation................................. (39,500) -- -- -- (39,500)
Repayment of note receivable.................. 2,000 -- -- -- 2,000
Proceeds from sale of PanEast Petroleum
Corporation................................. -- -- 21,245 -- 21,245
Other additions............................... (2,510) 8,408 (17,371) -- (11,473)
--------- -------- --------- --------- ---------
(563,932) 8,408 7,474 -- (548,050)
--------- -------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings............ -- -- 658,750 -- 658,750
Payments on long-term borrowings.............. -- -- (474,166) -- (474,166)
Cash received from issuance of preferred
stock....................................... -- -- 222,663 -- 222,663
Cash paid for purchase of treasury stock...... -- -- (29,962) -- (29,962)
Dividends paid on common stock and preferred
stock....................................... -- -- (13,642) -- (13,642)
Exercise of stock options..................... -- -- 154 -- 154
Intercompany advances, net.................... 476,663 6,035 466,534 (949,232) --
--------- -------- --------- --------- ---------
476,663 6,035 830,331 (949,232) 363,797
--------- -------- --------- --------- ---------
EFFECT OF EXCHANGE RATE CHANGES
ON CASH....................................... (4,726) -- -- -- (4,726)
--------- -------- --------- --------- ---------
Net increase (decrease) in cash and cash
equivalents................................... (25,035) 1,306 (70,611) -- (94,340)
Cash, beginning of period....................... (284) 13,694 110,450 -- 123,860
--------- -------- --------- --------- ---------
Cash, end of period............................. $ (25,319) $ 15,000 $ 39,839 $ -- $ 29,520
========= ======== ========= ========= =========
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- --------- ------------ ------------
FOR THE YEAR ENDED DECEMBER 31, 1999:
CASH FLOWS FROM OPERATING
ACTIVITIES.................................... $ 135,303 $ 7,193 $ 36,753 $(34,227) $ 145,022
--------- -------- --------- -------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net................... (159,888) 2,362 -- -- (157,526)
Proceeds from sale of assets.................. 2,082 3,448 -- -- 5,530
Other investments............................. (480) (250) -- -- (730)
Other additions............................... (5,777) (72) (1,198) -- (7,047)
--------- -------- --------- -------- ---------
(164,063) 5,488 (1,198) -- (159,773)
--------- -------- --------- -------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings............ 116,500 -- -- -- 116,500
Payments on long-term borrowings.............. (98,000) -- -- -- (98,000)
Cash paid for purchase of preferred stock..... -- (53) -- -- (53)
Exercise of stock options..................... -- -- 520 -- 520
Intercompany advances, net.................... 15,501 781 (50,509) 34,227 --
--------- -------- --------- -------- ---------
34,001 728 (49,989) 34,227 18,967
--------- -------- --------- -------- ---------
EFFECT OF EXCHANGE RATE CHANGES ON CASH......... 4,922 -- -- -- 4,922
--------- -------- --------- -------- ---------
Net increase (decrease) in cash and cash
equivalents................................... 10,163 13,409 (14,434) -- 9,138
Cash, beginning of period....................... (17,319) 7,000 39,839 -- 29,520
--------- -------- --------- -------- ---------
Cash, end of period............................. $ (7,156) $ 20,409 $ 25,405 $ -- $ 38,658
========= ======== ========= ======== =========
-54-
56
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ IN THOUSANDS)
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- --------- ------------ ------------
FOR THE YEAR ENDED DECEMBER 31, 2000:
CASH FLOWS FROM OPERATING
ACTIVITIES.................................... $ 320,002 $ (9,627) $ 194,499 $(190,234) $ 314,640
--------- -------- --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties, net................... (267,674) 1,515 -- -- (266,159)
Proceeds from sale of assets.................. 782 16 271 -- 1,069
Other investments............................. (8,019) -- (2,000) -- (10,019)
Investment in Gothic Energy Corporation....... -- (33,076) (3,617) -- (36,693)
Other additions............................... (4,453) (2,740) (11,041) -- (18,234)
--------- -------- --------- --------- ---------
(279,364) (34,285) (16,387) -- (330,036)
--------- -------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings............ 244,000 -- -- -- 244,000
Payments on long-term borrowings.............. (262,500) -- -- -- (262,500)
Cash paid for redemption of preferred stock... -- -- (8,269) -- (8,269)
Cash received on make whole provision......... -- 6,109 974 -- 7,083
Cash dividends paid on preferred stock........ -- -- (4,645) -- (4,645)
Exercise of stock options..................... -- -- 1,398 -- 1,398
Intercompany advances, net.................... (34,521) 24,594 (180,307) 190,234 --
--------- -------- --------- --------- ---------
(53,021) 30,703 (190,849) 190,234 (22,933)
--------- -------- --------- --------- ---------
EFFECT OF EXCHANGE RATE CHANGES ON CASH......... (329) -- -- -- (329)
--------- -------- --------- --------- ---------
Net increase (decrease) in cash and cash
equivalents................................... (12,712) (13,209) (12,737) -- (38,658)
Cash, beginning of period....................... (7,156) 20,409 25,405 -- 38,658
--------- -------- --------- --------- ---------
Cash, end of period............................. $ (19,868) $ 7,200 $ 12,668 $ -- $ --
========= ======== ========= ========= =========
-55-
57
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
($ IN THOUSANDS)
GUARANTOR NON-GUARANTOR
SUBSIDIARIES SUBSIDIARY PARENT ELIMINATIONS CONSOLIDATED
------------ ------------- --------- ------------ ------------
FOR THE YEAR ENDED DECEMBER 31, 1998:
Net income (loss)............................. $(943,268) $(5,964) $(933,854) $ 949,232 $(933,854)
Other comprehensive income (loss) -- foreign
currency translation........................ (4,689) -- -- -- (4,689)
--------- ------- --------- --------- ---------
Comprehensive income (loss)................... $(947,957) $(5,964) $(933,854) $ 949,232 $(938,543)
========= ======= ========= ========= =========
FOR THE YEAR ENDED DECEMBER 31, 1999:
Net income (loss)............................. $ 28,662 $ 5,565 $ 33,266 $ (34,227) $ 33,266
Other comprehensive income (loss) -- foreign
currency translation........................ 4,922 -- -- -- 4,922
--------- ------- --------- --------- ---------
Comprehensive income (loss)................... $ 33,584 $ 5,565 $ 33,266 $ (34,227) $ 38,188
========= ======= ========= ========= =========
FOR THE YEAR ENDED DECEMBER 31, 2000:
Net income.................................... $ 185,045 $ 5,189 $ 455,570 $(190,234) $ 455,570
Other comprehensive income (loss) -- foreign
currency translation........................ (4,097) -- -- -- (4,097)
--------- ------- --------- --------- ---------
Comprehensive income.......................... $ 180,948 $ 5,189 $ 455,570 $(190,234) $ 451,473
========= ======= ========= ========= =========
-56-
58
3. NOTES PAYABLE AND LONG-TERM DEBT
Notes payable and long-term debt consist of the following:
DECEMBER 31,
--------------------
1999 2000
-------- --------
($ IN THOUSANDS)
7.875% Senior Notes (see note 2)............................ $150,000 $150,000
Discount on 7.875% Senior notes............................. (73) (55)
8.5% Senior Notes (see note 2).............................. 150,000 150,000
Discount on 8.5% Senior notes............................... (715) (657)
9.125% Senior Notes (see note 2)............................ 120,000 120,000
Discount on 9.125% Senior notes............................. (52) (44)
9.625% Senior Notes (see note 2)............................ 500,000 500,000
Note payable................................................ 2,200 1,437
Revolving bank credit facility.............................. 43,500 25,000
-------- --------
Total notes payable and long-term debt...................... 964,860 945,681
Less -- current maturities.................................. (763) (836)
-------- --------
Notes payable and long-term debt, net of current
maturities................................................ $964,097 $944,845
======== ========
Chesapeake has a $100 million revolving bank credit facility which matures
in July 2002, with a committed borrowing base of $100 million. As of December
31, 2000, we had borrowed $25 million under the revolving bank credit facility
and had $31.5 million of the facility securing various letters of credit.
Borrowings under the facility are collateralized by certain producing oil and
gas properties and bear interest at a variable rate, which was 9.3% per annum as
of December 31, 2000. Interest is payable quarterly calculated at .50% to 1.25%,
depending on utilization, plus the higher of (a) the Union Bank of California
reference rate or (b) the federal funds rate plus .50% per year. We may elect to
convert a portion of our borrowings to interest calculated under a London
Interbank Offered Rate ("LIBOR") plus 2.00% to 2.75%, depending on utilization.
We are required to pay a commitment fee on the unused portion of the borrowing
base equal to 0.375% per annum due quarterly.
During 2000, we obtained a standby commitment for a $275 million credit
facility, consisting of a $175 million term loan and a $100 million revolving
credit facility which would have replaced our existing revolving credit
facility. The term loan was available to repurchase any of Gothic Production
Corporation's 11.125% senior secured notes tendered following the closing of the
Gothic acquisition pursuant to a change-of-control offer to purchase. In
February 2001, we purchased $1.0 million of notes tendered for 101% of such
amount. We did not use the standby credit facility and the commitment terminated
on February 23, 2001. Chesapeake incurred $3.2 million of costs for the standby
facility.
The aggregate scheduled maturities of notes payable and long-term debt for
the next five fiscal years ending December 31, 2005, and thereafter were as
follows as of December 31, 2000 ($ in thousands):
2001........................................................ $ 836
2002........................................................ 25,601
2003........................................................ --
2004........................................................ 149,945
2005........................................................ 500,000
After 2005.................................................. 269,299
--------
$945,681
========
4. CONTINGENCIES AND COMMITMENTS
West Panhandle Field Cessation Cases. One of our subsidiaries, Chesapeake
Panhandle Limited Partnership ("CP") (f/k/a MC Panhandle, Inc.), and two
subsidiaries of Kinder Morgan, Inc. have been defendants in 13 lawsuits filed
between June 1997 and January 1999 by royalty owners seeking the cancellation of
oil and gas leases in the West Panhandle Field in Texas. MC Panhandle, Inc.,
which we acquired in April 1998, has owned the leases since January 1, 1997. The
co-defendants are prior lessees. The plaintiffs in these cases have claimed the
leases terminated upon the cessation of production for various periods,
primarily during the 1960s. In addition, the
-57-
59
plaintiffs have sought to recover conversion damages, exemplary damages,
attorneys' fees and interest. The defendants have asserted that any cessation of
production was excused and have pled affirmative defenses of limitations,
waiver, temporary estoppel, laches and title by adverse possession. Four of the
13 cases have been tried, and there have been appellate decisions in three of
them. In January 2001, the principal plaintiffs in eight of ten cases tried or
pending in the District Court of Moore County, Texas, 69th Judicial District
agreed to settle their claims. We do not consider our portion of the settlement
consideration material to our financial condition or results of operations.
There are five related West Panhandle cessation cases which continue to be
pending, two in the District Court of Moore County, Texas, 69th Judicial
District, one in the District Court of Carson County, Texas, 100th Judicial
District, and two in the U.S. District Court, Northern District of Texas,
Amarillo Division. In one of the Moore County cases, CP and the other defendants
have appealed a January 2000 judgment notwithstanding verdict in favor of
plaintiffs. In addition to quieting title to the lease (including existing gas
wells and all attached equipment) in plaintiffs, the court awarded actual
damages against CP in the amount of $716,400 and exemplary damages in the amount
of $25,000. The court further awarded, jointly and severally from all
defendants, $160,000 in attorneys' fees and interest and court costs. We will
have additional cash needs to fund our future operations. If we do not have cash
available, or borrowings under our credit facilities have been utilized when our
cash need arises, we would be forced to seek additional debt or equity financing
or to forego the opportunity. In the event that we determine to seek additional
debt or equity financing, there can be no assurance that any such financing will
be available, on commercially reasonable terms or at all, or permitted by the
terms of our existing indebtedness. In the other Moore County, Texas case, in
June 1999, the court granted plaintiffs' motion for summary judgment in part,
finding that the lease had terminated due to the cessation of production,
subject to the defendants' affirmative defenses. In February 2001, the court
granted plaintiffs' motion for summary judgment on defendants' affirmative
defenses but reversed its ruling that the lease had terminated as a matter of
law. In one of the U.S. District Court cases, after a trial in May 1999, the
jury found plaintiffs' claims were barred by the payment of shut-in royalties,
laches and revivor. Plaintiffs have moved for a new trial. There are motions
pending in the remaining two cases and no trial date has been set.
We have previously established an accrued liability we believe will be
sufficient to cover the estimated costs of litigation for each of the pending
cases and the settlement consideration under the terms of the settlement
agreement mentioned above. Because of the inconsistent verdicts reached by the
juries in the four cases tried to date and because the amount of damages sought
is not specified in all of the pending cases, the outcome of any future trials
and the amount of damages that might ultimately be awarded could differ from
management's estimates. CP and the other defendants intend to vigorously defend
against the plaintiffs' claims.
Chesapeake is currently involved in various other routine disputes
incidental to its business operations. While it is not possible to determine the
ultimate disposition of these matters, management, after consultation with legal
counsel, is of the opinion that the final resolution of all such currently
pending or threatened litigation is not likely to have a material adverse effect
on the consolidated financial position or results of operations of Chesapeake.
Chesapeake has employment contracts with its chief executive officer, chief
operating officer and chief financial officer and various other senior
management personnel which provide for annual base salaries, bonus compensation
and various benefits. The contracts provide for the continuation of salary and
benefits for varying terms in the event of termination of employment without
cause. The agreements with the chief executive officer and chief operating
officer have terms of five years commencing July 1, 2000. The term of each
agreement is automatically extended for one additional year on each June 30
unless one of the parties provides 30 days notice of non-extension. The
agreements with the chief financial officer and other senior managers expire on
June 30, 2003.
Due to the nature of the oil and gas business, Chesapeake and its
subsidiaries are exposed to possible environmental risks. Chesapeake has
implemented various policies and procedures to avoid environmental contamination
and risks from environmental contamination. Chesapeake is not aware of any
potential material environmental issues or claims.
-58-
60
5. INCOME TAXES
The components of the income tax provision (benefit) for each of the
periods are as follows:
YEARS ENDED DECEMBER 31,
-----------------------------
1998 1999 2000
----- ------ ---------
($ IN THOUSANDS)
Current..................................................... $ -- $ -- $ 1,800
Deferred:
United States............................................. -- -- (266,800)
Foreign................................................... -- 1,764 5,592
----- ------ ---------
Total............................................... $ -- $1,764 $(259,408)
===== ====== =========
The effective income tax expense (benefit) differed from the computed
"expected" federal income tax expense (benefit) on earnings before income taxes
for the following reasons:
YEARS ENDED DECEMBER 31,
---------------------------------
1998 1999 2000
--------- ------- ---------
($ IN THOUSANDS)
Computed "expected" income tax provision (benefit).......... $(322,182) $12,720 $ 70,168
Tax percentage depletion.................................... (430) (240) (191)
Change in valuation allowance............................... 380,969 (10,956) (329,516)
State income taxes and other................................ (58,357) 240 131
--------- ------- ---------
$ -- $ 1,764 $(259,408)
========= ======= =========
Deferred income taxes are provided to reflect temporary differences in the
basis of net assets for income tax and financial reporting purposes. The
tax-effected temporary differences and tax loss carryforwards which comprise
deferred taxes are as follows:
YEARS ENDED
DECEMBER 31,
---------------------
1999 2000
--------- --------
($ IN THOUSANDS)
Deferred tax liabilities:
Acquisition, exploration and development costs and related
depreciation, depletion and amortization.................. $ (6,484) $(11,850)
--------- --------
Deferred tax assets:
Acquisition, exploration and development costs and related
depreciation, depletion and amortization.................. 211,961 50,567
Net operating loss carryforwards............................ 228,279 216,332
Percentage depletion carryforward........................... 1,776 1,851
Alternative minimum tax credits............................. -- 1,892
--------- --------
Deferred tax asset.......................................... 442,016 270,642
--------- --------
Net deferred tax asset (liability).......................... 435,532 258,792
Less: Valuation allowance................................... (442,016) --
--------- --------
Total deferred tax asset (liability)........................ $ (6,484) $258,792
========= ========
Reflected in accompanying balance sheets as:
Current income tax asset.................................... -- 40,819
Deferred income tax asset................................... -- 229,823
Deferred income tax liability............................... (6,484) (11,850)
--------- --------
$ (6,484) $258,792
========= ========
At December 31, 2000, we classified $41 million of our deferred tax assets
as current to recognize the portion of the NOL carryover that is expected to be
utilized to reduce taxable income in 2001.
During 2000, we revised our estimate of the 1999 U.S. net deferred tax
asset from $442 million to $330 million as a result of further evaluation of the
income tax basis of several acquisitions. Since there was a full valuation
allowance against the deferred tax asset, this revision had no impact on net
income.
-59-
61
In the fourth quarter of 2000, we eliminated our valuation allowance
resulting in the recognition of a $265 million income tax benefit. This resulted
in an increase to 2000 net income of $265 million, or $1.75 per diluted share.
Based upon recent results of operations and anticipated improvement in
Chesapeake's outlook for sustained profitability, we believe that it is more
likely than not that we will generate sufficient future taxable income to
realize the tax benefits associated with our NOL carryforwards prior to their
expiration.
At December 31, 2000, Chesapeake had U.S. regular tax net operating loss
carryforwards of approximately $567 million and a U.S. alternative minimum tax
net operating loss carryforward of approximately $301 million. The U.S. loss
carryforward amounts will expire during the years 2009 through 2019. We also had
a U.S. percentage depletion carryforward of approximately $5 million at December
31, 2000, which is available to offset Chesapeake's future U.S. federal income
and has no expiration date. A summary of our NOLs follows:
NOL AMT NOL
-------- --------
($ IN THOUSANDS)
Expiration Date:
December 31, 2009........................................... $ 19,099 $ --
December 31, 2010........................................... 41,494 --
December 31, 2011........................................... 168,186 17,559
December 31, 2012........................................... 48,229 --
December 31, 2018........................................... 154,642 146,840
December 31, 2019........................................... 135,697 137,094
-------- --------
Total................................................... $567,347 $301,493
======== ========
In the event of an ownership change, Section 382 of the Internal Revenue
Code imposes an annual limitation on the amount of a corporation's taxable
income that can be offset by these carryforwards. The limitation is generally
equal to the product of (i) the fair market value of the equity of the company
multiplied by (ii) a percentage approximately equivalent to the yield on
long-term tax exempt bonds during the month in which an ownership change occurs.
Of the $567 million NOLs and $301 million AMT NOLs, the utilization of $254
million and the utilization of $25 million, respectively, are subject to annual
limitations under Section 382. Therefore, $313 million of NOLs and $276 million
of the AMT NOLs are not subject to the limitation. The utilization of $254
million of the NOLs and $25 million of the AMT NOLs subject to the Section 382
limitation are both limited to approximately $26 million each taxable year.
6. RELATED PARTY TRANSACTIONS
Certain directors, shareholders and employees of Chesapeake have acquired
working interests in certain of our oil and gas properties. The owners of such
working interests are required to pay their proportionate share of all costs. As
of December 31, 1999 and 2000, we had accounts receivable from related parties,
primarily related to such participation, of $4.6 million and $4.4 million,
respectively.
As of December 31, 1998, the chief executive officer and chief operating
officer of Chesapeake had notes payable to Chesapeake Energy Marketing, Inc. in
the principal amount of $9.9 million. In November 1999, the chief executive
officer and the chief operating officer tendered 2,320,107 shares of Chesapeake
common stock in full satisfaction of the notes, which had a combined outstanding
balance of $7.6 million. The common stock was valued at $3.29 per share, which
was the market value of the stock at the time of the transaction.
During 1998, 1999 and 2000, we incurred legal expenses of $493,000,
$398,000 and $439,000, respectively, for legal services provided by a law firm
of which a director is a member.
7. EMPLOYEE BENEFIT PLANS
We maintain the Chesapeake Energy Corporation Savings and Incentive Stock
Bonus Plan, a 401(k) profit sharing plan. Eligible employees may make voluntary
contributions to the plan which Chesapeake matches up to 10% of the employee's
annual salary with Chesapeake's common stock purchased in the open-market. The
amount of employee contribution is limited as specified in the plan. We may, at
our discretion, make additional contributions to the plan. We contributed
$1,359,000, $1,163,000 and $1,490,000 to the plan during 1998, 1999 and 2000,
respectively.
-60-
62
8. MAJOR CUSTOMERS AND SEGMENT INFORMATION
Sales to individual customers constituting 10% or more of total oil and gas
sales were as follows:
PERCENT OF
YEAR ENDED DECEMBER 31, AMOUNT OIL AND GAS SALES
------------------------------------------------------------------------ ---------------- -----------------
($ IN THOUSANDS)
1998 Koch Oil Company............................................ $30,564 12%
Aquila Southwest Pipeline Corporation....................... $28,946 11%
1999 Aquila Southwest Pipeline Corporation....................... $31,505 11%
2000 Aquila Southwest Pipeline Corporation....................... $54,931 12%
Management believes that the loss of any of the above customers would not
have a material impact on our results of operations or our financial position.
Chesapeake has two reportable segments under SFAS No. 131 "Disclosures
about Segments of an Enterprise and Related Information" consisting of
exploration and production, and marketing. The reportable segment information
can be derived from note 2 as Chesapeake Energy Marketing, Inc., which is our
marketing segment, is the only non-guarantor subsidiary for all periods
presented. The geographic distribution of our revenue, operating income and
long-lived assets is summarized below:
UNITED
STATES CANADA COMBINED
---------- -------- ----------
($ IN THOUSANDS)
1998:
Revenue..................................................... $ 369,968 $ 7,978 $ 377,946
Operating income (loss)..................................... (842,798) (13,399) (856,197)
Long-lived assets........................................... 617,431 77,185 694,616
1999:
Revenue..................................................... $ 340,969 $ 13,977 $ 354,946
Operating income (loss)..................................... 103,188 4,332 107,520
Long-lived assets........................................... 648,841 104,146 752,987
2000:
Revenue..................................................... $ 594,126 $ 33,826 $ 627,952
Operating income (loss)..................................... 259,828 18,941 278,769
Long-lived assets........................................... 1,163,952 109,548 1,273,500
9. STOCKHOLDERS' EQUITY AND STOCK-BASED COMPENSATION
During 1998, our Board of Directors approved the expenditure of up to $30
million to purchase our outstanding common stock. During 1998, we purchased 8.5
million shares of common stock for an aggregate amount of $30 million pursuant
to such authorization.
On April 28, 1998, we acquired by merger the Mid-Continent operations of
DLB Oil & Gas, Inc. for $17.5 million in cash, 5 million shares of our common
stock, and the assumption of $90 million in outstanding debt and working capital
obligations.
On April 22, 1998, we issued $230 million (4.6 million shares) of our 7%
cumulative convertible preferred stock, $50 per share liquidation preference,
resulting in net proceeds to us of $223 million.
On March 10, 1998, we acquired Hugoton Energy Corporation pursuant to a
merger by issuing 25.8 million shares of our common stock in exchange for 100%
of Hugoton's common stock.
