e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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Annual Report Pursuant to Section 13 or 15 (d)
of the Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 2008
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Transition Report Pursuant to Section 13 of 15(d) of the
Securities Exchange Act of 1934 |
For the transition period from to
Commission File Number: 000 13305
PARALLEL PETROLEUM CORPORATION
(Exact Name of Registrant as Specified in its Charter)
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Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
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75-1971716
(I.R.S. Employer
Identification No.) |
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1004 N. Big Spring, Suite 400
Midland, Texas
(Address of Principal Executive Offices
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79701
(Zip Code) |
Registrants Telephone Number, Including Area Code: (432) 684-3727
Securities Registered Pursuant to Section 12(b) of the Act:
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Title of Class
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Name of Each Exchange on Which Registered |
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Common Stock, $.01 par value
Rights to Purchase Series A Preferred Stock
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Nasdaq Global Select Market |
Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act. Yes o No þ
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 þ No o
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 registrants 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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
a non-accelerated filer, or a smaller reporting company.
See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
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Large accelerated filer þ |
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Accelerated filer o |
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Non-accelerated filer o
(Do not check if a smaller reporting company) |
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Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
The aggregate market value of voting and non-voting common equity held by non-affiliates of
the Registrant as of February 2, 2009 was approximately $99,401,654, based on the closing price of
the common stock on the same date.
At February 17, 2009 there were 41,597,161 shares of common stock outstanding.
Documents Incorporated by Reference
Portions of the registrants definitive proxy statement to be filed with respect to the annual
meeting of stockholders to be held on or about May 20, 2009 are incorporated by reference into Part
III of this Form 10-K.
FORM 10-K
PARALLEL PETROLEUM CORPORATION
TABLE OF CONTENTS
Cautionary Statement Regarding Forward -Looking Statements
Some statements contained in this Annual Report on Form 10-K are forward-looking statements.
These forward-looking statements relate to, among others, the following:
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our future financial and operating performance and results; |
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our drilling plans and ability to secure drilling rigs to effectuate our plans; |
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production volumes; |
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availability of natural gas gathering and transmission facilities; |
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our business strategy; |
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market prices; |
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sources and availability of funds necessary to conduct operations and
complete acquisitions; |
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development costs; |
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number and location of planned wells; |
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our future commodity price risk management activities; |
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our plans and forecasts; and |
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any other statements that are not historical facts. |
We have based these forward-looking statements on our current assumptions, expectations and
projections about future events.
We use the words may, will, expect, could, anticipate, estimate, believe,
continue, intend, plan, budget, future, present value, reserves and other similar
words to identify forward-looking statements. These statements also involve risks and uncertainties
that could cause our actual results or financial condition to materially differ from our
expectations. We believe the assumptions and expectations reflected in these forward-looking
statements are reasonable. However, we cannot give any assurance that our assumptions and
expectations will prove to be correct or that we will be able to take any actions that are
presently planned. All of these statements involve assumptions of future events and risks and
uncertainties. Risks and uncertainties associated with forward-looking statements include, but are
not limited to:
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difficult and adverse conditions in the global and domestic capital and credit markets; |
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continued volatility and further deterioration of the capital and credit markets; |
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uncertainty about the effectiveness of the U.S. governments plan to purchase large
amounts of illiquid, mortgage-backed and other securities from financial institutions; |
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the impairment of financial institutions; |
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exposure to financial and capital market risk; |
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changes in general economic conditions, including the performance of financial
markets and interest rates, which may affect our ability to raise capital and generate
operating cash flow; |
(i)
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unanticipated changes in industry trends; |
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fluctuations in prices of oil and natural gas; |
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dependence on key personnel; |
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reliance on technological development and technology development programs; |
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demand for oil and natural gas; |
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losses due to future litigation; |
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future capital requirements and availability of financing; |
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geological concentration of our reserves; |
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risks associated with drilling and operating wells; |
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competition; |
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general economic conditions; |
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governmental regulations and liability for environmental matters; |
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receipt of amounts owed to us by customers and counterparties to our derivative contracts; |
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hedging decisions, including whether or not to hedge; |
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terrorist attacks or war; |
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actions of third party co-owners of interests in properties in which we also
own an interest; and |
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fluctuations in interest rates and availability of capital. |
For these and other reasons, actual results may differ materially from those projected or
implied. We believe it is important to communicate our expectations of future performance to our
investors. However, events may occur in the future that we are unable to accurately predict or
over which we have no control. We caution you against putting undue reliance on forward-looking
statements or projecting any future results based on such statements.