In November 1999, the chief executive officer and the chief operating
officer of Chesapeake tendered 2,320,107 shares of Chesapeake common stock in
full satisfaction of two notes payable to Chesapeake Energy Marketing, Inc. with
a combined outstanding balance of $7.6 million. See note 6.
During 2000, Chesapeake entered into a number of unsolicited transactions
whereby we issued 43.4 million shares of our common stock, plus a cash payment
of $8.3 million, in exchange for 3,972,363 shares of our preferred stock. This
reduced the liquidation amount of preferred stock outstanding by $198.6 million
to $31.2 million, and reduced the amount of preferred dividends in arrears by
$22.9 million.
-61-
63
During 2000, Chesapeake Energy Marketing, Inc. purchased 99.8% of Gothic
Energy Corporation's $104 million 14.125% Series B senior secured discount notes
for total consideration of $80.8 million, comprised of $17.2 million in cash and
$63.6 million of Chesapeake common stock (8,875,775 shares valued at $7.16 per
share), as adjusted for make-whole provisions. Chesapeake Energy Marketing, Inc.
received $6.1 million in cash and $7.2 million of Chesapeake common stock
(982,562 shares) from the sellers of Gothic notes pursuant to make-whole
provisions included in the purchase agreements. These provisions required
payments to be made by the sellers to us or additional payments to be made by us
to the sellers, depending upon changes in market value of our common stock
during a specified period pending registration of our common stock issued to the
sellers of Gothic notes.
In 2000, Chesapeake purchased $31.6 million of the $235 million of 11.125%
senior secured notes issued by Gothic Production Corporation for total
consideration of $34.8 million consisting of $11.5 million in cash and $23.3
million of Chesapeake common stock (3,694,939 shares valued at $6.30 per share),
as adjusted for make-whole provisions as described above. Through the make-whole
provisions, Chesapeake received cash of $1.0 million.
Stock Option Plans
Chesapeake's 1992 Incentive Stock Option Plan terminated on December 16,
1994. Until then, we granted incentive stock options to purchase common stock
under the ISO Plan to employees. Subject to any adjustment as provided by the
ISO Plan, the aggregate number of shares which may be issued and sold may not
exceed 3,762,000 shares. The maximum period for exercise of an option may not be
more than ten years (or five years for an optionee who owns more than 10% of the
common stock) from the date of grant, and the exercise price may not be less
than the fair market value of the shares underlying the options on the date of
grant (or 110% of such value for an optionee who owns more than 10% of the
common stock). Options granted become exercisable at dates determined by the
Stock Option Committee of the Board of Directors.
Under our 1992 Nonstatutory Stock Option Plan, non-qualified options to
purchase common stock may be granted only to directors and consultants of
Chesapeake. Subject to any adjustment as provided by this plan, the aggregate
number of shares which may be issued and sold may not exceed 3,132,000 shares.
The maximum period for exercise of an option may not be more than ten years from
the date of grant, and the exercise price may not be less than the fair market
value of the shares underlying the options on the date of grant. Options granted
become exercisable at dates determined by the Stock Option Committee of the
Board of Directors. This plan also contains a formula award provision pursuant
to which each director who is not an executive officer receives every quarter a
ten-year immediately exercisable option to purchase 7,500 shares of common stock
at an option price equal to the fair market value of the shares on the date of
grant. The amount of the award was changed from 20,000 shares to 15,000 shares
per year in 1998, to 25,000 shares per year in 1999 and to 30,000 shares per
year in 2000. No options can be granted under this plan after December 10, 2002.
Under Chesapeake's 1994 Stock Option Plan, and our 1996 Stock Option Plan,
incentive and nonqualified stock options to purchase Chesapeake common stock may
be granted to employees and consultants of Chesapeake. Subject to any adjustment
as provided by the respective plans, the aggregate number of shares which may be
issued and sold may not exceed 4,886,910 shares under the 1994 Plan and
6,000,000 shares under the 1996 Plan. The maximum period for exercise of an
option may not be more than ten years from the date of grant and the exercise
price of nonqualified stock options may not be less than par value and, under
the 1996 Plan, 85% of the fair market value of the shares underlying the options
on the date of grant. Options granted become exercisable at dates determined by
the Stock Option Committee of the Board of Directors. No options can be granted
under the 1994 Plan after October 17, 2004 or under the 1996 Plan after October
14, 2006.
Under Chesapeake's 1999 Stock Option Plan, nonqualified stock options to
purchase Chesapeake common stock may be granted to employees and consultants of
Chesapeake. Subject to any adjustment as provided by this plan, the aggregate
number of shares which may be issued and sold may not exceed 3,000,000 shares.
The maximum period for exercise of an option may not be more than ten years from
the date of grant and the exercise price may not be less than the fair market
value of the shares underlying the options on the date of grant; provided,
however, nonqualified stock options not exceeding 10% of the options issuable
under this plan may be granted at an exercise price which is not less than 85%
of the grant date fair market value. Options granted become exercisable at
-62-
64
dates determined by the Stock Option Committee of the Board of Directors. No
options can be granted under this plan after March 4, 2009.
Under Chesapeake's 2000 Employee Stock Option Plan, nonqualified stock
options to purchase Chesapeake common stock may be granted to employees of
Chesapeake. Subject to any adjustment as provided by the plan, the aggregate
number of shares which may be issued and sold may not exceed 3,000,000 shares.
The maximum period for exercise of an option may not be more than ten years from
the date of grant and the exercise price may not be less than the fair market
value of the shares underlying the options on the date of grant; provided,
however, nonqualified stock options not exceeding 10% of the options issuable
under this plan may be granted at an exercise price which is not less than 85%
of the grant date fair market value. Options granted become exercisable at dates
determined by the Stock Option Committee of the Board of Directors. No options
can be granted under this plan after April 25, 2010.
Under Chesapeake's 2000 Executive Officer Stock Option Plan, nonqualified
stock options to purchase Chesapeake common stock may be granted to executive
officers of Chesapeake. Subject to any adjustment as provided by the plan, the
aggregate number of shares which may be issued and sold may not exceed 2,500,000
shares and must represent issued shares which have been reacquired by
Chesapeake. The maximum period for exercise of an option may not be more than
ten years from the date of grant and the exercise price may not be less than the
fair market value of the shares underlying the options on the date of grant;
provided, however, nonqualified stock options not exceeding 10% of the options
issuable under this plan may be granted at an exercise price which is not less
than 85% of the grant date fair market value. Options granted become exercisable
at dates determined by the Stock Option Committee of the Board of Directors. No
options can be granted under this plan after April 25, 2010.
Chesapeake has elected to follow APB No. 25, Accounting for Stock Issued to
Employees and related interpretations in accounting for its employee stock
options. Under APB No. 25, compensation expense is recognized for the difference
between the option price and market value on the measurement date. In March
2000, the Financial Accounting Standards Board issued FASB Interpretation No. 44
which provided clarification regarding the application of APB No. 25. FIN 44
specifically addressed the accounting consequence of various modifications to
the terms of a previously granted fixed stock option. Compensation expense of
$238,000 was recognized in 2000 as a result of modifications that were made
during the year ended December 31, 2000. No compensation expense has been
recognized for newly issued stock options in 1998, 1999 or 2000 because the
exercise price of the stock options granted under the plans equaled the market
price of the underlying stock on the date of grant.
Pro forma information regarding net income and earnings per share is
required by SFAS No. 123 and has been determined as if we had accounted for our
employee stock options under the fair value method of the statement. The fair
value for these options was estimated at the date of grant using a Black-Scholes
option pricing model with the following weighted-average assumptions for 1998,
1999 and 2000, respectively: interest rates (zero-coupon U.S. government issues
with a remaining life equal to the expected term of the options) of 5.20%, 5.88%
and 6.32%; dividend yields of 0.0%, 0.0% and 0.0%; volatility factors of the
expected market price of our common stock of .96, .82, and .73; and
weighted-average expected life of the options of five years.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because our employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options.
-63-
65
Chesapeake's pro forma information follows:
YEARS ENDED DECEMBER 31,
-------------------------------------------
1998 1999 2000
---------- -------- ---------
($ IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Net Income (Loss)
As reported............................................... $(933,854) $33,266 $455,570
Pro forma................................................. (948,014) 24,802 444,865
Basic Earnings (Loss) per Share
As reported............................................... $ (9.97) $ 0.17 $ 3.52
Pro forma................................................. (10.12) 0.08 3.43
Diluted Earnings (Loss) per Share
As reported............................................... $ (9.97) $ 0.16 $ 3.01
Pro forma................................................. (10.12) 0.08 2.94
For purposes of the pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period, which is four
years. Because our stock options vest over four years and additional awards are
typically made each year, the above pro forma disclosures are not likely to be
representative of the effects on pro forma net income for future years. A
summary of our stock option activity and related information follows:
YEARS ENDED DECEMBER 31,
----------------------------------------------------------------------------------------
1998 1999 2000
---------------------------- --------------------------- ---------------------------
WEIGHTED-AVG WEIGHTED-AVG WEIGHTED-AVG
OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE OPTIONS EXERCISE PRICE
----------- -------------- ---------- -------------- ---------- --------------
Outstanding Beginning of Period........ 8,330,381 $5.49 11,260,375 $1.86 12,858,429 $1.76
Granted................................ 14,580,063 2.78 3,210,493 1.11 8,143,280 4.08
Exercised.............................. (108,761) 1.35 (622,120) 0.99 (2,177,644) 1.21
Cancelled/Forfeited.................... (11,541,308) 5.64 (990,319) 1.87 (424,903) 2.47
----------- ----- ---------- ----- ---------- -----
Outstanding End of Period.............. 11,260,375 $1.86 12,858,429 $1.76 18,399,162 $2.83
----------- ----- ---------- ----- ---------- -----
Exercisable End of Period.............. 3,535,126 $2.99 5,040,302 $2.66 5,422,884 $2.61
----------- ----- ---------- ----- ---------- -----
Shares Authorized for Future Grants.... 1,761,359 2,560,687 588,435
----------- ---------- ----------
Fair Value of Options Granted During
the Period........................... $2.34 $0.77 $2.63
----- ----- -----
The following table summarizes information about stock options outstanding
at December 31, 2000:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------------------- ----------------------------
NUMBER WEIGHTED-AVG. NUMBER
RANGE OF OUTSTANDING REMAINING WEIGHTED-AVG. EXERCISABLE WEIGHTED-AVG.
EXERCISE PRICES @ 12/31/00 CONTRACTUAL LIFE EXERCISE PRICE @ 12/31/00 EXERCISE PRICE
--------------- ----------- ---------------- -------------- ----------- --------------
$0.08-$0.78 694,282 3.04 $0.63 694,282 $0.63
0.94-1.00 2,090,445 8.09 0.94 312,258 0.95
1.13-2.06 5,574,715 7.36 1.15 2,341,978 1.17
2.25-2.25 2,346,300 8.95 2.25 46,250 2.25
2.25-3.81 1,341,275 4.15 2.50 1,307,405 2.49
4.00-4.00 2,629,000 9.31 4.00 31,250 4.00
4.06-5.50 97,569 7.26 4.75 62,336 4.91
5.56-5.92 3,041,663 9.74 5.57 91,313 5.81
6.13-8.75 439,663 5.66 7.09 398,187 7.10
10.69-30.63 144,250 5.43 25.14 137,625 25.66
---------- ---- ----- --------- -----
$0.08-$30.63 18,399,162 7.86 $2.83 5,422,884 $2.61
========== =========
The exercise of certain stock options results in state and federal income
tax benefits to us related to the difference between the market price of the
common stock at the date of disposition and the option price. During 2000, we
recognized a tax benefit of $3.8 million, which was recorded as adjustments to
additional paid-in capital and deferred income taxes with respect to such
benefits. There was no similar tax benefit in 1998 or 1999.
-64-
66
Shareholder Rights Plan
Chesapeake maintains a shareholder rights plan designed to deter coercive
or unfair takeover tactics, to prevent a person or group from gaining control of
Chesapeake without offering fair value to all shareholders and to deter other
abusive takeover tactics which are not in the best interest of shareholders.
Under the terms of the plan, each share of common stock is accompanied by
one right, which given certain acquisition and business combination criteria,
entitles the shareholder to purchase from Chesapeake one one-thousandth of a
newly issued share of Series A preferred stock at a price of $25.00, subject to
adjustment by Chesapeake.
The rights become exercisable 10 days after Chesapeake learns that an
acquiring person (as defined in the plan) has acquired 15% or more of the
outstanding common stock of Chesapeake or 10 business days after the
commencement of a tender offer which would result in a person owning 15% or more
of such shares. Chesapeake may redeem the rights for $0.01 per right within ten
days following the time Chesapeake learns that a person has become an acquiring
person. The rights will expire on July 27, 2008, unless redeemed earlier by
Chesapeake.
10. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
Chesapeake has only limited involvement with derivative financial
instruments, as defined in Statement of Financial Accounting Standards No. 119
"Disclosure About Derivative Financial Instruments and Fair Value of Financial
Instruments", and does not use them for trading purposes. Our primary objective
is to hedge a portion of our exposure to price volatility from producing crude
oil and natural gas. These arrangements may expose us to credit risk from our
counterparties and to basis risk. We do not expect that the counterparties will
fail to meet their obligations given their high credit ratings.
Hedging Activities
Periodically Chesapeake utilizes hedging strategies to hedge the price of a
portion of its future oil and gas production. These strategies include:
- swap arrangements that establish an index-related price above which we
pay the counterparty and below which we are paid by the counterparty
(counterparty payments in some contracts are subject to a cap),
- the purchase of index-related puts that provide for a "floor" price
below which the counterparty pays the amount by which the price of the
commodity is below the contracted floor,
- the sale of index-related calls that provide for a "ceiling" price
above which we pay the counterparty the amount by which the price of
the commodity is above the contracted ceiling,
- basis protection swaps, which are arrangements that guarantee the
price differential of oil or gas from a specified delivery point or
points, and
- collar arrangements that establish an index-related price below which
the counterparty pays us and a separate index-related price above
which we pay the counterparty.
Commodity markets are volatile, and as a result, our hedging activity is
dynamic. As market conditions warrant, we may elect to settle a hedging
transaction prior to its scheduled maturity date and, as a result, realize a
gain or loss on the transaction.
Results from commodity hedging transactions are reflected in oil and gas
sales to the extent related to our oil and gas production. We only enter into
commodity hedging transactions related to our oil and gas production volumes or
physical purchase or sale commitments of our marketing subsidiary. Gains or
losses on crude oil and natural gas hedging transactions are recognized as price
adjustments in the months of related production.
-65-
67
As of December 31, 2000, we had the following open natural gas swap
arrangements designed to hedge a portion of our domestic gas production for
periods after December 2000:
NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
------ --------- ------------
January 2001................................................ 4,960,000 $6.03
February 2001............................................... 5,320,000 6.12
March 2001.................................................. 4,650,000 5.11
April 2001.................................................. 5,100,000 4.79
May 2001.................................................... 5,270,000 4.63
June 2001................................................... 3,900,000 4.61
July 2001................................................... 4,030,000 4.59
August 2001................................................. 4,030,000 4.58
September 2001.............................................. 3,900,000 4.57
October 2001................................................ 620,000 4.80
If the swap arrangements listed above had been settled on December 31,
2000, we would have incurred a loss of $80.1 million. Subsequent to December 31,
2000, we settled the natural gas swaps for January, February and March 2001. A
loss of $18.6 million and $4.4 million and a gain of $0.1 million will be
recognized as price adjustments in January, February and March, respectively. If
we had settled the remaining swaps (April through October) using March 21, 2001
prices, we would have incurred a loss of $13.5 million.
On June 2, 2000, we entered into a natural gas basis protection swap
transaction for 13,500,000 mmbtu for the period of January 2001 through March
2001. This transaction requires that the counterparty pay us if the NYMEX price
exceeds the Houston Ship Channel Beaumont/Texas Index by more than $0.0675 for
each of the related months of production. If the NYMEX price less $0.0675 does
not exceed the Houston Ship Channel Beaumont/ Texas Index for each month, we
will pay the counterparty. Gains or losses on basis swap transactions are
recognized as price adjustments in the month of related production. Subsequent
to December 31, 2000, we settled the natural gas basis protection swaps for
January, February and March 2001. A gain of $0.3 million, a loss of $0.1 million
and a loss of $0.5 million will be recognized as price adjustments in January,
February and March, respectively.
As of December 31, 2000, we had open natural gas collar transactions
designed to hedge 60,000 mmbtu per day throughout 2001 at an average
NYMEX-defined high strike price (cap) of $6.08 per mmbtu and an average
NYMEX-defined low strike price (floor) of $4.00 per mmbtu. If the collar
transactions had been settled on December 31, 2000, we would have incurred a
loss of $18.5 million. Subsequent to December 31, 2000, we settled the natural
gas collar transactions for January, February and March 2001. A loss of $6.9
million and $1.4 million will be recognized as price adjustments in January and
February, respectively. The March 2001 contract was settled for no gain or loss.
As of December 31, 2000, we had the following open crude oil swap
arrangements designed to hedge a portion of our domestic crude oil production
for periods after December 2000:
NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (BBLS) (PER BBL)
------ ------- ------------
January 2001................................................ 165,000 $29.97
February 2001............................................... 150,000 29.92
March 2001.................................................. 165,000 29.84
April 2001.................................................. 160,000 29.80
May 2001.................................................... 165,000 29.75
June 2001................................................... 160,000 29.71
July 2001................................................... 165,000 29.68
August 2001................................................. 165,000 29.65
September 2001.............................................. 160,000 29.62
October 2001................................................ 165,000 29.59
November 2001............................................... 160,000 29.56
December 2001............................................... 165,000 29.54
-66-
68
If the swap arrangements listed above had been settled on December 31,
2000, we would have realized a gain of $9.3 million. Subsequent to December 31,
2000, we settled the crude oil swap for January 2001 for a gain of $0.1 million
and February for a gain of $41,350, which will be recognized as a price
adjustment in January and February 2001.
Subsequent to December 31, 2000, we entered into the following natural gas
swap arrangements designed to hedge a portion of our domestic gas production for
periods after December 2000:
NYMEX-INDEX
VOLUME STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU)
------ --------- ------------
March 2001.................................................. 310,000 $5.93
April 2001.................................................. 300,000 5.66
May 2001.................................................... 930,000 5.34
June 2001................................................... 900,000 5.37
July 2001................................................... 930,000 5.40
August 2001................................................. 930,000 5.42
September 2001.............................................. 900,000 5.38
October 2001................................................ 1,240,000 5.40
The natural gas swap for March 2001 was settled for a gain of $0.3 million
which will be recognized as a price adjustment in March 2001. If we had settled
the remaining swaps (April through October) using March 21, 2001 prices, we
would have realized a gain of $1.0 million.
Subsequent to December 31, 2000, we entered into the following natural gas
collar transactions designed to hedge a portion of our domestic gas production
for periods after December 2000:
NYMEX NYMEX
DEFINED DEFINED
HIGH LOW
VOLUME STRIKE PRICE STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU) (PER MMBTU)
------ --------- ------------ ------------
June 2001................................................... 600,000 $ 6.80 $ 5.00
July 2001................................................... 620,000 6.80 5.00
August 2001................................................. 620,000 6.80 5.00
September 2001.............................................. 600,000 6.80 5.00
January 2002................................................ 620,000 5.75 4.00
February 2002............................................... 560,000 5.75 4.00
March 2002.................................................. 620,000 5.75 4.00
April 2002.................................................. 1,200,000 5.38 4.00
May 2002.................................................... 1,240,000 5.38 4.00
June 2002................................................... 1,200,000 5.38 4.00
July 2002................................................... 1,240,000 5.38 4.00
August 2002................................................. 1,240,000 5.38 4.00
September 2002.............................................. 1,200,000 5.38 4.00
October 2002................................................ 1,240,000 5.38 4.00
November 2002............................................... 600,000 5.75 4.00
December 2002............................................... 620,000 5.75 4.00
Subsequent to December 31, 2000, we entered into natural gas cap-swaps
designed to hedge a portion of our domestic gas production for periods after
December 2000. This transaction requires that we pay the counterparty if the
NYMEX price exceeds an average Nymex defined strike price. If the NYMEX price is
less than the strike price, the counterparty pays us. However, the
counterparty's payment is capped.
-67-
69
NYMEX CAPPED
INDEX LOW
VOLUME STRIKE PRICE STRIKE PRICE
MONTHS (MMBTU) (PER MMBTU) (PER MMBTU)
------ --------- ------------ ------------
May 2001.................................................... 1,860,000 5.77 4.60
June 2001................................................... 1,800,000 5.81 4.64
July 2001................................................... 1,860,000 5.85 4.68
August 2001................................................. 1,860,000 5.87 4.70
September 2001.............................................. 1,800,000 5.83 4.66
October 2001................................................ 1,860,000 5.83 4.66
November 2001............................................... 2,400,000 6.00 4.78
December 2001............................................... 2,480,000 6.10 4.88
January 2002................................................ 2,790,000 6.03 4.83
February 2002............................................... 2,520,000 5.82 4.62
March 2002.................................................. 2,790,000 5.48 4.28
April 2002.................................................. 5,700,000 4.85 3.85
May 2002.................................................... 5,890,000 4.81 3.81
June 2002................................................... 5,700,000 4.80 3.80
July 2002................................................... 5,890,000 4.81 3.81
August 2002................................................. 5,890,000 4.81 3.81
September 2002.............................................. 5,700,000 4.81 3.81
October 2002................................................ 5,890,000 4.80 3.80
November 2002............................................... 2,100,000 4.97 3.97
December 2002............................................... 2,170,000 5.06 4.06
In addition to commodity hedging transactions related to our oil and gas
production, our marketing subsidiary, CEMI, periodically enters into various
hedging transactions designed to hedge against physical purchase and sale
commitments it makes. Gains or losses on these transactions are recorded as
adjustments to oil and gas marketing sales in the consolidated statements of
operations and are not considered by management to be material.
Interest Rate Risk
Chesapeake also utilizes hedging strategies to manage fixed-interest rate
exposure. Through the use of a swap arrangement, we reduced our interest expense
by $2.6 million from May 1998 through December 2000. During 2000, our interest
rate swap resulted in a $38,000 increase in interest expense. The terms of the
swap agreement are as follows:
Months Notional Amount Fixed Rate Floating Rate
------ --------------- ---------- -------------
May 1998 -- April 2001 $230,000,000 7% Average of three-month Swiss Franc
LIBOR, Deutsche Mark and Australian
Dollar plus 300 basis points
May 2001 -- April 2008 $230,000,000 7% U.S. three-month LIBOR plus 300 basis
points
If the floating rate is less than the fixed rate, the counterparty will pay
us accordingly. If the floating rate exceeds the fixed rate, we will pay the
counterparty. The interest rate swap agreement contains a "knockout provision"
whereby the agreement will terminate on or after May 1, 2001 if the average
closing price for the previous twenty business days for shares of Chesapeake's
common stock is greater than or equal to $7.50 per share. The agreement also
provides for a maximum floating rate of 8.5% from May 2001 through April 2008.
Based on current market prices for Chesapeake common stock, we expect the
interest rate swap agreement will terminate in May 2001 under the knockout
provision of the agreement discussed above. The fair value of the swap
arrangement at December 31, 2000 was not material. Results from interest rate
hedging transactions are reflected as adjustments to interest expense in the
corresponding months covered by the swap agreement.
Concentration of Credit Risk
Other financial instruments which potentially subject us to concentrations
of credit risk consist principally of cash, short-term investments in debt
instruments and trade receivables. Our accounts receivable are primarily from
purchasers of oil and natural gas products and exploration and production
companies which own interests in
-68-
70
properties we operate. The industry concentration has the potential to impact
our overall exposure to credit risk, either positively or negatively, in that
the customers may be similarly affected by changes in economic, industry or
other conditions. We generally require letters of credit for receivables from
customers which are judged to have sub-standard credit, unless the credit risk
can otherwise be mitigated. The cash and cash equivalents are deposited with
major banks or institutions with high credit ratings.
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of Statement of
Financial Accounting Standards No. 107, "Disclosures About Fair Value of
Financial Instruments." We have determined the estimated fair value amounts by
using available market information and valuation methodologies. Considerable
judgment is required in interpreting market data to develop the estimates of
fair value. The use of different market assumptions or valuation methodologies
may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current
liabilities approximate fair values due to the short-term maturities of these
instruments. We estimate the fair value of our long-term (including current
maturities), fixed-rate debt using primarily quoted market prices. Our carrying
amount for such debt at December 31, 1999 and 2000 was $921.4 million and $920.7
million, respectively, compared to approximate fair values of $838.7 million and
$894.7 million, respectively. The carrying value of other long-term debt
approximates its fair value as interest rates are primarily variable, based on
prevailing market rates. We estimate the fair value of our convertible preferred
stock, which was issued in April 1998, using quoted market prices. Our carrying
amount for such preferred stock at December 31, 1999 and 2000 was $229.8 million
and $31.2 million, compared to an approximate fair value of $119.0 million and
$49.6 million, respectively.
11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
Net Capitalized Costs
Evaluated and unevaluated capitalized costs related to Chesapeake's oil and
gas producing activities are summarized as follows:
DECEMBER 31, 1999 U.S. CANADA COMBINED
----------------- ----------- -------- -----------
($ IN THOUSANDS)
Oil and gas properties:
Proved.................................................... $ 2,193,492 $121,856 $ 2,315,348
Unproved.................................................. 36,225 3,783 40,008
----------- -------- -----------
Total............................................... 2,229,717 125,639 2,355,356
Less accumulated depreciation, depletion and amortization... (1,645,185) (25,357) (1,670,542)
----------- -------- -----------
Net capitalized costs....................................... $ 584,532 $100,282 $ 684,814
=========== ======== ===========
DECEMBER 31, 2000 U.S. CANADA COMBINED
----------------- ----------- -------- -----------
($ IN THOUSANDS)
Oil and gas properties:
Proved.................................................... $ 2,453,316 $137,196 $ 2,590,512
Unproved.................................................. 23,673 2,012 25,685
----------- -------- -----------
Total............................................... 2,476,989 139,208 2,616,197
Less accumulated depreciation, depletion and amortization... (1,737,892) (32,935) (1,770,827)
----------- -------- -----------
Net capitalized costs....................................... $ 739,097 $106,273 $ 845,370
=========== ======== ===========
Unproved properties not subject to amortization at December 31, 1999 and
2000 consisted mainly of lease acquisition costs. We capitalized approximately
$6.5 million, $3.5 million and $2.4 million of interest during 1998, 1999 and
2000, respectively, on significant investments in unproved properties that were
not yet included in the
-69-
71
amortization base of the full-cost pool. We will continue to evaluate our
unevaluated properties; however, the timing of the ultimate evaluation and
disposition of the properties has not been determined.
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Costs incurred in oil and gas property acquisition, exploration and
development activities which have been capitalized are summarized as follows:
YEAR ENDED DECEMBER 31, 1998 U.S. CANADA COMBINED
---------------------------- -------- ------- --------
($ IN THOUSANDS)
Development and leasehold costs............................. $145,657 $ 4,584 $150,241
Exploration costs........................................... 63,245 5,427 68,672
Acquisition costs:
Proved.................................................... 662,104 78,176 740,280
Unproved.................................................. 23,834 2,535 26,369
Sales of oil and gas properties............................. (15,712) -- (15,712)
Capitalized internal costs.................................. 5,262 -- 5,262
-------- ------- --------
Total............................................... $884,390 $90,722 $975,112
======== ======= ========
YEAR ENDED DECEMBER 31, 1999 U.S. CANADA COMBINED
---------------------------- -------- ------- --------
($ IN THOUSANDS)
Development and leasehold costs............................. $ 92,582 $31,536 $124,118
Exploration costs........................................... 23,651 42 23,693
Acquisition costs:
Proved.................................................... 47,993 4,100 52,093
Unproved.................................................. 2,747 -- 2,747
Sales of oil and gas properties............................. (44,822) (813) (45,635)
Capitalized internal costs.................................. 2,710 -- 2,710
-------- ------- --------
Total............................................... $124,861 $34,865 $159,726
======== ======= ========
YEAR ENDED DECEMBER 31, 2000 U.S. CANADA COMBINED
---------------------------- -------- ------- --------
($ IN THOUSANDS)
Development and leasehold costs............................. $138,285 $13,559 $151,844
Exploration costs........................................... 24,648 10 24,658
Acquisition costs:
Proved.................................................... 75,285 -- 75,285
Unproved.................................................. 3,625 -- 3,625
Sales of oil and gas properties............................. (1,529) -- (1,529)
Capitalized internal costs.................................. 6,958 -- 6,958
-------- ------- --------
Total............................................... $247,272 $13,569 $260,841
======== ======= ========
Results of Operations from Oil and Gas Producing Activities (unaudited)
Chesapeake's results of operations from oil and gas producing activities
are presented below for 1998, 1999 and 2000. The following table includes
revenues and expenses associated directly with our oil and gas producing
activities. It does not include any allocation of our interest costs and,
therefore, is not necessarily indicative of the contribution to consolidated net
operating results of our oil and gas operations.
-70-
72
YEAR ENDED DECEMBER 31, 1998 U.S. CANADA COMBINED
---------------------------- --------- -------- ---------
($ IN THOUSANDS)
Oil and gas sales........................................... $ 248,909 $ 7,978 $ 256,887
Production expenses......................................... (49,368) (1,834) (51,202)
Production taxes............................................ (8,295) -- (8,295)
Impairment of oil and gas properties........................ (810,610) (15,390) (826,000)
Depletion and depreciation.................................. (143,283) (3,361) (146,644)
Imputed income tax (provision) benefit(a)................... 285,981 5,673 291,654
--------- -------- ---------
Results of operations from oil and gas producing
activities................................................ $(476,666) $ (6,934) $(483,600)
========= ======== =========
YEAR ENDED DECEMBER 31, 1999 U.S. CANADA COMBINED
---------------------------- --------- -------- ---------
($ IN THOUSANDS)
Oil and gas sales........................................... $ 266,468 $ 13,977 $ 280,445
Production expenses......................................... (44,165) (2,133) (46,298)
Production taxes............................................ (13,264) -- (13,264)
Depletion and depreciation.................................. (88,901) (6,143) (95,044)
Imputed income tax (provision) benefit(a)................... (45,052) (2,565) (47,617)
--------- -------- ---------
Results of operations from oil and gas producing
activities................................................ $ 75,086 $ 3,136 $ 78,222
========= ======== =========
YEAR ENDED DECEMBER 31, 2000 U.S. CANADA COMBINED
---------------------------- --------- -------- ---------
($ IN THOUSANDS)
Oil and gas sales........................................... $ 436,344 $ 33,826 $ 470,170
Production expenses......................................... (46,280) (3,805) (50,085)
Production taxes............................................ (24,840) -- (24,840)
Depletion and depreciation.................................. (92,708) (8,583) (101,291)
Imputed income tax (provision) benefit(a)................... (103,556) (9,647) (113,203)
--------- -------- ---------
Results of operations from oil and gas producing
activities................................................ $ 168,960 $ 11,791 $ 180,751
========= ======== =========
---------------
(a) The imputed income tax provision is hypothetical (at the statutory rate) and
determined without regard to our deduction for general and administrative
expenses, interest costs and other income tax credits and deductions, nor
whether the hypothetical tax benefits will be realized.
Capitalized costs, less accumulated amortization and related deferred
income taxes, cannot exceed an amount equal to the sum of the present value
(discounted at 10%) of estimated future net revenues less estimated future
expenditures to be incurred in developing and producing the proved reserves,
less any related income tax effects. At December 31, 1998 capitalized costs of
oil and gas properties exceeded the estimated present value of future net
revenues for our proved reserves, net of related income tax considerations,
resulting in writedowns in the carrying value of oil and gas properties of $826
million.
Oil and Gas Reserve Quantities (unaudited)
The reserve information presented below is based upon reports prepared by
independent petroleum engineers and Chesapeake's petroleum engineers.
- As of December 31, 1998, Williamson Petroleum Consultants, Inc., Ryder
Scott Company L.P., H.J. Gruy and Associates, Inc. and our internal
reservoir engineers evaluated 63%, 12%, 1% and 24% of the combined
discounted future net revenues from our estimated proved reserves,
respectively.
- As of December 31, 1999, Williamson, Ryder Scott, and our internal
reservoir engineers evaluated 50%, 16%, and 34% of the combined
discounted future net revenues from our estimated proved reserves,
respectively.
- As of December 31, 2000, Williamson, Ryder Scott, Lee Keeling and
Associates and our internal reservoir engineers evaluated 31%, 25%,
16% and 28% of our combined discounted future net revenues from our
estimated proved reserves, respectively.
-71-
73
The information is presented in accordance with regulations prescribed by
the Securities and Exchange Commission. Chesapeake emphasizes that reserve
estimates are inherently imprecise. Our reserve estimates were generally based
upon extrapolation of historical production trends, analogy to similar
properties and volumetric calculations. Accordingly, these estimates are
expected to change, and such changes could be material and occur in the near
term as future information becomes available.
Proved oil and gas reserves represent the estimated quantities of crude
oil, natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those expected to be recovered through
existing wells with existing equipment and operating methods.
Presented below is a summary of changes in estimated reserves of Chesapeake
for 1998, 1999 and 2000:
DECEMBER 31, 1998
----------------
U.S. CANADA COMBINED
------------------------------ --------------------------- ------------------------------
OIL GAS TOTAL OIL GAS TOTAL OIL GAS TOTAL
(MBBL) (MMCF) (MMCFE) (MBBL) (MMCF) (MMCFE) (MBBL) (MMCF) (MMCFE)
------ --------- --------- ------ ------- -------- ------ --------- ---------
Proved reserves, beginning of
period.......................... 18,226 339,118 448,473 -- -- -- 18,226 339,118 448,473
Extensions, discoveries and other
additions....................... 3,448 90,879 111,567 -- -- -- 3,448 90,879 111,567
Revisions of previous estimates... (4,082) (60,477) (84,969) -- -- -- (4,082) (60,477) (84,969)
Production........................ (5,975) (86,681) (122,531) (1) (7,740) (7,746) (5,976) (94,421) (130,277)
Sale of reserves-in-place......... (30) (3,515) (3,695) -- -- -- (30) (3,515) (3,695)
Purchase of reserves-in-place..... 10,973 444,694 510,532 34 239,513 239,717 11,007 684,207 750,249
------ --------- --------- --- ------- -------- ------ --------- ---------
Proved reserves, end of period.... 22,560 724,018 859,377 33 231,773 231,971 22,593 955,791 1,091,348
====== ========= ========= === ======= ======== ====== ========= =========
Proved developed reserves:
Beginning of period............. 10,087 178,082 238,604 -- -- -- 10,087 178,082 238,604
====== ========= ========= === ======= ======== ====== ========= =========
End of period................... 18,003 552,953 660,971 33 105,990 106,188 18,036 658,943 767,159
====== ========= ========= === ======= ======== ====== ========= =========
DECEMBER 31, 1999
----------------
U.S. CANADA COMBINED
------------------------------ --------------------------- ------------------------------
OIL GAS TOTAL OIL GAS TOTAL OIL GAS TOTAL
(MBBL) (MMCF) (MMCFE) (MBBL) (MMCF) (MMCFE) (MBBL) (MMCF) (MMCFE)
------ --------- --------- ------ ------- -------- ------ --------- ---------
Proved reserves, beginning of
period.......................... 22,560 724,018 859,377 33 231,773 231,971 22,593 955,791 1,091,348
Extensions, discoveries and other
additions....................... 4,593 158,801 186,359 -- 37,835 37,835 4,593 196,636 224,194
Revisions of previous estimates... 3,404 59,904 80,328 -- (98,571) (98,571) 3,404 (38,667) (18,243)
Production........................ (4,147) (96,873) (121,755) -- (11,737) (11,737) (4,147) (108,610) (133,492)
Sale of reserves-in-place......... (4,371) (31,616) (57,842) (33) (796) (994) (4,404) (32,412) (58,836)
Purchase of reserves-in-place..... 2,756 64,350 80,886 -- 19,738 19,738 2,756 84,088 100,624
------ --------- --------- --- ------- -------- ------ --------- ---------
Proved reserves, end of period.... 24,795 878,584 1,027,353 -- 178,242 178,242 24,795 1,056,826 1,205,595
====== ========= ========= === ======= ======== ====== ========= =========
Proved developed reserves:
Beginning of period............. 18,003 552,953 660,971 33 105,990 106,188 18,036 658,943 767,159
====== ========= ========= === ======= ======== ====== ========= =========
End of period................... 17,750 627,120 733,620 -- 136,203 136,203 17,750 763,323 869,823
====== ========= ========= === ======= ======== ====== ========= =========
DECEMBER 31, 2000
----------------
U.S. CANADA COMBINED
------------------------------ --------------------------- ------------------------------
OIL GAS TOTAL OIL GAS TOTAL OIL GAS TOTAL
(MBBL) (MMCF) (MMCFE) (MBBL) (MMCF) (MMCFE) (MBBL) (MMCF) (MMCFE)
------ --------- --------- ------ ------- -------- ------ --------- ---------
Proved reserves, beginning of
period.......................... 24,795 878,584 1,027,353 -- 178,242 178,242 24,795 1,056,826 1,205,595
Extensions, discoveries and other
additions....................... 3,599 157,719 179,313 -- 20,772 20,772 3,599 178,491 200,085
Revisions of previous estimates... (3,210) 25,652 6,392 -- (27,973) (27,973) (3,210) (2,321) (21,581)
Production........................ (3,068) (103,694) (122,102) -- (12,077) (12,077) (3,068) (115,771) (134,179)
Sale of reserves-in-place......... (136) (2,155) (2,971) -- -- -- (136) (2,155) (2,971)
Purchase of reserves-in-place..... 1,817 96,963 107,864 -- -- -- 1,817 96,963 107,864
------ --------- --------- --- ------- -------- ------ --------- ---------
Proved reserves, end of period.... 23,797 1,053,069 1,195,849 -- 158,964 158,964 23,797 1,212,033 1,354,813
====== ========= ========= === ======= ======== ====== ========= =========
Proved developed reserves:
Beginning of period............. 17,750 627,120 733,620 -- 136,203 136,203 17,750 763,323 869,823
====== ========= ========= === ======= ======== ====== ========= =========
End of period................... 15,445 739,775 832,445 -- 118,688 118,688 15,445 858,463 951,133
====== ========= ========= === ======= ======== ====== ========= =========
CHESAPEAKE AND GOTHIC ON A
COMBINED BASIS:
Proved reserves, end of
period........................ 25,565 1,343,976 1,497,364 -- 158,964 158,964 25,565 1,502,940 1,656,328
====== ========= ========= === ======= ======== ====== ========= =========
Proved developed reserves, end
of period..................... 17,012 985,247 1,087,319 -- 118,688 118,688 17,012 1,103,935 1,206,007
====== ========= ========= === ======= ======== ====== ========= =========
-72-
74
During 1999, Chesapeake acquired approximately 101 bcfe of proved reserves
through purchases of oil and gas properties for consideration of $52 million. We
also sold 59 bcfe of proved reserves for consideration of approximately $46
million. During 1999, we recorded upward revisions of 80 bcfe to the December
31, 1998 estimates of our U.S. reserves, and downward revisions of 99 bcfe to
the December 31, 1998 estimates of our Canadian reserves, for a total revision
of 19 bcfe, or approximately 1.7%. The upward revisions to our U.S. reserves
were caused by higher oil and gas prices at December 31, 1999, and actual
performance in excess of predicted performance. Higher prices extend the
economic lives of the underlying oil and gas properties and thereby increase the
estimated future reserves. The downward revisions to our Canadian reserves were
caused by a reduction of our proved undeveloped locations and an increase in
projected transportation and operating costs in Canada, which decreased the
economic lives of the underlying properties.
During 2000, Chesapeake acquired 107.9 bcfe of proved reserves for
consideration of $75.3 million. Also during 2000, we recorded downward revisions
to our U.S. oil reserves of 3.2 million barrels and upward revisions to our U.S.
natural gas reserves of 25.7 bcf. The downward revisions to our U.S. oil
reserves were related to lower estimates primarily in the Knox, Permian and
Williston areas. The upward revisions to our U.S. gas reserves were due
primarily to additional reserves added as a result of the significant increase
in natural gas prices as of December 31, 2000, which had the effect of extending
the economic life of our properties. These upward revisions were partially
offset by the elimination of proved undeveloped locations primarily in the Knox,
Independence and Sahara fields, as well as lower estimates in various areas
located primarily in the Mid-Continent area. During 2000, we also had negative
revisions to our Canadian gas reserves of 28.0 bcf. This decrease was primarily
due to the increase in crown royalties resulting from higher natural gas prices
at December 31, 2000, as well as lower estimates on various properties in the
Helmet field.
Standardized Measure of Discounted Future Net Cash Flows (unaudited)
Statement of Financial Accounting Standards No. 69 prescribes guidelines
for computing a standardized measure of future net cash flows and changes
therein relating to estimated proved reserves. Chesapeake has followed these
guidelines which are briefly discussed below.
Future cash inflows and future production and development costs are
determined by applying year-end prices and costs to the estimated quantities of
oil and gas to be produced. Estimates are made of quantities of proved reserves
and the future periods during which they are expected to be produced based on
year-end economic conditions. Estimated future income taxes are computed using
current statutory income tax rates including consideration for the current tax
basis of the properties and related carryforwards, giving effect to permanent
differences and tax credits. The resulting future net cash flows are reduced to
present value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those
prescribed by the Financial Accounting Standards Board and, as such, do not
necessarily reflect our expectations of actual revenue to be derived from those
reserves nor their present worth. The limitations inherent in the reserve
quantity estimation process, as discussed previously, are equally applicable to
the standardized measure computations since these estimates are the basis for
the valuation process.
The following summary sets forth our future net cash flows relating to
proved oil and gas reserves based on the standardized measure prescribed in SFAS
69:
DECEMBER 31, 1998
----------------
U.S. CANADA COMBINED
----------- ---------- -----------
($ IN THOUSANDS)
Future cash inflows(a)...................................... $ 1,374,280 $ 474,143 $ 1,848,423
Future production costs..................................... (432,876) (52,493) (485,369)
Future development costs.................................... (124,717) (29,634) (154,351)
Future income tax provision................................. (6,464) (143,747) (150,211)
----------- ---------- -----------
Net future cash flows....................................... 810,223 248,269 1,058,492
Less effect of a 10% discount factor........................ (303,096) (132,281) (435,377)
----------- ---------- -----------
Standardized measure of discounted future net cash flows.... $ 507,127 $ 115,988 $ 623,115
=========== ========== ===========
Discounted (at 10%) future net cash flows before income
taxes..................................................... $ 504,148 $ 156,843 $ 660,991
=========== ========== ===========
-73-
75
DECEMBER 31, 1999
----------------
U.S. CANADA COMBINED
----------- ---------- -----------
($ IN THOUSANDS)
Future cash inflows(b)...................................... $ 2,555,241 $ 437,928 $ 2,993,169
Future production costs..................................... (671,431) (195,464) (866,895)
Future development costs.................................... (209,921) (20,950) (230,871)
Future income tax provision................................. (219,866) (29,410) (249,276)
----------- ---------- -----------
Net future cash flows....................................... 1,454,023 192,104 1,646,127
Less effect of a 10% discount factor........................ (545,125) (94,390) (639,515)
----------- ---------- -----------
Standardized measure of discounted future net cash flows.... $ 908,898 $ 97,714 $ 1,006,612
=========== ========== ===========
Discounted (at 10%) future net cash flows before income
taxes..................................................... $ 991,748 $ 97,748 $ 1,089,496
=========== ========== ===========
DECEMBER 31, 2000
----------------
U.S. CANADA COMBINED
----------- ---------- -----------
($ IN THOUSANDS)
Future cash inflows(c)...................................... $11,336,112 $1,540,158 $12,876,270
Future production costs..................................... (1,778,325) (79,427) (1,857,752)
Future development costs.................................... (294,359) (21,185) (315,544)
Future income tax provision................................. (3,247,701) (447,887) (3,695,588)
----------- ---------- -----------
Net future cash flows....................................... 6,015,727 991,659 7,007,386
Less effect of a 10% discount factor........................ (2,440,407) (503,718) (2,944,125)
----------- ---------- -----------
Standardized measure of discounted future net cash flows.... $ 3,575,320 $ 487,941 $ 4,063,261
=========== ========== ===========
Discounted (at 10%) future net cash flows before income
taxes..................................................... $ 5,365,228 $ 680,800 $ 6,046,028(d)
=========== ========== ===========
---------------
(a) Calculated using weighted average prices of $10.48 per barrel of oil and
$1.68 per mcf of gas.
(b) Calculated using weighted average prices of $24.72 per barrel of oil and
$2.25 per mcf of gas.
(c) Calculated using weighted average prices of $26.41 per barrel of oil and
$10.12 per mcf of gas.
(d) Based on the adjusted cash spot price for natural gas and oil at December
31, 2000. These prices are significantly higher than the prices received in
2000.
In January 2001, Chesapeake acquired Gothic Energy Corporation. Gothic
reported $858 million as its standardized measure of discounted future net cash
flows and $1,266,503 as its discounted future net cash flows before income taxes
at December 31, 2001.