Before you invest in our common stock or our 101/4% senior notes, you should be aware that there
are various risks associated with an investment. We have described some of these risks in other
sections of this Annual Report on Form 10-K and under Item 1A. Risk Factors, beginning on page
17.
Unless the context requires otherwise, references in this Annual Report on Form 10-K to we,
us, our, Parallel or Company mean the registrant, Parallel Petroleum Corporation and, where
applicable, its former consolidated subsidiaries.
(ii)
PART I
ITEM 1. BUSINESS
About Our Company
We are a Midland, Texas-based independent oil and natural gas exploration and production
company focused on the acquisition, development and exploitation of long-lived oil and natural gas
reserves and, to a lesser extent, exploring for new oil and natural gas reserves. The majority of
our current producing properties are in the Permian Basin of west Texas and New Mexico, the Fort
Worth Basin of north Texas, and the onshore Gulf Coast area of south Texas. We are a publicly
traded company listed on Nasdaq under the ticker symbol PLLL.
Throughout this report, we refer to some terms that are commonly used and understood in the
oil and natural gas industry. These terms and their meanings are:
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Bbl or Bbls barrel or barrels of oil or other liquid hydrocarbons; |
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Bcf billion cubic feet of natural gas; |
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BOE equivalent barrel of oil or 6 Mcf of natural gas for one barrel of oil; |
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MBbls thousand barrels of oil or other liquid hydrocarbons; |
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MBoe thousand barrels of oil equivalent; |
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MMBbls million barrels of oil or other liquid hydrocarbons; |
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MMBoe million barrels of oil equivalent; |
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MMBtu million British thermal units; |
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Mcf thousand cubic feet of natural gas; and |
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MMcf million cubic feet of natural gas. |
Parallel was incorporated in Texas on November 26, 1979, and reincorporated in the State of
Delaware on December 18, 1984.
Our executive offices are located at 1004 N. Big Spring, Suite 400, Midland, Texas 79701. Our
telephone number is (432) 684-3727.
Available Information
You may read and copy any materials we file with, or furnish to, the Securities and Exchange
Commission, or the SEC, at the SECs public reference facilities at 100 F Street, N.E., Room 1580,
Washington, D.C. 20549. You may obtain information on the operation of the public reference
facilities by calling the SEC at 1-800-SEC-0330. The SEC maintains a website (www.sec.gov)
that contains reports, proxy and information statements, and other information regarding issuers,
including Parallel, that file electronically with the SEC.
Our website address is www.plll.com. Information on our website or any other website
is not incorporated by reference into this Annual Report on Form 10-K and does not constitute a
part of this Annual Report on Form 10-K.
We make available free of charge on our Internet website our annual reports on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed
or
(1)
furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as
reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
We will provide electronic or paper copies of our SEC filings free of charge upon request made
to Cindy Thomason, Manager of Investor Relations, cindyt@plll.com, 1-800-299-3727.
Developments in 2008 and 2009
Adverse Economic Environment. In the last half of 2008, we, along with others in the oil and
gas exploration and production industry, began to feel the fall-out of the credit crisis, which
is ongoing. During this past year, U.S. equity markets dropped sharply, as evidenced by the trading
prices of our common stock. During the period from January 1, 2008 to June 30, 2008, the closing
price of our stock ranged from a high of $23.22 to a low of $13.15 per share. During the period
from July 1, 2008 to December 31, 2008, the closing price of our stock ranged from a high of $20.79
to a low of $1.61 per share. The landscape for companies such as ours changed drastically as a
direct result of market turbulence and declines in the financial sector, and steep declines in the
price of oil and natural gas. In anticipation of difficult times in the exploration and production
segment of the oil and gas industry, we have reduced our capital expenditure budget, and we
declined an increase in our borrowing base. In addition, as a result of recent conditions in the
capital markets and all of the surrounding uncertainties, we concluded that it would be prudent to
draw an additional $62.5 million under our line of credit in order to assure availability of and
access to these funds. However, in view of the difficulties experienced by many banking
institutions, it is possible that we could also become exposed to certain risks faced by our bank
lenders, including legal, political, regulatory, operational and other risks. We depend on our
ability to withdraw funds on short notice to meet our obligations. A lenders insolvency or
inability to continue participating in our syndicate of banks in the ordinary course of business
could have a material adverse effect our financial condition and results of operations. For more
information about the steps we have taken in response to the recent financial downturn, please read
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operation -
Trends and Outlook.