U.S. CANADA COMBINED
----------- ---------- -----------
($ IN THOUSANDS)
CHESAPEAKE AND GOTHIC ON A COMBINED BASIS AT DECEMBER 31,
2000:
Future cash flows........................................... $14,341,562 $1,540,158 $15,881,720
Future production costs..................................... (2,128,696) (79,427) (2,208,123)
Future development costs.................................... (336,619) (21,185) (357,804)
Future income tax provision................................. (4,091,330) (447,887) (4,539,217)
----------- ---------- -----------
Net future cash flows....................................... 7,784,917 991,659 8,776,576
Less effect of a 10% discount factor........................ (3,352,024) (503,718) (3,855,742)
----------- ---------- -----------
Standard measure of discounted future net cash flows........ $ 4,432,893 $ 487,941 $ 4,920,834
=========== ========== ===========
Discounted (at 10%) future net cash flows before income
taxes..................................................... $ 6,631,731 $ 680,800 $ 7,312,531
=========== ========== ===========
-74-
76
The principal sources of change in the standardized measure of discounted
future net cash flows are as follows:
DECEMBER 31, 1998
----------------
U.S. CANADA COMBINED
----------- --------- -----------
($ IN THOUSANDS)
Standardized measure, beginning of period................... $ 430,110 $ -- $ 430,110
Sales of oil and gas produced, net of production costs...... (191,246) (6,144) (197,390)
Net changes in prices and production costs.................. (189,817) -- (189,817)
Extensions and discoveries, net of production and
development costs......................................... 85,464 -- 85,464
Changes in future development costs......................... 72,279 -- 72,279
Development costs incurred during the period that reduced
future development costs.................................. 28,191 -- 28,191
Revisions of previous quantity estimates.................... (64,770) -- (64,770)
Purchase of reserves-in-place............................... 288,694 164,821 453,515
Sales of reserves-in-place.................................. (3,079) -- (3,079)
Accretion of discount....................................... 46,651 -- 46,651
Net change in income taxes.................................. 39,377 (40,855) (1,478)
Changes in production rates and other....................... (34,727) (1,834) (36,561)
----------- --------- -----------
Standardized measure, end of period......................... $ 507,127 $ 115,988 $ 623,115
=========== ========= ===========
DECEMBER 31, 1999
----------------
U.S. CANADA COMBINED
----------- --------- -----------
($ IN THOUSANDS)
Standardized measure, beginning of period................... $ 507,127 $ 115,988 $ 623,115
Sales of oil and gas produced, net of production costs...... (209,039) (11,844) (220,883)
Net changes in prices and production costs.................. 320,123 (55,156) 264,967
Extensions and discoveries, net of production and
development costs......................................... 200,787 14,333 215,120
Changes in future development costs......................... (15,011) 20,679 5,668
Development costs incurred during the period that reduced
future development costs.................................. 14,114 1,985 16,099
Revisions of previous quantity estimates.................... 88,250 (49,034) 39,216
Purchase of reserves-in-place............................... 66,895 18,476 85,371
Sales of reserves-in-place.................................. (25,838) (920) (26,758)
Accretion of discount....................................... 50,415 15,684 66,099
Net change in income taxes.................................. (85,828) 40,821 (45,007)
Changes in production rates and other....................... (3,097) (13,298) (16,395)
----------- --------- -----------
Standardized measure, end of period......................... $ 908,898 $ 97,714 $ 1,006,612
=========== ========= ===========
DECEMBER 31, 2000
----------------
U.S. CANADA COMBINED
----------- --------- -----------
($ IN THOUSANDS)
Standardized measure, beginning of period................... $ 908,898 $ 97,714 $ 1,006,612
Sales of oil and gas produced, net of production costs...... (365,224) (30,021) (395,245)
Net changes in prices and production costs.................. 2,750,651 573,654 3,324,305
Extensions and discoveries, net of production and
development costs......................................... 878,128 87,647 965,775
Changes in future development costs......................... 2,167 3,233 5,400
Development costs incurred during the period that reduced
future development costs.................................. 38,112 6,415 44,527
Revisions of previous quantity estimates.................... 25,818 (113,473) (87,655)
Purchase of reserves-in-place............................... 494,483 -- 494,483
Sales of reserves-in-place.................................. (3,113) -- (3,113)
Accretion of discount....................................... 99,175 9,775 108,950
Net change in income taxes.................................. (1,707,060) (192,825) (1,899,885)
Changes in production rates and other....................... 453,285 45,822 499,107
----------- --------- -----------
Standardized measure, end of period......................... $ 3,575,320 $ 487,941 $ 4,063,261
=========== ========= ===========
12. QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized unaudited quarterly financial data for 1999 and 2000 are as
follows ($ in thousands except per share data):
QUARTERS ENDED
------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
1999 1999 1999 1999
--------- -------- ------------- ------------
Net sales................................................... $ 65,677 $80,892 $102,140 $106,237
Gross profit(a)............................................. 7,067 25,765 36,498 38,190
Net income (loss)........................................... (11,950) 8,147 18,115 18,954
Net income (loss) per share:
Basic..................................................... (0.17) 0.04 0.14 0.15
Diluted................................................... (0.17) 0.04 0.13 0.14
-75-
77
QUARTERS ENDED
------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
2000 2000 2000 2000
--------- -------- ------------- ------------
Net sales................................................... $114,661 $134,463 $168,182 $210,646
Gross profit(a)............................................. 40,975 53,142 76,918 107,734
Net income.................................................. 21,202 31,634 54,689 348,045(b)
Net income per share:
Basic..................................................... .27 .26 .33 2.28
Diluted................................................... .15 .22 .31 2.12
---------------
(a) Total revenue less total operating costs.
(b) In the fourth quarter of 2000, we eliminated our valuation allowance
resulting in the recognition of a $265 million income tax benefit. Based
upon recent results of operations and anticipated improvement in
Chesapeake's outlook for sustained profitability, we believe that it is more
likely than not that we will generate sufficient future taxable income to
realize the tax benefits associated with our NOL carryforwards prior to
their expiration.
13. SUBSEQUENT EVENTS
We completed the acquisition of Gothic Energy Corporation on January 16,
2001 by merging a wholly-owned subsidiary into Gothic. We issued a total of 4.0
million shares in the merger. Gothic shareholders (other than Chesapeake)
received 0.1908 of a share of Chesapeake common stock for each share of Gothic
common stock. In addition, outstanding warrants and options to purchase Gothic
common stock were converted to the right to purchase Chesapeake common stock
(1.1 million shares as of March 15, 2001 at an average price of $12.28 per
share) based on the merger exchange ratio. Prior to the merger, Chesapeake
purchased substantially all of Gothic's 14.125% senior secured discount notes
for total consideration valued at $80.8 million in cash and Chesapeake common
stock. Prior to the merger, we also purchased $31.6 million principal amount of
11.125% senior secured notes due 2005 issued by Gothic's operating subsidiary
and guaranteed by Gothic. The consideration for these purchases consisted of
cash and Chesapeake common stock valued at a total of $34.8 million. In February
2001, we purchased $1.0 million principal amount of Gothic senior secured notes
tendered at 101%. There remain outstanding $202.3 million principal amount of
the 11.125% senior secured notes, all of which are secured by Gothic's oil and
gas properties. Chesapeake has not assumed any payment obligations with respect
to the notes. The parties executed a definitive merger agreement on September 8,
2000, as amended on October 1, 2000, and Gothic's shareholders approved the
merger at a special meeting on December 12, 2000.
-76-
78
SCHEDULE II
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
($ IN THOUSANDS)
ADDITIONS
----------------------
BALANCE AT CHARGED BALANCE AT
BEGINNING CHARGED TO OTHER END
DESCRIPTION OF PERIOD TO EXPENSE ACCOUNTS DEDUCTIONS OF PERIOD
------------------------------------------------------- ---------- ---------- -------- ---------- ----------
December 31, 1998:
Allowance for doubtful accounts...................... $ 691 $ 1,589 $ 1,000 $ 71 $ 3,209
Valuation allowance for deferred tax assets.......... $ 77,934 $380,969 $ -- $ -- $458,903
December 31, 1999:
Allowance for doubtful accounts...................... $ 3,209 $ 9 $ -- $ -- $ 3,218
Valuation allowance for deferred tax assets.......... $458,903 $ -- $(5,931)(a) $ 10,956 $442,016
December 31, 2000:
Allowance for doubtful accounts...................... $ 3,218 $ 256 $ -- $ 2,389 $ 1,085
Valuation allowance for deferred tax assets.......... $442,016 $ -- $ -- $442,016(b) $ --
---------------
(a) At December 31, 1998, $5.9 million of the valuation allowance was related to
our Canadian deferred tax assets. During 1999, this valuation allowance was
eliminated as part of a purchase price reallocation related to a 1998
acquisition.
(b) In the fourth quarter of 2000, we eliminated the valuation allowance for
deferred tax assets. The reversal was based upon recent results of
operations and anticipated improvements in Chesapeake's outlook for
sustained profitability. During 2000, we revised our estimate of the 1999
U.S. net deferred tax asset and related valuation allowance from $442
million to $330 million as a result of further evaluation of the income tax
basis of several acquisitions.
-77-
79
CHESAPEAKE ENERGY CORPORATION
PRO FORMA COMBINED FINANCIAL STATEMENTS
SUMMARY
Chesapeake Energy Corporation completed the acquisition of Gothic Energy
Corporation on January 16, 2001, by merging a wholly-owned subsidiary of
Chesapeake into Gothic. We issued a total of 4.0 million shares of our common
stock in the merger. Gothic shareholders (other than Chesapeake) received 0.1908
of a share of Chesapeake common stock for each share of Gothic common stock. In
addition, outstanding warrants and options to purchase Gothic common stock were
converted to the right to purchase Chesapeake common stock (1.1 million shares
as of March 15, 2001 at an average price of $12.28 per share) based on the
merger exchange ratio. Prior to the merger, Chesapeake purchased substantially
all of Gothic's 14.125% senior secured discount notes for total consideration
valued at $80.8 million in cash and Chesapeake common stock. We also purchased
prior to the merger $31.6 million principal amount of 11.125% senior secured
notes due 2005 issued by Gothic's operating subsidiary and guaranteed by Gothic.
The consideration for these purchases consisted of cash and Chesapeake common
stock valued at a total of $34.8 million. In February 2001, we purchased an
additional $1.0 million principal amount of Gothic Production senior secured
notes tendered pursuant to a change-of-control offer to purchase for 101%. There
remain outstanding $202.3 million principal amount of the Gothic Production
11.125% senior secured notes. The notes are collateralized by Gothic's oil and
gas properties. Chesapeake has not assumed any payment obligations with respect
to the notes. Gothic's preferred stock, all of which was owned by Chesapeake
prior to the merger, remains outstanding. As part of the merger, the terms of
the Gothic preferred stock were amended to eliminate cumulative dividends and
conversion rights. The parties executed a definitive merger agreement on
September 8, 2000, as amended on October 1, 2000, and Gothic's shareholders
approved the merger at a special meeting on December 12, 2000.
The following unaudited pro forma combined financial statements are derived
from the historical financial statements of Chesapeake Energy Corporation and
Gothic Energy Corporation. The pro forma combined statements of operations for
the year ended December 31, 2000 reflect the Gothic acquisition, accounted for
as a purchase, as if the acquisition occurred on January 1, 2000. The pro forma
combined balance sheet at December 31, 2000 reflects the consummation of the
Gothic acquisition as if it occurred on December 31, 2000. The unaudited pro
forma combined financial data should be read in conjunction with the notes
thereto and the historical financial statements of Chesapeake and Gothic,
including the notes thereto.
The unaudited pro forma combined financial statements do not purport to be
indicative of the results of operations that would actually have occurred if the
transaction described had occurred as presented in such statements or that may
occur in the future. In addition, future results may vary significantly from the
results reflected in such statements due to general economic conditions, oil and
gas commodity prices, Chesapeake's ability to successfully integrate the
operations of Gothic with its current business and several other factors, many
of which are beyond Chesapeake's control.
-78-
80
CHESAPEAKE ENERGY CORPORATION
UNAUDITED PRO FORMA COMBINED BALANCE SHEET
AS OF DECEMBER 31, 2000
($ IN THOUSANDS)
HISTORICAL PRO FORMA
------------------------ ----------------------------
CHESAPEAKE GOTHIC ADJUSTMENTS AS ADJUSTED
----------- --------- ----------- -----------
ASSETS
Current assets.............................................. $ 166,926 $ 22,229 $ 58(a) $ 188,203
(1,010)(j)
Property, plant and equipment:
Proved properties......................................... 2,590,512 275,827 87,374(a) 2,953,377
(336)(k)
Unproved properties....................................... 25,685 6,191 3,809(a) 35,685
Accumulated DD&A.......................................... (1,770,827) (75,003) 75,003(a) (1,770,827)
----------- --------- --------- -----------
Net proved and unproved properties........................ 845,370 207,015 165,850 1,218,235
Other, net................................................ 42,864 4,737 (4,587)(a) 43,014
----------- --------- --------- -----------
Total property, plant and equipment, net.................. 888,234 211,752 161,263 1,261,249
Investment in Gothic........................................ 126,434 -- (125,521)(a) --
(913)(k)
Deferred tax asset.......................................... 229,823 -- (20)(j) 231,083
1,280(i)
Other....................................................... 29,009 8,675 (8,675)(a) 26,209
(2,800)(i)
----------- --------- --------- -----------
Total assets........................................ $1,440,426 $ 242,656 $ 23,662 $ 1,706,744
=========== ========= ========= ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities......................................... $ 162,701 $ 11,209 $ 12,000(a) $ 183,924
(1,137)(a)
(1,249)(k)
400(i)
Long-term debt.............................................. 944,845 321,676 (112,400)(a) 1,159,495
6,434(a)
(1,060)(j)
Deferred income tax liabilities............................. 11,850 -- -- 11,850
Other liabilities........................................... 7,798 2,835 -- 10,633
Stockholders equity:
Preferred stock........................................... 31,202 55,139 (55,139)(a) 31,202
Common stock.............................................. 1,578 233 (233)(a) 1,618
40(a)
Warrants.................................................... -- -- 1,500(a) 1,500
Paid-in capital............................................. 963,584 44,830 (44,830)(a) 991,544
27,960(a)
Accumulated earnings (deficit).............................. (659,286) (193,266) 193,266(a) (661,176)
(1,920)(i)
30(j)
Accumulated other comprehensive income (loss)............... (3,901) -- -- (3,901)
Less treasury stock......................................... (19,945) -- -- (19,945)
----------- --------- --------- -----------
Total stockholders' equity (deficit)................ 313,232 (93,064) 120,674 340,842
----------- --------- --------- -----------
Total liabilities and stockholders' equity
(deficit)......................................... $1,440,426 $ 242,656 $ 23,662 $ 1,706,744
=========== ========= ========= ===========
The accompanying notes are an integral part of these pro forma combined
financial statements.
-79-
81
CHESAPEAKE ENERGY CORPORATION
UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2000
(IN THOUSANDS, EXCEPT PER SHARE DATA)
HISTORICAL PRO FORMA
---------------------- ----------------------------
CHESAPEAKE GOTHIC ADJUSTMENTS AS ADJUSTED
---------- -------- ----------- -----------
REVENUES:
Oil and gas sales......................................... $ 470,170 $ 83,065 $ -- $ 553,235
Oil and gas marketing sales............................... 157,782 -- -- 157,782
Well operations........................................... -- 2,680 (2,680)(h) --
--------- -------- -------- ---------
Total revenues...................................... 627,952 85,745 (2,680) 711,017
--------- -------- -------- ---------
OPERATING COSTS:
Production expenses and taxes............................. 74,925 11,800 -- 86,725
General and administrative................................ 13,177 5,763 (2,680)(h) 16,260
Oil and gas marketing expenses............................ 152,309 -- -- 152,309
Oil and gas depreciation, depletion and amortization...... 101,291 21,817 25,286(b) 148,394
Depreciation and amortization of other assets............. 7,481 2,632 (2,582)(c) 7,531
--------- -------- -------- ---------
Total operating costs............................... 349,183 42,012 20,024 411,219
--------- -------- -------- ---------
INCOME FROM OPERATIONS...................................... 278,769 43,733 (22,704) 299,798
--------- -------- -------- ---------
OTHER INCOME (EXPENSE):
Interest and other income................................. 3,649 280 -- 3,929
Interest expense.......................................... (86,256) (37,931) 14,427(g) (106,987)
2,773(l)
--------- -------- -------- ---------
Total other income (expense)........................ (82,607) (37,651) 17,200 (103,058)
--------- -------- -------- ---------
INCOME (LOSS) BEFORE INCOME TAXES........................... 196,162 6,082 (5,504) 196,740
--------- -------- -------- ---------
INCOME TAX EXPENSE (BENEFIT)................................ (259,408) -- (2,202)(d) (261,610)
--------- -------- -------- ---------
NET INCOME (LOSS)........................................... 455,570 6,082 (3,302) 458,350
Preferred stock dividends................................. (8,484) (9,527) 9,527(f) (8,484)
Gain (loss) on redemption of preferred stock.............. 6,574 -- -- 6,574
--------- -------- -------- ---------
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS.......... $ 453,660 $ (3,445) $ 6,225 $ 456,440
========= ======== ======== =========
EARNINGS (LOSS) PER COMMON SHARE(E):
Basic..................................................... $ 3.52 $ 3.27
========= =========
Assuming dilution......................................... $ 3.01 $ 2.83
========= =========
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES
OUTSTANDING(E):
Basic..................................................... 128,993 139,536
========= =========
Assuming dilution......................................... 151,564 162,107
========= =========
The accompanying notes are an integral part of these pro forma combined
financial statements.
-80-
82
NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS
(a) The purchase price reflects:
- the issuance of 4.0 million shares of Chesapeake common stock, valued
at $7.00 per share, the closing price of Chesapeake common stock on
the day the merger was announced, in exchange for all outstanding
shares of Gothic common stock (other than shares of Gothic common
stock held by Chesapeake);
- the issuance of Chesapeake warrants and options to purchase 2.9
million shares of Chesapeake common stock in exchange for all of the
outstanding warrants and options to purchase shares of Gothic common
stock based on the exchange ratio of 0.1908 of a share of Chesapeake
common stock for each share of Gothic common stock;
- Chesapeake's investment in Gothic preferred and common stock, which
has a carrying value of $10.0 million;
- Chesapeake estimated the fair value of the Gothic Production senior
secured notes equalled 106% of their face value; and
- the incurrence of acquisition costs of approximately $12.0 million.
Below is a summary of the purchase price allocation to the estimated fair
value of the assets acquired and liabilities assumed ($ in 000's):
Issuance of common stock.................................... $ 28,000
Investment in Gothic preferred and common stock............. 10,000
Fair value of Chesapeake warrants........................... 1,500
Investment in Gothic senior secured discount notes.......... 80,761
Investment in Gothic Production senior secured notes........ 34,760
Other acquisition costs..................................... 12,000
--------
Purchase price.......................................... $167,021
========
GOTHIC ESTIMATED PRO FORMA
BOOK VALUE FAIR VALUE ADJUSTMENT
---------- ---------- ----------
Current assets.............................................. $ 22,229 $ 22,287 $ 58
Property and equipment -- proved properties................. 275,827 363,201 87,374
Property and equipment -- unproved properties............... 6,191 10,000 3,809
Accumulated DD&A............................................ (75,003) -- 75,003
Other property and equipment................................ 4,737 150 (4,587)
Other assets................................................ 8,675 -- (8,675)
Current liabilities......................................... (11,209) (10,072) 1,137
Debt, less $112.4 million of Gothic notes held by
Chesapeake................................................ (209,276) (215,710) (6,434)
Other liabilities........................................... (2,835) (2,835) --
--------- --------- --------
$ 19,336 $ 167,021 $147,685
========= ========= ========
(b) To adjust DD&A expense of oil and gas properties using a rate of $0.92
per mcfe. This combined rate reflects the impact of the allocation of purchase
price to Gothic's proved oil and gas properties.
(c) To adjust depreciation and amortization expense in connection with the
allocation of purchase price to the estimated fair value of Gothic's other
property and equipment and other assets. A significant portion of Gothic's
depreciation and amortization expense was related to (1) telemetry assets which
have been classified to oil and gas properties (and depreciated accordingly),
and (2) debt issue costs that will have no future value to Chesapeake. The
remaining fair value of other property and equipment will be depreciated over a
three-year period.
(d) To record tax effects of the pro forma adjustments at a statutory rate
of 40% (federal and state).
-81-
83
(e) Basic and diluted earnings per share have been calculated assuming the
transaction was consummated at the beginning of the period and are calculated as
follows (in 000's):
YEAR ENDED
DECEMBER 31, 2000
-----------------
Chesapeake's basic shares outstanding (as reported)......... 128,993
Adjustment to reflect issuance of common stock to acquire
Gothic debt at January 1, 2000............................ 6,543
Issuance of common stock to Gothic -- merger
consideration............................................. 4,000
-------
Basic shares outstanding -- as adjusted................. 139,536
=======
Chesapeake's diluted shares outstanding (as reported)....... 151,564
Adjustment to reflect issuance of common stock to acquire
Gothic debt at January 1, 2000............................ 6,543
Issuance of common stock to Gothic -- merger
consideration............................................. 4,000
-------
Diluted shares outstanding -- as adjusted............... 162,107
=======
(f) To eliminate dividends on Gothic's preferred stock held by Chesapeake.
(g) To eliminate interest expense related to the Gothic senior discount
notes and Gothic Production senior secured notes acquired by Chesapeake.
(h) To reclassify overhead reimbursements recognized by Gothic as operator
of certain oil and gas properties and reported as well operations revenue. These
reimbursements have been reclassified as a reduction to general and
administrative expenses to conform with Chesapeake's presentation of similar
reimbursements.
(i) To record the remaining financing fees (net of income tax) incurred by
Chesapeake to establish a standby credit facility to fund purchases of Gothic
Production senior secured notes tendered after the merger pursuant to a
change-of-control offer to purchase the notes at 101% principal amount. The
standby credit facility was not utilized, and therefore the associated fees were
expensed when the holders' change-of-control put options expired in February
2001. Chesapeake incurred $2.8 million in financing fees prior to December 31,
2000 and $0.4 million subsequent thereto.
(j) To record the purchase of $1.0 million principal amount of Gothic
Production senior secured notes which were tendered pursuant to the
post-acquisition change-of-control offer to purchase at 101%. These notes were
adjusted to their market value of 106% in the purchase price allocation (see
note a). The gain on extinguishment is tax effected.
(k) To adjust the purchase price allocation and accrued merger-related
costs for $1.24 million incurred through December 31, 2000. This amount includes
$913 thousand paid by Chesapeake, included in Other Assets, and $336 thousand
paid and expensed by Gothic.
(l) To record amortization of the 6% premium on remaining Gothic senior
secured notes held by third parties.
-82-
84
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Stockholder of Gothic Energy Corporation
In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, stockholders' equity (deficit)
and cash flows present fairly, in all material respects, the financial position
of Gothic Energy Corporation ("Gothic") and Subsidiary at December 31, 1999 and
2000, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2000, in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of Gothic's management; our responsibility is
to express an opinion on these financial statements based on our audits. We
conducted our audits of these financial statements in accordance with auditing
standards generally accepted in the United States of America which require that
we plan and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
Chesapeake Energy Corporation ("Chesapeake") acquired all of the
outstanding common stock and related outstanding warrants and options to acquire
common stock of Gothic and Gothic was merged into a wholly owned subsidiary of
Chesapeake.
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 26, 2001
-83-
85
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
----------------------
1999 2000
--------- ---------
($ IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 2,583 $ 2,000
Natural gas and oil receivables........................... 8,163 18,273
Receivable from officers and employees.................... 77 1,764
Other..................................................... 624 192
--------- ---------
Total Current Assets................................ 11,447 22,229
PROPERTY AND EQUIPMENT:
Natural gas and oil properties on full cost method:
Properties being amortized.............................. 258,818 275,827
Unproved properties not subject to amortization......... 5,473 6,191
Equipment, furniture and fixtures......................... 6,123 6,385
Accumulated depreciation, depletion and amortization...... (54,170) (76,651)
--------- ---------
PROPERTY AND EQUIPMENT, NET............................... 216,244 211,752
OTHER ASSETS, NET........................................... 10,706 8,675
--------- ---------
TOTAL ASSETS................................................ $ 238,397 $ 242,656
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable trade.................................... $ 4,630 $ 203
Revenues payable.......................................... 6,047 6,349
Accrued interest.......................................... 4,357 4,366
Other accrued liabilities................................. 893 291
--------- ---------
Total Current Liabilities........................... 15,927 11,209
LONG-TERM DEBT.............................................. 319,857 321,676
GAS IMBALANCE LIABILITY..................................... 3,648 2,835
COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 6)
STOCKHOLDERS' EQUITY (DEFICIT):
Series B Preferred stock, par value $.05, authorized
165,000 shares; 59,216 and 66,674 shares issued and
outstanding, respectively............................... 45,612 55,139
Common stock, par value $.01, authorized 100,000,000
shares; 18,685,765 and 23,305,094 shares issued and
outstanding, respectively............................... 187 233
Additional paid in capital................................ 42,987 44,830
Accumulated deficit....................................... (189,821) (193,266)
--------- ---------
Total Stockholders' Equity (Deficit)................ (101,035) (93,064)
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)........ $ 238,397 $ 242,656
========= =========
See accompanying notes to consolidated financial statements.
-84-
86
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENT OF OPERATIONS
YEARS ENDED DECEMBER 31,
---------------------------------
1998 1999 2000
--------- -------- --------
($ IN THOUSANDS, EXCEPT
PER SHARE DATA)
REVENUES:
Natural gas and oil sales................................. $ 50,714 $ 52,967 $ 83,065
Well operations........................................... 2,319 2,657 2,680
--------- -------- --------
Total revenues............................................ 53,033 55,624 85,745
COSTS AND EXPENSES:
Lease operating expense................................... 12,129 9,605 11,800
Depletion, depreciation and amortization.................. 24,001 20,969 22,621
General and administrative expense........................ 3,823 4,675 4,551
Investment banking and related fees....................... -- 638 1,212
Provision for impairment of natural gas and oil
properties.............................................. 76,000 -- --
--------- -------- --------
Operating income (loss)..................................... (62,920) 19,737 45,561
Interest expense and amortization of debt issuance costs.... (35,438) (37,988) (39,759)
Interest and other income................................... 433 942 280
Loss on sale of investments................................. (305) -- --
--------- -------- --------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM..................... (98,230) (17,309) 6,082
LOSS ON EARLY EXTINGUISHMENT OF DEBT........................ 31,459 -- --
--------- -------- --------
NET INCOME (LOSS)........................................... (129,689) (17,309) 6,082
PREFERRED DIVIDEND.......................................... 5,599 6,820 7,678
PREFERRED DIVIDEND -- AMORTIZATION OF PREFERRED DISCOUNT.... 5,095 1,847 1,849
--------- -------- --------
NET LOSS AVAILABLE FOR COMMON SHARES........................ $(140,383) $(25,976) $ (3,445)
========= ======== ========
LOSS PER COMMON SHARE BEFORE EXTRAORDINARY ITEM, BASIC AND
DILUTED................................................... $ (6.70) $ (1.51) $ (0.17)
LOSS ON EARLY EXTINGUISHMENT OF DEBT........................ (1.93) -- --
--------- -------- --------
NET LOSS PER COMMON SHARE, BASIC AND DILUTED................ $ (8.63) $ (1.51) $ (0.17)
========= ======== ========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING.................. 16,262 17,219 20,637
========= ======== ========
See accompanying notes to consolidated financial statements.
-85-
87
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIT)
YEARS ENDED DECEMBER 31,
-----------------------------------
1998 1999 2000
--------- --------- ---------
($ IN THOUSANDS)
PREFERRED STOCK:
Balance beginning of period............................... $ -- $ 36,945 $ 45,612
Preferred stock dividend -- Series B...................... 4,187 6,820 7,678
Preferred dividend -- amortization of discount -- Series
B....................................................... 1,231 1,847 1,849
Issuance of Series A preferred stock...................... 33,909 -- --
Redemption of Series A preferred stock.................... (33,909) -- --
Issuance of Series B preferred stock...................... 31,527 -- --
--------- --------- ---------
Balance, end of period.................................... $ 36,945 $ 45,612 $ 55,139
========= ========= =========
COMMON STOCK:
Balance, beginning of period.............................. $ 162 $ 162 $ 187
Issuance of common stock on exercise of options........... -- -- 44
Issuance of common stock on exercise of warrants.......... -- -- 2
Issuance of common stock on warrant conversion............ -- 25 --
--------- --------- ---------
Balance, end of period.................................... $ 162 $ 187 $ 233
========= ========= =========
ADDITIONAL PAID-IN CAPITAL:
Balance, beginning of period.............................. $ 36,043 $ 42,996 $ 42,987
Issuance of common stock on exercise of options........... -- -- 1,695
Issuance of common stock as employee severance............ -- 16 --
Issuance of common stock on exercise of warrants.......... -- -- 148
Issuance of common stock on warrant conversion............ -- (25) --
Issuance of Series A preferred stock...................... (20) -- --
Warrants issued in connection with Series A preferred..... 941 -- --
Warrants issued in connection with Amoco acquisition...... 1,153 -- --
Warrants issued in connection with Series B preferred..... 4,879 -- --
--------- --------- ---------
Balance, end of period.................................... $ 42,996 $ 42,987 $ 44,830
========= ========= =========
ACCUMULATED DEFICIT:
Balance, beginning of period.............................. $ (23,462) $(163,845) $(189,821)
Net income (loss)......................................... (129,689) (17,309) 6,082
Preferred stock dividend -- Series B...................... (4,187) (6,820) (7,678)
Preferred stock dividend -- amortization of
discount -- Series B.................................... (1,231) (1,847) (1,849)
Preferred stock dividend -- Series A...................... (1,412) -- --
Preferred stock dividend -- amortization of
discount -- Series A.................................... (3,864) -- --
--------- --------- ---------
Balance, end of period.................................... $(163,845) $(189,821) $(193,266)
========= ========= =========
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance, beginning of period.............................. $ (121) $ -- $ --
Realized loss on available for sale investments........... 121 -- --
--------- --------- ---------
Balance, end of period.................................... $ -- $ -- $ --
========= ========= =========
NOTE RECEIVABLE:
Balance, beginning of period.............................. $ (169) $ (179) $ --
Advance to officer........................................ (10) -- --
Forgiveness of officer note receivable.................... -- 179 --
--------- --------- ---------
Balance, end of period.................................... $ (179) $ -- $ --
========= ========= =========
TOTAL STOCKHOLDERS' EQUITY (DEFICIT)........................ $ (83,921) $(101,035) $ (93,064)
========= ========= =========
See accompanying notes to consolidated financial statements.
-86-
88
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CASH FLOWS
YEARS ENDED DECEMBER 31,
---------------------------------
1998 1999 2000
--------- -------- --------
($ IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $(129,689) $(17,309) $ 6,082
ADJUSTMENTS TO RECONCILE NET LOSS TO NET CASH PROVIDED BY
OPERATING ACTIVITIES:
Depreciation, depletion and amortization.................. 24,001 20,969 22,621
Amortization of discount and loan costs................... 1,994 1,769 1,828
Provision for impairment of natural gas and oil
properties.............................................. 76,000 -- --
Accretion of interest on discount notes................... 6,023 9,678 10,819
Loss on early extinguishment of debt...................... 31,459 -- --
Other..................................................... -- 179 --
CHANGES IN ASSETS AND LIABILITIES:
Increase in accounts receivable........................... (4,009) (949) (11,797)
(Increase) decrease in other current assets............... (143) (403) 432
Increase (decrease) in accounts and revenues payable...... 5,605 1,438 (4,125)
Increase (decrease) in gas imbalance and other
liabilities............................................. 65 (2,532) (813)
Increase (decrease) in accrued liabilities................ 411 639 (593)
(Increase) decrease in other assets....................... (150) 228 202
--------- -------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES................... 11,567 13,707 24,656
NET CASH USED BY INVESTING ACTIVITIES:
Collection of note receivable from officer and director... 167 -- --
Purchase of available-for-sale investments................ (462) -- --
Proceeds from sale of investments......................... 1,359 -- --
Proceeds from sale of property and equipment.............. 44,678 2,228 1,877
Purchase of property and equipment........................ (218,738) (3,413) (939)
Property development costs................................ (18,379) (21,056) (19,066)
--------- -------- --------
NET CASH USED BY INVESTING ACTIVITIES....................... (191,375) (22,241) (18,128)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from short-term borrowings....................... 60,000 -- --
Payments of short-term borrowings......................... (60,000) -- --
Proceeds from long-term borrowings........................ 431,290 31,000 13,473
Payments of long-term borrowings.......................... (259,884) (22,000) (22,473)
Redemption of preferred stock, net........................ (40,809) -- --
Proceeds from sale of preferred stock, net................ 73,475 -- --
Proceeds from exercise of stock options................... -- -- 1,739
Proceeds from exercise of stock warrants.................. -- -- 150
Payment of loan and offering fees......................... (38,535) (172) --
Other..................................................... (162) -- --
--------- -------- --------
NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES............ 165,375 8,828 (7,111)
NET CHANGE IN CASH AND CASH EQUIVALENTS..................... (14,433) 294 (583)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD.............. 16,722 2,289 2,583
--------- -------- --------
CASH AND CASH EQUIVALENTS, END OF PERIOD.................... $ 2,289 $ 2,583 $ 2,000
========= ======== ========
SUPPLEMENTAL DISCLOSURE OF INTEREST PAID.................... $ 23,063 $ 26,541 $ 27,104
========= ======== ========
See accompanying notes to consolidated financial statements.
-87-
89
GOTHIC ENERGY CORPORATION AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. GENERAL AND ACCOUNTING POLICIES
Organization and Nature of Operations
The consolidated financial statements include the accounts of Gothic Energy
Corporation, ("Gothic Energy"), a holding company, and its wholly owned
subsidiary, Gothic Production Corporation ("Gothic Production") since its
formation in April of 1998 (collectively referred to as "Gothic" or the
"Company"). All significant intercompany balances and transactions have been
eliminated. Through January 15, 2001, Gothic Production was an independent
energy company engaged in the business of acquiring, developing and exploiting
natural gas and oil reserves in Oklahoma, Texas, New Mexico and Kansas.
On January 16, 2001, Gothic Energy Corporation merged with Chesapeake
Merger 2000 Corp., a wholly owned subsidiary of Chesapeake Energy Corporation
("Chesapeake") (the "Merger"). Gothic was the surviving corporation in the
Merger and since January 16, 2001 has been a wholly owned subsidiary of
Chesapeake. Chesapeake had previously acquired all of Gothic's Series B
Preferred Stock, substantially all of Gothic Energy's 14 1/8% Senior Secured
Discount Notes, and $31.6 million of Gothic Production's 11 1/8% Senior Secured
Notes. Under terms of the Merger, Chesapeake issued 4.0 million shares of common
stock to the Gothic stockholders, with an exchange ratio of 0.1908 of a
Chesapeake share for each share of Gothic common stock.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. In addition,
accrued and deferred lease operating expenses, gas imbalance liabilities,
natural gas and oil reserves (see Note 11) and the tax valuation allowance (see
Note 5) also include significant estimates which, in the near term, could
materially differ from the amounts ultimately realized or incurred.
Cash Equivalents
Cash equivalents include cash on hand, amounts held in banks, money market
funds and other highly liquid investments with a maturity of three months or
less at date of purchase.
Concentration of Credit Risk
Financial instruments, which potentially subject Gothic to concentrations
of credit risk consist principally of derivative contracts (see "Hedging
Activities" below), cash, cash equivalents and trade receivables. Gothic's
accounts receivable are primarily from the purchasers (See Note 8 -- Major
Customers) of natural gas and oil products and exploration and production
companies which own interests in properties operated by Gothic. The industry
concentration has the potential to impact Gothic's overall exposure to credit
risk, either positively or negatively, in that the customers may be similarly
affected by changes in economic, industry or other conditions. Gothic generally
does not require collateral from customers. Gothic had an account receivable
from one customer (CMS Continental Natural Gas) of approximately $2.3 million at
December 31, 1999 and $8.8 million at December 31, 2000. The cash and cash
equivalents are with major banks or institutions with high credit ratings. At
December 31, 1999 and 2000, Gothic had a concentration of cash of $5.8 million
and $6.5 million, respectively, with one bank, which was in excess of federally
insured limits.
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of Statement of
Financial Accounting Standards No. 107, "Disclosures About Fair Value of
Financial
-88-
90
Instruments." Gothic, using available market information, has determined the
estimated fair value amounts. Considerable judgment is required in interpreting
market data to develop the estimates of fair value. The use of different market
assumptions or valuation methodologies may have a material effect on the
estimated fair value amounts.
The carrying values of items comprising current assets and current
liabilities approximate fair values due to the short-term maturities of these
instruments. Gothic estimates the fair value of Gothic Production's 11 1/8%
Senior Secured Notes and Gothic Energy's 14 1/8% Senior Secured Discount Notes
using estimated market prices. Gothic's carrying amount for such debt at
December 31, 1999 was $235.0 million and $75.9 million, respectively, compared
to approximate fair value of $197.4 million and $35.9 million, respectively. At
December 31, 2000, the notes were carried at $235.0 million and $86.7 million,
respectively, compared to an approximate fair value of $249.1 million and $80.1
million, respectively. The carrying value of other long-term debt approximates
its fair value as interest rates are primarily variable, based on prevailing
market rates.
Hedging Activities
Gothic has involvement with derivative financial instruments, as defined in
Statement of Financial Accounting Standards No. 119 "Disclosure About Derivative
Financial Instruments and Fair Value of Financial Instruments," and does not use
them for trading purposes. Gothic's objective is to hedge a portion of its
exposure to price volatility from producing natural gas. These arrangements may
expose Gothic to credit risk from its counterparty.
In July 1999, Gothic entered into a costless collar agreement with respect
to the production of 50,000 mmbtu per day during the period of November 1999
through March 2000, which placed a floor of $2.30 per mmbtu and a ceiling of
$3.03 per mmbtu. Collar arrangements limit the benefits Gothic will realize if
actual prices rise above the ceiling price. These arrangements provide for
Gothic to exchange a floating market price for a fixed range contract price.
Payments are made by Gothic when the floating price exceeds the fixed range for
a contract month and payments are received when the fixed range price exceeds
the floating price. The commodity reference price for the contract was the
Panhandle Eastern Pipeline Company, Texas, and Oklahoma Mainline Index. In
August 1999, Gothic entered into a hedge agreement covering 10,000 barrels of
oil per month at a price of $20.10 per barrel. This hedge was in effect from
September 1999 through August 2000.
Additionally, in January 2000, Gothic entered into a hedge agreement
covering 50,000 mmbtu per day at a fixed price of $2.435 per mmbtu. This hedge
was in effect from April 2000 through October 2000. In February 2000, Gothic
entered into a hedge agreement covering 20,000 mmbtu per day at a fixed price of
$2.535 per mmbtu for April 2000 and $2.555 per mmbtu for May 2000. This hedge
was in effect for the months of April and May 2000. The commodity price for both
contracts was the Panhandle Eastern Pipeline Company, Texas, Oklahoma Mainline
Index.
In September 2000, Gothic entered into hedge contracts for the months of
November and December 2000, for 60,000 mmbtu per day at a price of $4.88 and
$5.00, respectively. The commodity price for both contracts was the Panhandle
Eastern Pipeline Company, Texas, Oklahoma Mainline Index.
Gains and losses on such natural gas and oil hedging contracts are
reflected in revenues when the natural gas or crude oil is sold. Hedging
activities reduced 2000 realized prices by $0.65 per mcf and $5.79 per barrel,
and reduced natural gas and oil sales by $17.9 million. Gothic had no open
commodity hedges at December 31, 2000. If the open commodity hedges outstanding
at December 31, 1999 had been settled at that date, Gothic would have realized a
gain of approximately $500,000.
Natural Gas and Oil Properties
Gothic accounts for its natural gas and oil exploration and development
activities using the full-cost method of accounting prescribed by the Securities
and Exchange Commission ("SEC"). Accordingly, all productive and non-productive
costs incurred in connection with the acquisition, exploration and development
of natural gas and oil reserves are capitalized and depleted using the
units-of-production method based on proved natural gas and oil reserves. Gothic
capitalizes costs, including salaries and related fringe benefits of employees
and/or consultants directly engaged in the acquisition, exploration and
development of natural gas and oil properties, as well as other
-89-
91
directly identifiable general and administrative costs associated with such
activities. Such costs do not include any costs related to production, general
corporate overhead, or similar activities.
Gothic's natural gas and oil reserves are estimated annually by independent
petroleum engineers. Gothic's calculation of depreciation, depletion and
amortization ("DD&A") includes estimated future expenditures to be incurred in
developing proved reserves and estimated dismantlement and abandonment costs,
net of salvage values. The average composite rate used for DD&A of natural gas
and oil properties was $0.91, $0.77 and $0.81 per mcfe in 1998, 1999 and 2000,
respectively. DD&A of natural gas and oil properties amounted to $23.6 million,
$20.4 million and $21.9 million in 1998, 1999 and 2000, respectively.
In the event the unamortized cost of natural gas and oil properties being
amortized exceeds the full-cost ceiling as defined by the SEC, the excess is
charged to expense in the period during which such excess occurs. The full-cost
ceiling is based principally on the estimated future discounted net cash flows
from Gothic's natural gas and oil properties. Gothic recorded a $76.0 million
provision for impairment of natural gas and oil properties during the year ended
December 31, 1998. No such provision was recorded in 1999 or 2000. As discussed
in Note 11, estimates of natural gas and oil reserves are imprecise. Changes in
the estimates or declines in natural gas and oil prices could cause Gothic in
the near-term to reduce the carrying value of its natural gas and oil
properties.
Sales and abandonments of properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized unless a significant amount of
reserves is involved. Since all of Gothic's natural gas and oil properties are
located in the United States, a single cost center is used.
Equipment, Furniture and Fixtures
Equipment, furniture and fixtures are stated at cost and are depreciated on
the straight-line method over their estimated useful lives which range from
three to seven years.
Debt Issuance Costs
Debt issuance costs, including the original issue discount associated with
Gothic's 11 1/8% Senior Secured Notes Due 2005 and Gothic Energy's 14 1/8%
Senior Secured Discount Notes Due 2006, are amortized and included in interest
expense using the effective interest method over the term of the notes. The
unamortized portion of debt issuance costs associated with Gothic's credit
facility is also included in other assets and amortized and included in interest
expense using the straight-line method over the term of the facility.
Amortization of debt issuance costs for the years ended December 31, 1998, 1999
and 2000 amounted to $2.0 million, $1.8 million and $1.8 million, respectively.
Unamortized debt issue costs at December 31, 1999 and 2000 were $9.9 million and
$7.4 million, respectively.
Natural Gas and Oil Sales and Natural Gas Balancing
Gothic uses the sales method for recording natural gas sales. Gothic's oil
and condensate production is sold, the title passes, and revenue is recognized
at or near its wells under short-term purchase contracts at prevailing prices in
accordance with arrangements which are customary in the oil industry. Sales of
gas applicable to Gothic's interest in producing natural gas and oil leases are
recorded as revenues when the gas is metered and title transferred pursuant to
the gas sales contracts covering its interest in gas reserves. During such times
as Gothic's sales of gas exceed its pro rata ownership in a well, such sales are
recorded as revenues unless total sales from the well have exceeded Gothic's
share of estimated total gas reserves underlying the property at which time such
excess is recorded as a gas imbalance liability. At December 31, 1999, total
sales exceeded Gothic's share of estimated total gas reserves on 32 wells by
$2.8 million (1,449 mmcf), based on historical settlement prices. At December
31, 2000, total sales exceeded Gothic's share of estimated total gas reserves on
27 wells by $2.2 million (1,233 mmcf). The gas imbalance liability has been
classified in the balance sheet as non-current, as Gothic does not expect to
settle the liability during the next twelve months.
Gothic has recorded deferred charges for estimated lease operating expenses
incurred in connection with its underproduced gas imbalance position. Cumulative
total gas sales volumes for underproduced wells were less than Gothic's pro-rata
share of total gas production from these wells by 4,435 mmcf and 4,122 mmcf for
1999 and 2000,
-90-
92
respectively, resulting in prepaid lease operating expenses of $1.5 million and
$1.2 million for 1999 and 2000, respectively, which are included in other assets
in the accompanying balance sheet. The rate used to calculate the deferred
charge is the average annual production costs per mcf.
Gothic has recorded accrued charges for estimated lease operating expenses
incurred in connection with its overproduced gas imbalance position. Cumulative
total gas sales volumes for overproduced wells exceeded Gothic's pro-rata share
of total gas production from these wells by 2,717 mmcf and 2,271 mmcf for 1999
and 2000, respectively, resulting in accrued lease operating expenses of
$897,000 and $681,000 in 1999 and 2000, respectively, which are included in the
gas imbalance liability in the accompanying balance sheet. The rate used to
calculate the accrued liability is the average annual production costs per mcf.
Income Taxes
Gothic applies the provisions of Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes" ("SFAS No. 109"). Under SFAS
No. 109, deferred tax liabilities or assets arise from the temporary differences
between the tax basis of assets and liabilities, and their basis for financial
reporting, and are subject to tests of realizability in the case of deferred tax
assets. A valuation allowance is provided for deferred tax assets to the extent
realization is not judged to be more likely than not.
Loss per Common Share
Loss per common share before extraordinary item and net loss per common
share are computed in accordance with Statement of Financial Accounting
Standards No. 128 ("FAS 128"). Presented on the Consolidated Statement of
Operations is a reconciliation of loss available to common shareholders. There
is no difference between actual weighted average shares outstanding, which are
used in computing basic loss per share, and diluted weighted average shares,
which are used in computing diluted loss per share, because the effect of
outstanding options and warrants would be antidilutive. Warrants and options to
purchase approximately 20,775,000, 19,940,000 and 14,731,000 shares were
outstanding as of December 31, 1998, 1999 and 2000, and were excluded from the
computation of diluted loss per share due to their anti-dilutive impact.
Stock Based Compensation
Gothic applies Accounting Principles Board Opinion No. 25 in accounting for
its stock option plans. Under this standard, no compensation expense is
recognized for grants of options which include an exercise price equal to or
greater than the market price of the stock on the date of grant. Accordingly,
based on Gothic's grants in 1998 and 1999 no compensation expense has been
recognized.
Recently Issued Financial Accounting Pronouncements
In June 1998, the FASB issued Statement No. 133, "Accounting for Derivative
Instruments and Hedging Activities". FAS 133, as amended, is effective for all
fiscal quarters of fiscal years beginning after June 15, 2000 (January 1, 2001
for Gothic). FAS 133 standardizes the accounting for derivative instruments by
requiring that all derivatives be recognized as assets and liabilities and
measured at fair value. Upon the Statement's initial application, all
derivatives are required to be recognized in the statement of financial position
as either assets or liabilities and measured at fair value. In addition, all
existing hedging relationships must be designated, reassessed, documented and
the accounting conformed to the provisions of FAS 133. Gothic had no derivative
instruments outstanding at December 31, 2000, and has not subsequently entered
into any hedging instruments.