Amended and Restated Credit Agreement. In May 2008, we entered into a Fourth Amended and
Restated Credit Agreement, or the Credit Agreement, with Citibank, N.A., BNP Paribas, Comerica
Bank, Compass Bank, Bank of Scotland, plc, Texas Capital Bank, N.A. and Western National Bank.
The Credit Agreement provided us with a revolving line of credit which had a borrowing base
limitation of $230.0 million at the time we entered into the Credit Agreement. The total amount
that we could borrow and have outstanding at any one time is limited to the lesser of $600.0
million or the borrowing base established by the lenders.
First Amendment to Credit Agreement. On October 31, 2008, we entered into a First
Amendment to our Fourth Amended and Restated Credit Agreement, or the Revolving Credit
Agreement, amending the Credit Agreement from May 2008 described above. Generally, the
Revolving Credit Agreement increased our annual interest rate by one-fourth of one percent
(.25%). The borrowing base limitation of $230.0 million remained unchanged with the total
amount available to borrow and have outstanding at any one time being limited to the lesser
of $600.0 million or the borrowing base established by the lenders.
Second
Amendment to Credit Agreement. On February 19, 2009,
but effective as of December 31, 2008, we entered into a Second
Amendment to our Revolving Credit Agreement. Generally, the Second Amendment increased our annual
interest rate for Libor loans by one-fourth of one percent (0.25%). In addition, the Second
Amendment modified one of the financial covenants that we must comply with. Before the amendment,
our ratio of consolidated funded debt to consolidated EBITDA (calculated at the end of each fiscal
quarter using the results of the immediately preceding twelve-month period, each a test period)
was not allowed to exceed 4.00 to 1.00. After the Second Amendment, this
(2)
ratio is not allowed to
exceed 4.25 to 1.00 as of December 31, 2008 and for any test period during 2009 and 2010, or 4.00 to 1.00 during the
year 2011 and thereafter. See Note 19- Subsequent Events.
The next redetermination of our borrowing base is scheduled to be April 1, 2009. Each
borrowing base determination is primarily based upon our then existing quantities of proved oil and
gas reserves and commodity prices. However, our lenders are entitled to take into account in their
determination of the borrowing base other credit factors that the lenders customarily consider in
similar loan facilities, such as cash flow, liabilities, our business and our prospects. Given the
current financial crisis in the U.S. economy and the continued uncertainty and volatility in the
U.S. capital markets, along with recent declines in oil and gas prices, these other credit factors
may become more important to our lenders in their evaluation and determination of any future
borrowing base, which could cause any future borrowing base to be lower than expected relative to
the value of our oil and gas reserves.
Our bank lenders at February 2, 2009 included Citibank, N.A., BNP Paribas, Compass Bank, Bank
of Scotland plc, Bank of America, N.A., Texas Capital Bank, N.A., Western National Bank and West
Texas National Bank. None of the bank lenders held more than 21% of the facility at February 2,
2009. At February 2, 2009, the principal amount outstanding under the revolving credit facility
was $225.0 million, excluding $445,000 reserved for our letters of credit; our borrowing base was
$230.0 million; and our interest rate was 4.75%, based on Citibank N.A.s prime rate. For further
information regarding our credit facility please refer to Note 11-
Credit Arrangements.
Exercise of Warrants. In May 2008, warrants were exercised for a total of 148,757 shares of
common stock in a non-underwritten public offering. The shares were issued upon exercise of
outstanding warrants that we originally issued in our initial public offering in 1980. Under terms
of the warrants, holders of the warrants were entitled to purchase one share of common stock for
each warrant exercised. The warrants were exercisable at $6.00 per share on or before May 15, 2008.
Net proceeds from the offering, which we used for general corporate purposes, were approximately
$796,000. Warrants to purchase 151,273 shares were not exercised and expired by their own terms on
May 15, 2008. See Note 13- Stockholders Equity.