2. FINANCING ACTIVITIES
Credit Facility
On April 27, 1998, Gothic Production, with Gothic Energy as guarantor,
entered into a credit facility, with Bank One (the "Credit Facility"). The
Credit Facility consists of a revolving line of credit, with an initial
borrowing base of $25.0 million. Borrowings are limited to being available for
the acquisition and development of natural gas and oil properties, letters of
credit and general corporate purposes. The borrowing base will be redetermined
at least
-91-
93
semi-annually. Upon an amendment to the Credit Facility dated November 15, 2000,
the borrowing base was reduced to $10.75 million and the principal is due at
maturity, January 31, 2001. Interest is payable monthly calculated at the Bank
One base rate, as determined from time to time by Bank One. Gothic may elect to
calculate interest under a London Interbank Offered Rate ("LIBOR") plus 1.5% (or
up to 2.0% in the event the loan balance is greater than 75% of the borrowing
base). Gothic is required to pay a commitment fee on the unused portion of the
borrowing base equal to 1/2 of 1% per annum. Under the Credit Facility, Bank One
holds first priority liens on substantially all of the natural gas and oil
properties of Gothic, whether currently owned or hereafter acquired. As of
December 31, 2000 there were no borrowings outstanding under the Credit
Facility. The Credit Facility was terminated on January 31, 2001.
11 1/8% Senior Secured Notes Due 2005
The 11 1/8% Senior Secured Notes Due 2005 ("Senior Secured Notes") issued
by Gothic Production are fully and unconditionally guaranteed by Gothic Energy.
The aggregate original principal amount of Senior Secured Notes outstanding was
$235.0 million issued under an indenture dated April 21, 1998 (the "Senior Note
Indenture"). The Senior Secured Notes bear interest at 11 1/8% per annum payable
semi-annually in cash in arrears on May 1 and November 1 of each year commencing
November 1, 1998. The Senior Secured Notes mature on May 1, 2005. All of the
obligations of Gothic Production under the Senior Secured Notes are
collateralized by a second priority lien on substantially all of Gothic's
natural gas and oil properties, subject to certain permitted liens.
Gothic may, at its option, at any time on or after May 1, 2002, redeem all
or any portion of the Senior Secured Notes at redemption prices decreasing from
105.563%, if redeemed in the 12-month period beginning May 1, 2002, to 100.00%
if redeemed in the 12-month period beginning May 1, 2004 and thereafter plus, in
each case, accrued and unpaid interest thereon. Notwithstanding the foregoing,
at any time prior to May 1, 2002, Gothic may, at its option, redeem all or any
portion of the Senior Secured Notes at the Make-Whole Price (as defined in the
Senior Note Indenture) plus accrued or unpaid interest to the date of
redemption. In addition, in the event Gothic consummates one or more Equity
Offerings (as defined in the Senior Note Indenture) on or prior to May 1, 2001,
Gothic, at its option, may redeem up to 33 1/3% of the aggregate principal
amount of the Senior Secured Notes with all or a portion of the aggregate net
proceeds received by Gothic from such Equity Offering or Equity Offerings at a
redemption price of 111.125% of the aggregate principal amount of the Senior
Secured Notes so redeemed, plus accrued and unpaid interest thereon to the
redemption date; provided, however, that following such redemption, at least
66 2/3% of the original aggregate principal amount of the Senior Secured Notes
remains outstanding.
Following the occurrence of any Change of Control (as defined in the Senior
Note Indenture), Gothic must offer to repurchase all outstanding Senior Secured
Notes at a purchase price equal to 101% of the aggregate principal amount of the
Senior Secured Notes, plus accrued and unpaid interest to the date of
repurchase. Gothic made a Change of Control offer following the Chesapeake
Merger. The offer terminated on February 22, 2001. Prior to the expiration of
the offer, $1.0 million of the Senior Secured Notes were tendered and purchased
by Gothic.
The Senior Note Indenture under which the Senior Secured Notes were issued
contains certain covenants limiting Gothic with respect to or imposing
restrictions on the incurrence of additional indebtedness, the payment of
dividends, distributions and other restricted payments, including the payment of
dividends and distributions to Gothic Energy and Chesapeake, the sale of assets,
creating, assuming or permitting to exist any liens (with certain exceptions) on
its assets, mergers and consolidations (subject to meeting certain conditions),
sale leaseback transactions, and transactions with affiliates, among other
covenants.
Events of default under the Senior Note Indenture include the failure to
pay any payment of principal or premium when due, failure to pay for 30 days any
payment of interest when due, failure to make any optional redemption payment
when due, failure to perform any covenants relating to mergers or
consolidations, failure to perform any other covenant or agreement not remedied
within 30 days of notice from the Trustee under the Senior Note Indenture or the
holders of 25% in principal amount of the Senior Secured Notes then outstanding,
defaults under other indebtedness of Gothic causing the acceleration of the due
date of such indebtedness having an outstanding principal amount of $10.0
million or more, the failure of Gothic Production to be a wholly owned
subsidiary of Gothic Energy, and certain other bankruptcy and other court
proceedings, among other matters.
-92-
94
14 1/8% Senior Secured Discount Notes Due 2006
The 14 1/8% Senior Secured Discount Notes Due 2006 (the "Discount Notes")
were issued by Gothic Energy under an indenture (the "Discount Note Indenture")
dated April 21, 1998 in such aggregate principal amount and at such rate of
interest as generated gross proceeds of $60.2 million. Gothic also issued
seven-year warrants to purchase, at an exercise price of $2.40 per share,
825,000 shares of Gothic Energy's common stock with the Discount Notes. The
estimated fair value of such warrants was approximately $554,000 on the date of
issuance. The Discount Notes were issued at a substantial discount from their
principal amount and accrete at a rate per annum of 14 1/8%, compounded
semi-annually, to an aggregate principal amount of $104.0 million at May 1,
2002. Thereafter, the Discount Notes accrue interest at the rate of 14 1/8% per
annum, payable in cash semi-annually in arrears on May 1 and November 1 of each
year, commencing November 1, 2002. The Discount Notes mature on May 1, 2006 and
are collateralized by a first priority lien against the outstanding shares of
capital stock of Gothic Production. The carrying amount of the Discount Notes as
of December 31, 2000 was $86.7 million.
Gothic may, at its option, at any time on or after May 1, 2003, redeem all
or any portion of the Discount Notes at redemption prices decreasing from
107.063% if redeemed in the 12-month period beginning May 1, 2003 to 100.00% if
redeemed in the 12-month period beginning May 1, 2005 and thereafter plus, in
each case, accrued and unpaid interest thereon. Notwithstanding the foregoing,
at any time prior to May 1, 2003, Gothic may, at its option, redeem all or any
portion of the Discount Notes at the Make-Whole Price (as defined in the
Discount Note Indenture) plus accrued or unpaid interest to the date of
redemption.
3. STOCKHOLDERS' EQUITY
In January 1999, Gothic Energy issued 30,000 shares of its common stock as
part of a severance package to a former employee. On August 17, 1999, Chesapeake
fully exercised the common stock purchase warrant issued to it in April 1998 and
purchased 2,394,125 shares of Gothic Energy's common stock. The warrant had been
issued to Chesapeake as part of the transaction involving the sale to Chesapeake
of shares of Gothic Energy's Series B Senior Redeemable Preferred Stock, a 50%
interest in Gothic's Arkoma basin natural gas and oil properties and a 50%
interest in substantially all of Gothic's undeveloped acreage. The shares were
issued pursuant to the cashless exercise provisions of the warrant that
permitted Chesapeake to surrender the right to exercise the warrant for a number
of shares of Gothic Energy's common stock having a market value equivalent to
the total exercise price. The total exercise price was $23,941.25 or $0.01 per
share. An aggregate of 45,121 warrants were surrendered in payment of the total
exercise price. The shares of common stock were issued pursuant to the exemption
from the registration requirements of the Securities Act of 1933, as amended,
afforded by section 4(2) thereof.
In July 2000, Gothic Energy issued 225,000 shares of its common stock to
one director and certain employees upon their exercise of stock options.
In July 2000, Gothic Energy issued 233,000 shares of its common stock to
two warrant holders upon the exercise of outstanding common stock purchase
warrants.
In August 2000, Gothic Energy issued 4,161,000 shares of its common stock
to certain employees, two officers and two directors, upon their exercise of
stock options. The directors, officers and employees issued full recourse
interest bearing promissory notes, due one year from the date of issuance, upon
exercise of the stock options. All of these notes were paid in full prior to
January 31, 2001.
Preferred Stock
On April 27, 1998, as part of a recapitalization, Gothic Energy issued
50,000 shares of Series B Preferred Stock with an aggregate liquidation
preference of $50.0 million and a warrant to purchase 2,439,246 shares of Gothic
Energy's common stock, discussed above. The estimated fair value of such warrant
was $4.9 million on the date of issuance. The Series B Preferred Stock, with
respect to dividend rights and rights on liquidation, winding-up and
dissolution, ranks senior to all classes of common stock of Gothic Energy and
senior to all other classes or series of any class of preferred stock. Holders
of the Series B Preferred Stock are entitled to receive dividends payable at a
rate per annum of 12% of the aggregate liquidation preference of the Series B
Preferred Stock payable in additional shares of Series B Preferred Stock;
provided that after April 1, 2000, at Gothic Energy's option, it may pay the
-93-
95
dividends in cash. Dividends are cumulative and will accrue from the date of
issuance and are payable quarterly in arrears.
At any time prior to April 30, 2000, the Series B Preferred Stock may have
been redeemed at the option of Gothic Energy in whole or in part, at 105% of the
liquidation preference payable in cash out of the net proceeds from a public or
private offering of any equity security, plus accrued and unpaid dividends
(whether or not declared), which shall also be paid in cash. At any time on or
after April 30, 2000, the Series B Preferred Stock may have been redeemed at the
option of Gothic Energy in whole or in part, in cash at a redemption price equal
to the liquidation preference.
Gothic Energy is required to redeem the Series B Preferred Stock on June
30, 2008 at a redemption price equal to the liquidation preference payable in
cash or, at the option of Gothic Energy, in shares of common stock valued at the
fair market value at the date of such redemption.
Except as required by Oklahoma law, the holders of Series B Preferred Stock
are not entitled to vote on any matters submitted to a vote of the stockholders
of Gothic Energy.
The Series B Preferred Stock is convertible at the option of the holders on
or after April 30, 2000 into the number of fully paid and non-assessable shares
of common stock determined by dividing the liquidation preference by the higher
of (i) $2.04167 or (ii) the fair market value on the date the Series B Preferred
Stock is converted. Notwithstanding the foregoing, no holder or group shall be
able to convert any shares of Series B Preferred Stock to the extent that the
conversion of such shares would cause such holder or group to own more than
19.9% of the outstanding common stock of Gothic Energy.
The Series B Preferred Stock, all of which was owned by Chesapeake prior to
the Merger, remains outstanding. As part of the Merger, the terms of the Series
B Preferred Stock were amended to provide for noncumulative cash dividends of
$80 per share per annum if, as and when declared by the Board of Directors,
optional redemption rights permitting Gothic Energy to redeem the shares at any
time or from time to time, and mandatory redemption for cash on June 30, 2008.
The amendment also eliminated conversion rights.
Other Warrants
In connection with past financing arrangements and as compensation for
consulting and professional services, Gothic Energy has issued other warrants to
purchase its common stock.
A summary of the status of Gothic Energy's warrants as of December 31,
1997, 1998, 1999 and 2000, and changes during the years ended December 31, 1998,
1999 and 2000 is presented below:
NUMBER WEIGHTED NUMBER WEIGHTED AVERAGE
OUTSTANDING AVERAGE PRICE EXERCISABLE EXERCISE PRICE
----------- ------------- ----------- ----------------
Balance at December 31, 1997....................... 11,404,531 $2.54 11,404,531 $2.54
Warrants granted................................... 5,940,024 1.06
----------
Balance at December 31, 1998....................... 17,344,555 $2.00 17,344,555 $2.00
Warrants exercised/expired......................... (2,639,246) 0.20
----------
Balance at December 31, 1999....................... 14,705,309 $2.33 14,705,309 $2.33
Warrants exercised/expired....................... (1,233,121) 2.20
Warrants adjusted for antidilution............... 524,109 --
----------
Balance at December 31, 2000....................... 13,996,297 $2.40 13,996,297 $2.40
==========
The following table summarizes information about Gothic Energy's warrants,
which were outstanding, and those which were exercisable, as of December 31,
2000:
WARRANTS OUTSTANDING WARRANTS EXERCISABLE
------------------------------------------ ---------------------------
PRICE NUMBER WEIGHTED WEIGHTED NUMBER WEIGHTED
RANGE OUTSTANDING AVERAGE LIFE AVERAGE PRICE EXERCISABLE AVERAGE PRICE
----- ----------- ------------ ------------- ----------- -------------
$1.78 -- $3.00 13,996,297 1.1 years $2.40 13,996,297 $2.40
-94-
96
4. STOCK OPTIONS
Incentive Stock Option Plan
Gothic Energy has an incentive stock option and non-statutory option plan,
which provides for the issuance of options to purchase up to 2,500,000 shares of
common stock to key employees and directors. The incentive stock options granted
under the Plan are generally exercisable for a period of ten years from the date
of the grant, except that the term of an incentive stock option granted under
the Plan to a stockholder owning more than 10% of the outstanding common stock
must not exceed five years and the exercise price of an incentive stock option
granted to such a stockholder must not be less than 110% of the fair market
value of the common stock on the date of grant. The exercise price of a
non-qualified option granted under the Plan may not be less than 40% of the fair
market value of the common stock at the time the option is granted. No
non-qualified options have been issued under the Plan. As of December 31, 1998
and 1999, options to purchase 2,095,000 and 2,500,000 shares of common stock,
respectively, had been issued under the Plan. As of December 31, 2000, all
options granted under the Plan had been exercised.
Omnibus Incentive Plan
On August 13, 1996 at the annual shareholders' meeting, the shareholders
approved the 1996 Omnibus Incentive Plan and the 1996 Non-Employee Stock Option
Plan. The 1996 Omnibus Incentive Plan provides for compensatory awards of up to
an aggregate of 1,000,000 shares of common stock of Gothic Energy to officers,
directors and certain other key employees. Awards may be granted for no
consideration and consist of stock options, stock awards, stock appreciation
rights, dividend equivalents, other stock-based awards (such as phantom stock)
and performance awards consisting of any combination of the foregoing.
Generally, options will be granted at an exercise price equal to the lower of
(i) 100% of the fair market value of the shares of common stock on the date of
grant or (ii) 85% of the fair market value of the shares of common stock on the
date of exercise. Each option will be exercisable for the period or periods
specified in the option agreement, which will generally not exceed 10 years from
the date of grant. As of December 31, 1999, options to purchase 1,000,000 shares
of common stock had been issued under the Omnibus Incentive Plan. As of December
31, 2000, all options granted under the Omnibus Incentive Plan had been
exercised.
Non-Employee Stock Option Plan
The 1996 Non-Employee Stock Option Plan provides a means by which
non-employee directors of Gothic and consultants to Gothic can be given an
opportunity to purchase stock in Gothic Energy. The plan provides that a total
of 1,000,000 shares of Gothic Energy's common stock may be issued pursuant to
options granted under the Non-Employee Plan, subject to certain adjustments. The
exercise price for each option granted under the Non-Employee Plan will not be
less than the fair market value of the common stock on the date of grant. Each
option will be exercisable for the period or periods specified in the option
agreement, which can not exceed 10 years from the date of grant. Options granted
to directors will terminate thirty (30) days after the date the director is no
longer a director of Gothic. As of December 31, 1998 and 1999, options to
purchase 600,000 and 1,000,000 shares of common stock, respectively, had been
issued under the Non-Employee Plan. As of December 31, 2000, all options granted
under the Non-Employee Plan had been exercised.
-95-
97
A summary of the status of Gothic Energy's stock options as of December 31,
1997, 1998, 1999 and 2000, and changes during December 31, 1998, 1999 and 2000,
is presented below:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
---------------------------- ----------------------------
NUMBER WEIGHTED NUMBER WEIGHTED
OUTSTANDING AVERAGE PRICE EXERCISABLE AVERAGE PRICE
----------- ------------- ----------- -------------
Balance at December 31, 1997........................... 2,690,000 $ 1.17 1,850,000 $1.52
Options granted........................................ 1,285,000 .40
Options forfeited...................................... (545,000) .40
----------
Balance at December 31, 1998........................... 3,430,000 $ 1.00 1,927,500 $1.47
Options granted...................................... 2,185,000 .39
Options forfeited.................................... (380,000) .40
----------
Balance at December 31, 1999........................... 5,235,000 $ .79 2,807,500 $1.13
Options exercised.................................... (4,390,000) .15-.53
Options forfeited.................................... (110,000) .40
----------
Balance at December 31, 2000........................... 735,000 $ 3.21 735,000 $3.21
==========
The following table summarizes information about Gothic Energy's stock
options which were outstanding, and those which were exercisable, as of December
31, 2000:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------ ---------------------------
PRICE NUMBER WEIGHTED WEIGHTED NUMBER WEIGHTED
RANGE OUTSTANDING AVERAGE LIFE AVERAGE PRICE EXERCISABLE AVERAGE PRICE
----- ----------- ------------ ------------- ----------- -------------
$1.50 -- $3.30 735,000 0.3 years $3.21 735,000 $3.21
Gothic applies Accounting Principles Board Opinion No. 25 in accounting for
stock options granted to employees, including directors, and Statement of
Financial Accounting Standards No. 123 ("SFAS No. 123") for stock options and
warrants granted to non-employees. No compensation cost has been recognized in
1998, 1999 or 2000.
Had compensation been determined on the basis of fair value pursuant to
SFAS No. 123, net loss and loss per share would have been increased as follows:
1998 1999 2000
---------- --------- --------
($ IN THOUSANDS, EXCEPT PER SHARE
DATA)
Net loss available for common shares:
As reported............................................... $(140,383) $(25,976) $(3,445)
========= ======== =======
Pro forma................................................. $(141,232) $(26,439) $(3,751)
========= ======== =======
Basic and diluted loss per share:
As reported............................................... $ (8.63) $ (1.51) $ (0.17)
========= ======== =======
Pro forma................................................. $ (8.68) $ (1.54) $ (0.18)
========= ======== =======
The fair value of each option granted is estimated using the Black Scholes
model. Gothic's stock volatility was 0.81 and 0.95 in 1998 and 1999,
respectively, based on previous stock performance. Dividend yield was estimated
to remain at zero with an average risk-free interest rate of 4.81 percent and
5.59 percent in 1998 and 1999, respectively. Expected life was three years for
options issued in both 1998 and 1999 based on the vesting periods involved and
the make up of participating employees within each grant. Fair value of options
granted during 1998 and 1999 under the Stock Option Plan were $643,000 and
$646,000, respectively. No options were granted during 2000. As part of the
Merger, all plans terminated on January 16, 2001.
-96-
98
5. INCOME TAXES
A reconciliation of the income tax expense or benefit, computed by applying
the federal statutory rate to pre-tax income or loss, to Gothic's effective
income tax expense or benefit is as follows:
1998 1999 2000
-------- ------- -------
($ IN THOUSANDS)
Income tax (expense) benefit computed at the statutory rate
(34%)..................................................... $ 44,094 $ 5,885 $(2,068)
State income taxes, net of federal.......................... 5,135 685 (260)
Change in valuation allowance............................... (49,229) (6,570) 2,555
Other....................................................... -- -- (227)
-------- ------- -------
Income tax (expense) benefit................................ -- -- --
======== ======= =======
Deferred tax assets and liabilities are comprised of the following at
December 31, 1999 and 2000:
1999 2000
-------- --------
($ IN THOUSANDS)
Deferred tax assets:
Gas balancing liability................................... $ 1,386 $ 1,077
Net operating loss carryforwards.......................... 68,448 68,436
Depletion carryforwards................................... 257 257
Tax over book basis of property and equipment............. 2,627 426
Accrued wages............................................. 119 --
-------- --------
Gross deferred tax assets................................. 72,837 70,196
Deferred tax liabilities:
Deferred lease operating expenses......................... (556) (470)
-------- --------
Gross deferred tax liabilities............................ (556) (470)
Net deferred tax assets..................................... 72,281 69,726
Valuation allowance....................................... (72,281) (69,726)
-------- --------
-- --
======== ========
Net operating losses of approximately $180.3 million are available for
future use against taxable income. These net operating loss carryforwards
("NOL") expire in the years 2010 through 2019.
Pursuant to Section 382 of the Internal Revenue Code of 1986, as amended,
in the event that a substantial change in the ownership of Gothic Energy were to
occur in the future (whether through the sale of stock by a significant
shareholder or shareholders, new issuances of stock by Gothic Energy,
conversions, a redemption, recapitalization, reorganization, any combination of
the foregoing or any other method) so that ownership of more than 50% of the
value of Gothic Energy's capital stock changed during any three-year period,
Gothic Energy's ability to utilize its NOLs could be substantially limited.
Realization of the net deferred tax asset is dependent on generating
sufficient taxable income in future periods. As a result of significant losses
in prior years, Gothic has recorded a 100% valuation allowance, as management
presently deems it is more likely than not that realization will not occur in
the future.
6. COMMITMENTS AND CONTINGENCIES
Gothic entered into an employment agreement with its President effective
January 1, 1999. The President received a base salary of $225,000 per year. In
addition, he was to receive a cash bonus as was determined by Gothic's Board of
Directors. The President was also entitled to participate in such incentive
compensation and benefit programs as Gothic made available. The term of the
agreement was for a period of three years and at the end of the first year and
at the end of each succeeding year the agreement was automatically extended for
one year such that at the end of each year there would automatically be three
years remaining on the term of the agreement. The President could terminate the
agreement at the end of the initial term and any succeeding term on not less
than six months notice. In the event the employment agreement was terminated by
Gothic (other than for cause, as defined), the President was entitled to receive
a payment representing all salary due under the remaining full term of his
agreement and Gothic was obligated to continue his medical insurance and other
benefits provided under the
-97-
99
agreement in effect for a period of one year after such termination. In the
event of a change in control, as defined, of Gothic, the President had the right
to terminate his employment agreement with Gothic within sixty days thereafter,
whereupon Gothic would be obligated to pay to him a sum equal to three years of
his base salary under the agreement, plus a lump sum payment of $250,000. The
President resigned from Gothic effective January 16, 2001, upon completion of
the Chesapeake Merger.
Gothic also entered into an employment agreement with its Chief Financial
Officer effective January 1, 1999. The Chief Financial Officer received a base
salary of $187,500 per year. In addition, he was to receive a cash bonus as was
determined by Gothic's Board of Directors. The CFO was also entitled to
participate in such incentive compensation and benefit programs as Gothic made
available. The term of the agreement was for a period of three years and at the
end of the first year and at the end of each succeeding year the agreement was
automatically extended for one year such that at the end of each year there
would automatically be three years remaining on the term of the agreement. The
CFO could terminate the agreement at the end of the initial term and any
succeeding term on not less than six months notice. In the event the employment
agreement was terminated by Gothic (other than for cause, as defined), the CFO
was entitled to receive a payment representing all salary due under the
remaining full term of his agreement, and Gothic was obligated to continue his
medical insurance and other benefits provided under the agreement in effect for
a period of one year after such termination. In the event of a change in
control, as defined, of Gothic, the CFO had the right to terminate his
employment with Gothic within sixty days thereafter, whereupon Gothic would be
obligated to pay to him a sum equal to three years base salary, plus a lump sum
payment of $200,000. The Chief Financial Officer resigned from Gothic effective
January 16, 2001, upon completion of the Chesapeake Merger.
The above employment agreements were amended in connection with the Merger
whereby the executives each received a severance payment equal to their year
2000 base salary, and entered into consulting and non-compete agreements with
Chesapeake.
Gothic leases its corporate offices and certain office equipment and
automobiles under non-cancelable operating leases. Rental expense under
non-cancelable operating leases was $190,000, $240,000 and $345,000 for the
years ended December 31, 1998, 1999 and 2000, respectively.
Remaining minimum annual rentals under non-cancelable lease agreements
subsequent to December 31, 2000 are as follows:
2001........................................................ $295,000
2002........................................................ $282,000
2003........................................................ $267,000
2004........................................................ $247,000
Gothic is not a defendant in any pending legal proceedings other than
routine litigation incidental to its business. While the ultimate results of
these proceedings cannot be predicted with certainty, Gothic does not believe
that the outcome of these matters will have a material adverse effect on
Gothic's financial position or results of operations.
7. BENEFIT PLAN
Gothic maintained a 401(k) plan for the benefit of its employees. The plan
was implemented in October 1997. The plan permitted employees to make
contributions on a pre-tax salary reduction basis. Gothic made limited matching
contributions to the plan, and also made other discretionary contributions.
Gothic's contributions for 1998, 1999 and 2000 were $62,000, $85,000 and
$81,000, respectively. The plan was terminated in December 2000.
8. MAJOR CUSTOMERS
During the year ended December 31, 2000, Gothic was a party to contracts
whereby it sold approximately 60% of its natural gas production to CMS
Continental Natural Gas Corporation ("Continental"), and approximately 64% of
its oil production to Duke Energy, Inc. Gothic has a ten-year marketing
agreement, whereby the majority of the natural gas associated with properties
acquired from Amoco in January 1998 will be sold to Continental, at market
prices, under this agreement.
-98-
100
9. RELATED PARTY TRANSACTIONS
During 1997, Gothic made advances totaling $336,000 to two officers and
directors of Gothic. In February 1998, $168,000 was received in connection with
a severance agreement. The balance outstanding on the remaining advance was
$179,000 as of December 31, 1998. This amount was forgiven by Gothic during
1999.
During 2000, Gothic made advances to directors, officers and employees
totaling $1.7 million for the exercise of options to purchase Gothic common
stock. These amounts were settled in connection with the Merger on January 16,
2001.
10. SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Summarized quarterly financial information for 1999 and 2000 is as follows:
THREE MONTHS ENDED
--------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
($ IN THOUSANDS, EXCEPT PER SHARE DATA)
Year Ended December 31, 1999:
Revenues.................................................. $11,470 $13,206 $14,150 $16,798
------- ------- ------- -------
Gross profit(1)........................................... $ 3,846 $5,577 $ 6,217 $ 9,410
------- ------- ------- -------
Net loss.................................................. $(5,621) $(4,850) $(4,296) $(2,542)
------- ------- ------- -------
Loss per common share:(2)
Basic................................................... $ (0.47) $(0.43) $ (0.37) $ (0.26)
------- ------- ------- -------
Diluted................................................. $ (0.47) $(0.43) $ (0.37) $ (0.26)
------- ------- ------- -------
Year Ended December 31, 2000:
Revenues.................................................. $15,559 $17,660 $21,904 $30,622
------- ------- ------- -------
Gross profit(1)........................................... $ 8,334 $10,467 $12,920 $19,603
------- ------- ------- -------
Net income (loss)......................................... $(2,883) $ (517) $ 1,325 $ 8,157
------- ------- ------- -------
Earnings (loss) per common share:(2)
Basic................................................... $ (0.28) $(0.15) $ (0.05) $ 0.24
------- ------- ------- -------
Diluted................................................. $ (0.28) $(0.15) $ (0.05) $ 0.24
------- ------- ------- -------
---------------
(1) Gross profit includes total revenues, less lease operating expenses and
depletion, depreciation and amortization expense.
(2) As a result of shares issued during the year, earnings per share for the
year's four quarters, which is based on average shares outstanding during
each quarter, does not equal the annual earnings per share, which is based
on the average shares outstanding during the year.
11. SUPPLEMENTARY NATURAL GAS AND OIL INFORMATION
The following supplemental historical and reserve information is presented
in accordance with Financial Accounting Standards Board Statement No. 69,
"Disclosures About Oil and Gas Producing Activities".
FINANCIAL DATA
Capitalized Costs
The aggregate amounts of capitalized costs relating to natural gas and oil
producing activities, net of valuation allowances, and the aggregate amounts of
the related accumulated depreciation, depletion, and amortization at December
31, 1999 and 2000 were as follows:
1999 2000
-------- --------
($ IN THOUSANDS)
Proved properties........................................... $258,818 $275,827
Unproved, not subject to depreciation, depletion and
amortization.............................................. 5,473 6,191
Less accumulated depreciation, depletion, and
amortization.............................................. (53,137) (75,003)
-------- --------
Net natural gas and oil properties...................... $211,154 $207,015
======== ========
-99-
101
Costs Incurred
Costs incurred in natural gas and oil property acquisition, exploration and
development activities for the years ended December 31, 1998, 1999 and 2000 were
as follows:
1998 1999 2000
-------- ------- -------
($ IN THOUSANDS)
Proved property acquisition................................. $225,103 $ 1,499 $ 655
Unproved property acquisition............................... 2,109 2,611 718
Development costs........................................... 16,270 18,445 18,535
-------- ------- -------
Total costs incurred.................................... $243,482 $22,555 $19,908
======== ======= =======
RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Gothic's results of operations from natural gas and oil producing
activities are presented below for 1998, 1999 and 2000. The following table
includes revenues and expenses associated directly with Gothic's natural gas and
oil producing activities.
1998 1999 2000
-------- -------- --------
($ IN THOUSANDS)
Oil and gas sales........................................... $ 50,714 $ 52,967 $ 83,065
Production expenses......................................... (8,608) (5,725) (5,234)
Production taxes............................................ (3,521) (3,880) (6,566)
Impairment of oil and gas properties........................ (76,000) -- --
Depletion and depreciation.................................. (24,001) (20,969) (22,621)
-------- -------- --------
Results of operations from oil and gas producing
activities................................................ $(61,416) $ 22,393 $ 48,644
======== ======== ========
NATURAL GAS AND OIL RESERVES DATA (UNAUDITED)
Estimated Quantities
Natural gas and oil reserves cannot be measured exactly. Estimates of
natural gas and oil reserves require extensive judgments of reservoir
engineering data and are generally less precise than other estimates made in
connection with financial disclosures.
Proved reserves are those quantities which, upon analysis of geological and
engineering data, appear with reasonable certainty to be recoverable in the
future from known natural gas and oil reservoirs under existing economic and
operating conditions. Proved developed reserves are those reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods. Proved undeveloped reserves are those reserves which are
expected to be recovered from new wells on undrilled acreage or from existing
wells where a relatively major expenditure is required.
Estimates of natural gas and oil reserves require extensive judgments of
reservoir engineering data as explained above. Assigning monetary values to such
estimates does not reduce the subjectivity and changing nature of such reserve
estimates. Indeed, the uncertainties inherent in the disclosure are compounded
by applying additional estimates of the rates and timing of production and the
costs that will be incurred in developing and producing the reserves. The
information set forth herein is therefore subjective and, since judgments are
involved, may not be comparable to estimates submitted by other natural gas and
oil producers. In addition, since prices and costs do not remain static and no
price or cost escalations or de-escalations have been considered, the results
are not necessarily indicative of the estimated fair market value of estimated
proved reserves nor of estimated future cash flows and significant revisions
could occur in the near term. Accordingly, these estimates are expected to
change as future information becomes available. All of Gothic's reserves are
located onshore in the states of Oklahoma, Texas, New Mexico, Arkansas and
Kansas.
-100-
102
The following unaudited table, which is based on reports of Lee Keeling and
Associates, Inc., sets forth proved natural gas and oil reserves:
1998 1999 2000
----------------- ---------------- ----------------
MBBLS MMCF MBBLS MMCF MBBLS MMCF
------ ------- ----- ------- ----- -------
Proved Reserves:
Beginning of year.................................... 3,585 127,460 1,761 306,668 1,922 289,191
Revisions of previous estimates...................... (872) 39,577 319 6,598 50 32,051
Purchases of reserves in place....................... 1,362 233,007 -- 1,402 -- 172
Production........................................... (257) (24,455) (158) (25,477) (135) (26,309)
Sales of reserves in place........................... (2,057) (68,921) -- -- (69) (4,198)
------ ------- ----- ------- ----- -------
End of year.......................................... 1,761 306,668 1,922 289,191 1,768 290,907
====== ======= ===== ======= ===== =======
Proved Developed:
Beginning of year.................................... 2,503 91,690 1,523 254,762 1,683 251,631
End of year.......................................... 1,523 254,762 1,683 251,631 1,567 245,472
Standardized Measure of Discounted Future Net Cash Flows
Future net cash inflows are based on the future production of proved
reserves of natural gas and crude oil as estimated by Lee Keeling and
Associates, Inc., independent petroleum engineers, by applying current prices of
natural gas and oil to estimated future production of proved reserves. The
average prices used in determining future cash inflows for natural gas and oil
as of December 31, 2000, were $10.19 per mcf, and $26.54 per barrel,
respectively. These prices were based on the adjusted cash spot price for
natural gas and oil at December 31, 2000. These prices are significantly higher
than the average natural gas and oil price ($5.88 per mcf and $25.00 per barrel)
received by Gothic during December 2000, and the prices Gothic expects to
receive during 2001. Future net cash flows are then calculated by reducing such
estimated cash inflows by the estimated future expenditures (based on current
costs) to be incurred in developing and producing the proved reserves and by the
estimated future income taxes.
Estimated future income taxes are computed by applying the appropriate
year-end statutory tax rate to the future pretax net cash flows relating to
Gothic's estimated proved natural gas and oil reserves. The estimated future
income taxes give effect to permanent differences and tax credits and
allowances.
Included in the estimated standardized measure of future cash flows are
certain capital projects (future development costs). Gothic estimates the
capital required to develop its undeveloped natural gas and oil reserves during
2001 to be approximately $30.0 million. If such capital is not employed, the
estimated future cash flows will be negatively impacted.
The following table sets forth Gothic's unaudited estimated standardized
measure of discounted future net cash flows.
FOR THE YEARS ENDED DECEMBER 31,
------------------------------------
1998 1999 2000
--------- --------- ----------
($ IN THOUSANDS)
Cash Flows Relating to Proved Reserves:
Future cash inflows....................................... $ 573,604 $ 596,216 $3,005,450
Future production costs................................... (141,253) (139,458) (350,371)
Future development costs.................................. (37,028) (26,969) (42,260)
Future income tax expense................................. (47,264) (30,113) (843,629)
--------- --------- ----------
348,059 399,676 1,769,190
Ten percent annual discount factor........................ (169,297) (201,291) (911,617)
--------- --------- ----------
Standardized measure of discounted future net cash
flows................................................... $ 178,762 $ 198,385 $ 857,573
========= ========= ==========
-101-
103
The following table sets forth changes in the standardized measure of
discounted future net cash flows:
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1998 1999 2000
-------- -------- --------
($ IN THOUSANDS)
Standardized measure of discounted future cash
flows-beginning of period................................. $ 94,102 $178,762 $198,385
Sales of natural gas and oil produced, net of operating
expenses.................................................. (38,585) (43,362) (71,265)
Purchases of reserves-in-place.............................. 231,184 1,000 114
Sales of reserves-in-place.................................. (62,933) -- (3,815)
Revisions of previous quantity estimates and changes in
sales prices and production costs......................... (54,416) 44,109 714,315
Accretion of discount....................................... 9,410 17,876 19,839
-------- -------- --------
Standardized measure of discounted future cash flows-end of
period.................................................... $178,762 $198,385 $857,573
======== ======== ========
-102-
104
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information called for by this Item 10 is incorporated herein by
reference to the definitive Proxy Statement to be filed by Chesapeake pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 30, 2001.
ITEM 11. EXECUTIVE COMPENSATION
The information called for by this Item 11 is incorporated herein by
reference to the definitive Proxy Statement to be filed by Chesapeake pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 30, 2001.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information called for by this Item 12 is incorporated herein by
reference to the definitive Proxy Statement to be filed by Chesapeake pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 30, 2001.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by this Item 13 is incorporated herein by
reference to the definitive Proxy Statement to be filed by Chesapeake pursuant
to Regulation 14A of the General Rules and Regulations under the Securities
Exchange Act of 1934 not later than April 30, 2001.
-103-
105
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements. Chesapeake's consolidated financial statements,
Gothic's consolidated financial statements and pro forma combined financial
statements are included in Item 8 of this report. Reference is made to the
accompanying Index to Financial Statements.
2. Financial Statement Schedules. Schedule II is included in Item 8 of
this report with our consolidated financial statements. No other financial
statement schedules are applicable or required.
3. Exhibits. The following exhibits are filed herewith pursuant to the
requirements of Item 601 of Regulation S-K:
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.1 -- Senior Secured Discount Notes Purchase Agreement dated June
23, 2000 between Chesapeake Energy Marketing, Inc. and
Appaloosa Investment Limited Partnership I, Palomino Fund
Ltd. and Tersk L.L.C. Incorporated herein by reference to
Exhibit 2.1 to Registrant's Form S-1 Registration Statement
(No. 333-41014).
2.2 -- Senior Secured Discount Notes Purchase Agreement dated June
23, 2000 between Chesapeake Energy Marketing, Inc. and
Oppenheimer Strategic Income Fund, Oppenheimer Champion
Income Fund, Oppenheimer High Yield Fund, Oppenheimer
Strategic Bond Fund/VA and Atlas Strategic Income Fund.
Incorporated herein by reference to Exhibit 2.2 to
Registrant's Form S-1 Registration Statement (No.
333-41014).
2.3 -- Senior Secured Discount Notes Purchase Agreement dated June
26, 2000 between Chesapeake Energy Marketing, Inc. and John
Hancock High Yield Bond Fund and John Hancock Variable
Annuity High Yield Bond Fund. Incorporated herein by
reference to Exhibit 2.3 to Registrant's Form S-1
Registration Statement (No. 333-41014).
2.4 -- Senior Secured Discount Notes Purchase Agreement dated June
26, 2000 between Chesapeake Energy Marketing, Inc. and
Ingalls & Snyder Value Partners, L.P., Heritage Mark
Foundation and Arthur R. Ablin. Incorporated herein by
reference to Exhibit 2.4 to Registrant's Form S-1
Registration Statement (No. 333-41014).
2.5 -- Senior Secured Discount Notes Purchase Agreement dated
August 29, 2000 between Chesapeake Energy Marketing, Inc.
and BNP Paribas. Incorporated herein by reference to Exhibit
2.5 to Registrant's registration statement on Form S-1 (No.
333-45872).
2.6 -- Senior Secured Notes Purchase Agreement dated September 1,
2000 between Chesapeake Energy Corporation and Lehman
Brothers Inc. Incorporated herein by reference to Exhibit
2.6 to Registrant's registration statement on Form S-1 (No.
333-45872).
2.7 -- Agreement and Plan of Merger dated September 8, 2000 among
Chesapeake Energy Corporation, Chesapeake Merger 2000 Corp.
and Gothic Energy Corporation, as amended by Amendment No. 1
to Agreement and Plan of Merger dated October 31, 2000.
Incorporated by reference to Annex A to proxy
statement/prospectus included in Amendment No. 1 to
Registrant's registration statement on Form S-4 (No.
333-47330).
3.1 -- Registrant's Certificate of Incorporation as amended.
Incorporated herein by reference to Exhibit 3.1 to
Registrant's registration statement on Form S-1 (No.
333-45872).
3.2 -- Registrant's Bylaws. Incorporated herein by reference to
Exhibit 3.2 to Registrant's registration statement on Form
8-B (No. 001-13726).
-104-
106
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.1 -- Indenture dated as of March 15, 1997 among the Registrant,
as issuer, Chesapeake Operating, Inc., Chesapeake Gas
Development Corporation and Chesapeake Exploration Limited
Partnership, as Subsidiary Guarantors, and United States
Trust Company of New York, as Trustee, with respect to
7.875% Senior Notes due 2004. Incorporated herein by
reference to Exhibit 4.1 to Registrant's registration
statement on Form S-4 (No. 333-24995). First Supplemental
Indenture dated December 17, 1997 and Second Supplemental
Indenture dated February 16, 1998. Incorporated herein by
reference to Exhibit 4.1.1 to Registrant's transition report
on Form 10-K for the six months ended December 31, 1997.
Second [Third] Supplemental Indenture dated April 22, 1998.
Incorporated herein by reference to Exhibit 4.1.1 to
Registrant's Amendment No. 1 to Form S-3 registration
statement (No. 333-57235). Fourth Supplemental Indenture
dated July 1, 1998. Incorporated herein by reference to
Exhibit 4.1.1 to Registrant's quarterly report on Form 10-Q
for the quarter ended September 30, 1998.
4.2 -- Indenture dated as of March 15, 1997 among the Registrant,
as issuer, Chesapeake Operating, Inc., Chesapeake Gas
Development Corporation and Chesapeake Exploration Limited
Partnership, as Subsidiary Guarantors, and United States
Trust Company of New York, As Trustee, with respect to 8.5%
Senior Notes due 2012. Incorporated herein by reference to
Exhibit 4.1.3 to Registrant registration statement on Form
S-4 (No. 333-24995). First Supplemental Indenture dated
December 17, 1997 and Second Supplemental Indenture dated
February 16, 1998. Incorporated herein by reference to
Exhibit 4.2.1 to Registrant's transition report on Form 10-K
for the six months ended December 31, 1997. Second [Third]
Supplemental Indenture dated April 22, 1998. Incorporated
herein by reference to Exhibit 4.2.1 to Registrant's
Amendment No. 1 to Form S-3 registration statement (No.
333-57235). Fourth Supplemental Indenture dated July 1,
1998. Incorporated herein by reference to Exhibit 4.2.1 to
Registrant's quarterly report on Form 10-Q for the quarter
ended September 30, 1998.
4.3 -- Indenture dated as of April 1, 1998 among the Registrant, as
Subsidiary Guarantors, and United States Trust Company of
New York, As Trustee, with respect to 9.625% Senior Notes
due 2005. Incorporated herein by reference to Exhibit 4.3 to
Registrant registration statement on Form S-3 (No.
333-57235). First Supplemental Indenture dated July 1, 1998.
Incorporated herein by reference to Exhibit 4.4.1 to
Registrant's quarterly report on Form 10-Q for the quarter
ended September 30, 1998.
4.4 -- Indenture dated as of April 1, 1996 among the Registrant,
its subsidiaries signatory thereto, as Subsidiary
Guarantors, and United States Trust Company of New York, as
Trustee, with respect to 9.125% Senior Notes, due 2006.
Incorporated herein by reference to Exhibit 4.6 to
Registrant's registration statement on Form S-3 (No.
333-1588). First Supplemental Indenture dated December 30,
1996 and Second Supplemental Indenture dated December 17,
1997. Incorporated herein by reference to Exhibit 4.4.1 to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997. Third Supplemental Indenture
dated April 22, 1998. Incorporated herein by reference to
Exhibit 4.4.1 to Registrant's Amendment No. 1 to Form S-3
registration statement (No. 333-57235). Fourth Supplemental
Indenture dated July 1, 1998. Incorporated herein by
reference to Exhibit 4.3.1 to Registrant's quarterly report
on Form 10-Q for the quarter ended September 30, 1998.
4.5 -- Agreement to furnish copies of unfiled long-term debt
Instruments. Incorporated herein by reference to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997.
4.7 -- Common Stock Registration Rights Agreement dated as of June
27, 2000 among the Registrant and Appaloosa Investment
Limited Partnership I, Palomino Fund Ltd., Tersk L.L.C.,
Oppenheimer Strategic Income Fund, Oppenheimer Champion
Income Fund, Oppenheimer High Yield Fund, Oppenheimer
Strategic Bond Fund/VA and Atlas Strategic Income Fund.
Incorporated herein by reference to Exhibit 4.6 to
Registrant's registration statement on Form S-1 (No.
333-41014).
4.8* -- Warrant dated as of August 19, 1996 issued by Gothic Energy
Corporation to Gaines, Berland Inc.
4.9* -- Warrant Agreement dated as of September 9, 1997 between
Gothic Energy Corporation and American Stock Transfer &
Trust Company, as warrant agent, and Supplement to Warrant
Agreement dated as of January 16, 2001.
4.10* -- Registration Rights Agreement dated as of September 9, 1997
among Gothic Energy Corporation, two of its subsidiaries,
Oppenheimer & Co., Inc., Banc One Capital Corporation and
Paribas Corporation.
-105-
107
EXHIBIT
NUMBER DESCRIPTION
------- -----------
4.11* -- Warrant Agreement dated as of January 23, 1998 between
Gothic Energy Corporation and American Stock Transfer &
Trust Company, as warrant agent.
4.12* -- Common Stock Registration Rights Agreement dated as of
January 23, 1998 among Gothic Energy Corporation and
purchasers of its senior redeemable preferred stock.
4.13* -- Substitute Warrant to Purchase Common Stock of Chesapeake
Energy Corporation dated as of January 16, 2001 issued to
Amoco Corporation.
4.14* -- Warrant Agreement dated as of April 21, 1998 between Gothic
Energy Corporation and American Stock Transfer & Trust
Company, as warrant agent, and Supplement to Warrant
Agreement dated as of January 16, 2001.
4.15* -- Warrant Registration Rights Agreement dated as of April 21,
1998 among Gothic Energy Corporation and purchasers of units
consisting of its 14 1/8% senior secured discount notes due
2006 and warrants to purchase its common stock.
10.1.1+ -- Registrant's 1992 Incentive Stock Option Plan. Incorporated
herein by reference to Exhibit 10.1.1 to Registrant's
registration statement on Form S-4 (No. 33-93718).
10.1.2+ -- Registrant's 1992 Nonstatutory Stock Option Plan, as
Amended. Incorporated herein by reference to Exhibit 10.1.2
to Registrant's quarterly report on Form 10-Q for the
quarter ended December 31, 1996.
10.1.3+ -- Registrant's 1994 Stock Option Plan, as amended.
Incorporated herein by reference to Exhibit 10.1.3 to
Registrant's quarterly report on Form 10-Q for the quarter
ended December 31, 1996.
10.1.4+ -- Registrant's 1996 Stock Option Plan. Incorporated herein by
reference to Registrant's Proxy Statement for its 1996
Annual Meeting of Shareholders and to Registrant's quarterly
report on Form 10-Q for the quarter ended December 31, 1996.
10.1.5+ -- Registrant's 1999 Stock Option Plan. Incorporated herein by
reference to Exhibit 10.1.5 to Registrant's quarterly report
on Form 10-Q for the quarter ended June 30, 1999.
10.1.6+ -- Registrant's 2000 Employee Stock Option Plan. Incorporated
herein by reference to Exhibit 10.1.6 to Registrant's
quarterly report on Form 10-Q for the quarter ended March
31, 2000.
10.1.7+ -- Registrant's 2000 Executive Officer Stock Option Plan.
Incorporated herein by reference to Exhibit 10.1.7 to
Registrant's quarterly report on Form 10-Q for the quarter
ended March 31, 2000.
10.2.1+ -- Amended and Restated Employment Agreement dated as of July
1, 1998, as amended by First Amendment thereto dated
December 31, 1998 between Aubrey K. McClendon and Chesapeake
Energy Corporation. Incorporated herein by reference to
Exhibit 10.2.1 to Registrant's quarterly reports on Form
10-Q for the quarters ended September 30, 1998 and June 30,
1999.
10.2.2+ -- Amended and Restated Employment Agreement dated as of July
1, 1998, as amended by First Amendment thereto dated
December 31, 1998 between Tom L. Ward and Chesapeake Energy
Corporation. Incorporated herein by reference to Exhibit
10.2.2 to Registrant's quarterly reports on Form 10-Q for
the quarters ended September 30, 1998 and June 30, 1999.
10.2.3+ -- Amended and Restated Employment Agreement dated as of August
1, 2000 between Marcus C. Rowland and Chesapeake Energy
Corporation. Incorporated herein by reference to Exhibit
10.2.3 to Registrant's registration statement on Form S-1
(No. 333-45872).
10.2.5+ -- Employment Agreement dated as of July 1, 2000 between Steven
C. Dixon and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.5 to Registrant's
quarterly report on Form 10-Q for the quarter ended June 30,
2000.
10.2.6+ -- Employment Agreement dated as of July 1, 2000 between J.
Mark Lester and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.6 to Registrant's
quarterly report on Form 10-Q for the quarter ended June 30,
2000.
10.2.7+ -- Employment Agreement dated as of July 1, 2000 between Henry
J. Hood and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.7 to Registrant's
quarterly report on Form 10-Q for the quarter ended June 30,
2000.
-106-
108
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.2.8+ -- Employment Agreement dated as of July 1, 2000 between
Michael A. Johnson and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.8 to
Registrant's quarterly report on Form 10-Q for the quarter
ended June 30, 2000.
10.2.9+ -- Employment Agreement dated as of July 1, 2000 between Martha
A. Burger and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.9 to Registrant's
quarterly report on Form 10-Q for the quarter ended June 30,
2000.
10.3+ -- Form of Indemnity Agreement for officers and directors of
Registrant and its subsidiaries. Incorporated herein by
reference to Exhibit 10.30 to Registrant's registration
statement on Form S-1 (No. 33-55600).
10.4.1* -- Amended and Restated Consulting Agreement dated January 11,
2001 between Chesapeake Energy Corporation and Michael
Paulk.
10.4.2* -- Amended and Restated Consulting Agreement dated January 11,
2001 between Chesapeake Energy Corporation and Steven P.
Ensz.
10.5 -- Rights Agreement dated July 15, 1998 between the Registrant
and UMB Bank, N.A., as Rights Agent. Incorporated herein by
reference to Exhibit 1 to Registrant's registration
statement on Form 8-A filed July 16, 1998. Amendment No. 1
dated September 11, 1998. Incorporated herein by reference
to Exhibit 10.3 to Registrant's quarterly report on Form
10-Q for the quarter ended September 30, 1998.
10.10 -- Partnership Agreement of Chesapeake Exploration Limited
Partnership dated December 27, 1994 between Chesapeake
Energy Corporation and Chesapeake Operating, Inc.
Incorporated herein by reference to Exhibit 10.10 to
Registrant's registration statement on Form S-4 (No.
33-93718).
10.11 -- Amended and Restated Limited Partnership Agreement of
Chesapeake Louisiana, L.P. dated June 30, 1997 between
Chesapeake Operating, Inc. and Chesapeake Energy Louisiana
Corporation.
21* -- Subsidiaries of Registrant
23.1* -- Consent of PricewaterhouseCoopers LLP
23.2* -- Consent of Williamson Petroleum Consultants, Inc.
23.3* -- Consent of Ryder Scott Company L.P.
23.4* -- Consent of Lee Keeling and Associates, Inc.
23.5* -- Consent of PricewaterhouseCoopers LLP
23.6* -- Consent of Lee Keeling and Associates, Inc.
---------------
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K
During the quarter ended December 31, 2000, Chesapeake filed the following
current reports on Form 8-K:
On October 4, 2000, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing a dividend on preferred
shares.
On October 23, 2000, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing third quarter earnings and
providing information for a conference call with management.
On October 26, 2000, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release reporting record results for the third
quarter of 2000.
On November 14, 2000, we filed a current report on Form 8-K providing under
Item 9 guidance on future financial performance with respect to the fourth
quarter of 2000 and full year 2001.
On November 16, 2000, we filed a current report on Form 8-K providing under
Item 9 guidance on future financial performance with respect to the fourth
quarter of 2000 and full year 2001.
-107-
109
On December 4, 2000, we filed a current report on Form 8-K providing under
Item 9 guidance on future financial performance with respect to the fourth
quarter of 2000 and full year 2001.
On December 18, 2000, we filed a current report on Form 8-K including under
Item 5 an amendment to the description of our capital stock contained in our
Registration Statement on Form 8-B (No. 001-13726).
On December 21, 2000, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release reporting a major exploratory success,
increased 2001 capital expenditure budget, higher production and cash flow
forecasts and an update on the Gothic merger.
On December 21, 2000, we filed a current report on Form 8-K providing under
Item 9 guidance on future financial performance with respect to the fourth
quarter of 2000 and full year 2001.
-108-
110
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
CHESAPEAKE ENERGY CORPORATION
By /s/ AUBREY K. McCLENDON
-----------------------------------
Aubrey K. McClendon
Chairman of the Board and
Chief Executive Officer
Date: March 29, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------------------------------------------------- ------------------------------------ --------------
/s/ AUBREY K. McCLENDON Chairman of the Board, Chief March 29, 2001
--------------------------------------------------- Executive Officer and Director
Aubrey K. McClendon (Principal Executive Officer)
/s/ TOM L. WARD President, Chief Operating Officer March 29, 2001
--------------------------------------------------- and Director (Principal Executive
Tom L. Ward Officer)
/s/ MARCUS C. ROWLAND Executive Vice President and Chief March 29, 2001
--------------------------------------------------- Financial Officer (Principal
Marcus C. Rowland Financial Officer)
/s/ MICHAEL A. JOHNSON Senior Vice President -- Accounting, March 29, 2001
--------------------------------------------------- Controller and Chief Accounting
Michael A. Johnson Officer (Principal Accounting
Officer)
/s/ EDGAR F. HEIZER, JR. Director March 29, 2001
---------------------------------------------------
Edgar F. Heizer, Jr.
/s/ BREENE M. KERR Director March 29, 2001
---------------------------------------------------
Breene M. Kerr
/s/ SHANNON T. SELF Director March 29, 2001
---------------------------------------------------
Shannon T. Self
/s/ FREDERICK B. WHITTEMORE Director March 29, 2001
---------------------------------------------------
Frederick B. Whittemore
-109-
111
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION PAGE
------- ----------- ----
2.1 -- Senior Secured Discount Notes Purchase Agreement dated June
23, 2000 between Chesapeake Energy Marketing, Inc. and
Appaloosa Investment Limited Partnership I, Palomino Fund
Ltd. and Tersk L.L.C. Incorporated herein by reference to
Exhibit 2.1 to Registrant's Form S-1 Registration Statement
(No. 333-41014).
2.2 -- Senior Secured Discount Notes Purchase Agreement dated June
23, 2000 between Chesapeake Energy Marketing, Inc. and
Oppenheimer Strategic Income Fund, Oppenheimer Champion
Income Fund, Oppenheimer High Yield Fund, Oppenheimer
Strategic Bond Fund/VA and Atlas Strategic Income Fund.
Incorporated herein by reference to Exhibit 2.2 to
Registrant's Form S-1 Registration Statement (No.
333-41014).
2.3 -- Senior Secured Discount Notes Purchase Agreement dated June
26, 2000 between Chesapeake Energy Marketing, Inc. and John
Hancock High Yield Bond Fund and John Hancock Variable
Annuity High Yield Bond Fund. Incorporated herein by
reference to Exhibit 2.3 to Registrant's Form S-1
Registration Statement (No. 333-41014).
2.4 -- Senior Secured Discount Notes Purchase Agreement dated June
26, 2000 between Chesapeake Energy Marketing, Inc. and
Ingalls & Snyder Value Partners, L.P., Heritage Mark
Foundation and Arthur R. Ablin. Incorporated herein by
reference to Exhibit 2.4 to Registrant's Form S-1
Registration Statement (No. 333-41014).
2.5 -- Senior Secured Discount Notes Purchase Agreement dated
August 29, 2000 between Chesapeake Energy Marketing, Inc.
and BNP Paribas. Incorporated herein by reference to Exhibit
2.5 to Registrant's registration statement on Form S-1 (No.
333-45872).
2.6 -- Senior Secured Notes Purchase Agreement dated September 1,
2000 between Chesapeake Energy Corporation and Lehman
Brothers Inc. Incorporated herein by reference to Exhibit
2.6 to Registrant's registration statement on Form S-1 (No.
333-45872).
2.7 -- Agreement and Plan of Merger dated September 8, 2000 among
Chesapeake Energy Corporation, Chesapeake Merger 2000 Corp.
and Gothic Energy Corporation, as amended by Amendment No. 1
to Agreement and Plan of Merger dated October 31, 2000.
Incorporated by reference to Annex A to proxy
statement/prospectus included in Amendment No. 1 to
Registrant's registration statement on Form S-4 (No.
333-47330).
3.1 -- Registrant's Certificate of Incorporation as amended.
Incorporated herein by reference to Exhibit 3.1 to
Registrant's registration statement on Form S-1 (No.
333-45872).
3.2 -- Registrant's Bylaws. Incorporated herein by reference to
Exhibit 3.2 to Registrant's registration statement on Form
8-B (No. 001-13726).
4.1 -- Indenture dated as of March 15, 1997 among the Registrant,
as issuer, Chesapeake Operating, Inc., Chesapeake Gas
Development Corporation and Chesapeake Exploration Limited
Partnership, as Subsidiary Guarantors, and United States
Trust Company of New York, as Trustee, with respect to
7.875% Senior Notes due 2004. Incorporated herein by
reference to Exhibit 4.1 to Registrant's registration
statement on Form S-4 (No. 333-24995). First Supplemental
Indenture dated December 17, 1997 and Second [Third]
Supplemental Indenture dated February 16, 1998. Incorporated
herein by reference to Exhibit 4.1.1 to Registrant's
transition report on Form 10-K for the six months ended
December 31, 1997. Second Supplemental Indenture dated April
22, 1998. Incorporated herein by reference to Exhibit 4.1.1
to Registrant's Amendment No. 1 to Form S-3 registration
statement (No. 333-57235). Fourth Supplemental Indenture
dated July 1, 1998. Incorporated herein by reference to
Exhibit 4.1.1 to Registrant's quarterly report on Form 10-Q
for the quarter ended September 30, 1998.
-110-
112
EXHIBIT
NUMBER DESCRIPTION PAGE
------- ----------- ----
4.2 -- Indenture dated as of March 15, 1997 among the Registrant,
as issuer, Chesapeake Operating, Inc., Chesapeake Gas
Development Corporation and Chesapeake Exploration Limited
Partnership, as Subsidiary Guarantors, and United States
Trust Company of New York, As Trustee, with respect to 8.5%
Senior Notes due 2012. Incorporated herein by reference to
Exhibit 4.1.3 to Registrant registration statement on Form
S-4 (No. 333-24995). First Supplemental Indenture dated
December 17, 1997 and Second [Third] Supplemental Indenture
dated February 16, 1998. Incorporated herein by reference to
Exhibit 4.2.1 to Registrant's transition report on Form 10-K
for the six months ended December 31, 1997. Second
Supplemental Indenture dated April 22, 1998. Incorporated
herein by reference to Exhibit 4.2.1 to Registrant's
Amendment No. 1 to Form S-3 registration statement (No. 333-
57235). Fourth Supplemental Indenture dated July 1, 1998.
Incorporated herein by reference to Exhibit 4.2.1 to
Registrant's quarterly report on Form 10-Q for the quarter
ended September 30, 1998.
4.3 -- Indenture dated as of April 1, 1998 among the Registrant, as
Subsidiary Guarantors, and United States Trust Company of
New York, As Trustee, with respect to 9.625% Senior Notes
due 2005. Incorporated herein by reference to Exhibit 4.3 to
Registrant registration statement on Form S-3 (No.
333-57235). First Supplemental Indenture dated July 1, 1998.
Incorporated herein by reference to Exhibit 4.4.1 to
Registrant's quarterly report on Form 10-Q for the quarter
ended September 30, 1998.
4.4 -- Indenture dated as of April 1, 1996 among the Registrant,
its subsidiaries signatory thereto, as Subsidiary
Guarantors, and United States Trust Company of New York, as
Trustee, with respect to 9.125% Senior Notes, due 2006.
Incorporated herein by reference to Exhibit 4.6 to
Registrant's registration statement on Form S-3 (No.
333-1588). First Supplemental Indenture dated December 30,
1996 and Second Supplemental Indenture dated December 17,
1997. Incorporated herein by reference to Exhibit 4.4.1 to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997. Third Supplemental Indenture
dated April 22, 1998. Incorporated herein by reference to
Exhibit 4.4.1 to Registrant's Amendment No. 1 to Form S-3
registration statement (No. 333-57235). Fourth Supplemental
Indenture dated July 1, 1998. Incorporated herein by
reference to Exhibit 4.3.1 to Registrant's quarterly report
on Form 10-Q for the quarter ended September 30, 1998.
4.5 -- Agreement to furnish copies of unfiled long-term debt
Instruments. Incorporated herein by reference to
Registrant's transition report on Form 10-K for the six
months ended December 31, 1997.
4.7 -- Common Stock Registration Rights Agreement dated as of June
27, 2000 among the Registrant and Appaloosa Investment
Limited Partnership I, Palomino Fund Ltd., Tersk L.L.C.,
Oppenheimer Strategic Income Fund, Oppenheimer Champion
Income Fund, Oppenheimer High Yield Fund, Oppenheimer
Strategic Bond Fund/VA and Atlas Strategic Income Fund.
Incorporated herein by reference to Exhibit 4.6 to
Registrant's registration statement on Form S-1 (No.
333-41014).
4.8* -- Warrant dated as of August 19, 1996 issued by Gothic Energy
Corporation to Gaines, Berland Inc.
4.9* -- Warrant Agreement dated as of September 9, 1997 between
Gothic Energy Corporation and American Stock Transfer &
Trust Company, as warrant agent, and Supplement to Warrant
Agreement dated as of January 16, 2001.
4.10* -- Registration Rights Agreement dated as of September 9, 1997
among Gothic Energy Corporation, two of its subsidiaries,
Oppenheimer & Co., Inc., Banc One Capital Corporation and
Paribas Corporation.
4.11* -- Warrant Agreement dated as of January 23, 1998 between
Gothic Energy Corporation and American Stock Transfer &
Trust Company, as warrant agent.
4.12* -- Common Stock Registration Rights Agreement dated as of
January 23, 1998 among Gothic Energy Corporation and
purchasers of its senior redeemable preferred stock.
4.13* -- Substitute Warrant to Purchase Common Stock of Chesapeake
Energy Corporation dated as of January 16, 2001 issued to
Amoco Corporation.
-111-
113
EXHIBIT
NUMBER DESCRIPTION PAGE
------- ----------- ----
4.14* -- Warrant Agreement dated as of April 21, 1998 between Gothic
Energy Corporation and American Stock Transfer & Trust
Company, as warrant agent, and Supplement to Warrant
Agreement dated as of January 16, 2001.
4.15* -- Warrant Registration Rights Agreement dated as of April 21,
1998 among Gothic Energy Corporation and purchasers of units
consisting of its 14 1/8% senior secured discount notes due
2006 and warrants to purchase its common stock.
10.1.1+ -- Registrant's 1992 Incentive Stock Option Plan. Incorporated
herein by reference to Exhibit 10.1.1 to Registrant's
registration statement on Form S-4 (No. 33-93718).
10.1.2+ -- Registrant's 1992 Nonstatutory Stock Option Plan, as
Amended. Incorporated herein by reference to Exhibit 10.1.2
to Registrant's quarterly report on Form 10-Q for the
quarter ended December 31, 1996.
10.1.3+ -- Registrant's 1994 Stock Option Plan, as amended.
Incorporated herein by reference to Exhibit 10.1.3 to
Registrant's quarterly report on Form 10-Q for the quarter
ended December 31, 1996.
10.1.4+ -- Registrant's 1996 Stock Option Plan. Incorporated herein by
reference to Registrant's Proxy Statement for its 1996
Annual Meeting of Shareholders and to Registrant's quarterly
report on Form 10-Q for the quarter ended December 31, 1996.
10.1.5+ -- Registrant's 1999 Stock Option Plan. Incorporated herein by
reference to Exhibit 10.1.5 to Registrant's quarterly report
on Form 10-Q for the quarter ended June 30, 1999.
10.1.6+ -- Registrant's 2000 Employee Stock Option Plan. Incorporated
herein by reference to Exhibit 10.1.6 to Registrant's
quarterly report on Form 10-Q for the quarter ended March
31, 2000.
10.1.7+ -- Registrant's 2000 Executive Officer Stock Option Plan.
Incorporated herein by reference to Exhibit 10.1.7 to
Registrant's quarterly report on Form 10-Q for the quarter
ended March 31, 2000.
10.2.1+ -- Amended and Restated Employment Agreement dated as of July
1, 1998, as amended by First Amendment thereto dated
December 31, 1998 between Aubrey K. McClendon and Chesapeake
Energy Corporation. Incorporated herein by reference to
Exhibit 10.2.1 to Registrant's quarterly reports on Form
10-Q for the quarters ended September 30, 1998 and June 30,
1999.
10.2.2+ -- Amended and Restated Employment Agreement dated as of July
1, 1998, as amended by First Amendment thereto dated
December 31, 1998 between Tom L. Ward and Chesapeake Energy
Corporation. Incorporated herein by reference to Exhibit
10.2.2 to Registrant's quarterly reports on Form 10-Q for
the quarters ended September 30, 1998 and June 30, 1999.
10.2.3+ -- Amended and Restated Employment Agreement dated as of August
1, 2000 between Marcus C. Rowland and Chesapeake Energy
Corporation. Incorporated herein by reference to Exhibit
10.2.3 to Registrant's registration statement on Form S-1
(No. 333-45872).
10.2.5+ -- Employment Agreement dated as of July 1, 2000 between Steven
C. Dixon and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.5 to Registrant's
quarterly report on Form 10-Q for the quarter ended June 30,
2000.
10.2.6+ -- Employment Agreement dated as of July 1, 2000 between J.
Mark Lester and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.6 to Registrant's
quarterly report on Form 10-Q for the quarter ended June 30,
2000.
10.2.7+ -- Employment Agreement dated as of July 1, 2000 between Henry
J. Hood and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.7 to Registrant's
quarterly report on Form 10-Q for the quarter ended June 30,
2000.
10.2.8+ -- Employment Agreement dated as of July 1, 2000 between
Michael A. Johnson and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.8 to
Registrant's quarterly report on Form 10-Q for the quarter
ended June 30, 2000.
-112-
114
EXHIBIT
NUMBER DESCRIPTION PAGE
------- ----------- ----
10.2.8+ -- Employment Agreement dated as of July 1, 2000 between
Michael A. Johnson and Chesapeake Energy Corporation.
Incorporated herein by reference to Exhibit 10.2.8 to
Registrant's quarterly report on Form 10-Q for the quarter
ended June 30, 2000.
10.2.9+ -- Employment Agreement dated as of July 1, 2000 between Martha
A. Burger and Chesapeake Energy Corporation. Incorporated
herein by reference to Exhibit 10.2.9 to Registrant's
quarterly report on Form 10-Q for the quarter ended June 30,
2000.
10.3+ -- Form of Indemnity Agreement for officers and directors of
Registrant and its subsidiaries. Incorporated herein by
reference to Exhibit 10.30 to Registrant's registration
statement on Form S-1 (No. 33-55600).
10.4.1* -- Amended and Restated Consulting Agreement dated January 11,
2001 between Chesapeake Energy Corporation and Michael
Paulk.
10.4.2* -- Amended and Restated Consulting Agreement dated January 11,
2001 between Chesapeake Energy Corporation and Steven P.
Ensz.
10.5 -- Rights Agreement dated July 15, 1998 between the Registrant
and UMB Bank, N.A., as Rights Agent. Incorporated herein by
reference to Exhibit 1 to Registrant's registration
statement on Form 8-A filed July 16, 1998. Amendment No. 1
dated September 11, 1998. Incorporated herein by reference
to Exhibit 10.3 to Registrant's quarterly report on Form 10-
Q for the quarter ended September 30, 1998.
10.10 -- Partnership Agreement of Chesapeake Exploration Limited
Partnership dated December 27, 1994 between Chesapeake
Energy Corporation and Chesapeake Operating, Inc.
Incorporated herein by reference to Exhibit 10.10 to
Registrant's registration statement on Form S-4 (No.
33-93718).
10.11 -- Amended and Restated Limited Partnership Agreement of
Chesapeake Louisiana, L.P. dated June 30, 1997 between
Chesapeake Operating, Inc. and Chesapeake Energy Louisiana
Corporation.
21* -- Subsidiaries of Registrant
23.1* -- Consent of PricewaterhouseCoopers LLP
23.2* -- Consent of Williamson Petroleum Consultants, Inc.
23.3* -- Consent of Ryder Scott Company L.P.
23.4* -- Consent of Lee Keeling and Associates, Inc.
23.5* -- Consent of PricewaterhouseCoopers LLP
23.6* -- Consent of Lee Keeling and Associates, Inc.
---------------
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K
During the quarter ended December 31, 2000, Chesapeake filed the following
current reports on Form 8-K:
On October 4, 2000, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing a dividend on preferred
shares.
On October 23, 2000, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release announcing third quarter earnings and
providing information for a conference call with management.
On October 26, 2000, we filed a current report on Form 8-K reporting under
Item 5 that we had issued a press release reporting record results for the third
quarter of 2000.
On November 14, 2000, we filed a current report on Form 8-K providing under
Item 9 guidance on future financial performance with respect to the fourth
quarter of 2000 and full year 2001.
On November 16, 2000, we filed a current report on Form 8-K providing under
Item 9 guidance on future financial performance with respect to the fourth
quarter of 2000 and full year 2001.
-113-