Acquisitions and Divestitures. In June 2008 we purchased additional interests in our operated
Diamond M properties in Scurry County, Texas, effective May 1, 2008. The purchase price of
approximately $35.5 million was financed with borrowings under our Credit Agreement. The additional
interests acquired represented proved reserves of approximately 2.0 million BOE. The acquired
interests consisted of two components, the first component being an 89% working interest in the
Base production and reserves, and the second component being a 22.3% working interest in the
production and reserves above the Base. The Base production and reserves generally means future
production and reserves defined by an established base production decline curve as of December 19,
2001. Prior to this acquisition, we did not own an interest in the Base production and reserves but
owned a 65.7% working interest in the production and reserves above the Base. This acquisition
resulted in an increase in our ownership in the Base production and reserves from zero to an
approximate 89% working interest (77% net revenue interest), and an increase in the production and
reserves above the Base from a 65.7% working interest to an 88% working interest (76% net revenue
interest). See Note 4- Property Exchange and Acquisitions.
Exchange of Senior Notes. In July 2007, we completed a private offering of unsecured senior
notes (the senior notes or 101/4% senior notes) in the principal amount of $150.0 million. The
senior notes mature on August 1, 2014 and bear interest at 101/4% which is payable semi-annually
beginning on February 1, 2008. Prior to August 1, 2010, we may redeem up to 35% of the senior notes
for a price equal to 110.250% of the original principal amount of the senior notes with the
proceeds of certain equity offerings. On or after August 1, 2011 we may redeem all or some of the
senior notes at a redemption price that will decrease from 105.125% of the principal amount of the
senior notes to 100% of the principal amount on August 1, 2013. In addition, prior to August 1,
2011, we may redeem some or all of the senior notes at a redemption price equal to 100% of the
principal amount of the senior notes to be redeemed,
(3)
plus a make-whole premium, plus any accrued and unpaid interest. We agreed to use our
reasonable best efforts to exchange the senior notes for registered, freely tradable notes having
substantially identical terms to the senior notes, and a registration statement on Form S-4
allowing holders of the old senior notes to exchange the old senior notes for freely tradable
senior notes became effective on January 29, 2008. We completed the exchange of the old senior
notes for new registered, freely tradable senior notes on March 4, 2008. See Note 11- Credit
Arrangements.
Barnett Shale Farmout Agreement. On February 11, 2009, we entered into a farmout agreement
with Chesapeake Energy Corporation, or Chesapeake, related to our approximate 35% interest in
the Barnett Shale gas project. Under the farmout agreement, for all wells drilled on our Barnett
Shale leasehold from November 1, 2008 through December 31, 2016, we have agreed to assign to
Chesapeake 100% of our leasehold in the Barnett Shale, subject to the following terms:
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all wells drilled from November 1, 2008 through December 31, 2009, and all
wells drilled during each succeeding calendar year through 2016 will be treated
as a separate project or payout period, creating eight separate projects or
payout periods; |
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at the time Chesapeake commences the drilling of a well during one of the
payout periods, we will assign to Chesapeake 100% of our leasehold interest
within the subject unit or lease, reserving and retaining a 50% reversionary
interest that will vest after Chesapeake recovers 150% of its costs for a
particular payout period. Until 150% payout has been reached, Chesapeake will
fund 100% of our costs for drilling, completing and operating wells during the
payout period; |
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on each project, Chesapeake is entitled to receive all revenues from our
reversionary interest until Chesapeake receives revenues totaling 150% of the
drilling, completion and operating costs Chesapeake incurs in funding our
reversionary interest; |
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upon reaching the 150% payout level for a given project, 50% of the interest
assigned to Chesapeake will revert back to us; |
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after 150% project payout, we will pay all costs and receive all revenues
attributable to our 50% reversionary interest in each project; |
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for wells drilled after January 1, 2017, we will pay all costs and receive
all revenues attributable to our 50% reversionary interest; and |
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we will retain all of our interest in wells commenced prior to November 1,
2008, except for 3 wells commenced in late October 2008. We will retain all of
our interest in approximately 90 gross (22.4 net) producing wells and 31 gross
(9.49 net) wells in progress. |
As
non-operator, we do not control the timing of investment in the Barnett Shale gas project.
Therefore, we entered into the farmout agreement with Chesapeake. This farmout agreement had a
minimal effect on our proved reserves as of December 31, 2008.
We estimate that our Barnett Shale leasehold acreage operated by Chesapeake and subject to the
farmout agreement is approximately 25,600 gross (9,300 net) acres. We anticipate that
approximately 61 gross (10.0 net) wells will be drilled and included in the 2009 payout period from
November 1, 2008 through December 31, 2009. Payout of each project will depend on drilling and
completion costs, timing of completion and pipeline connection to sales, and natural gas prices,
among other things.
(4)
2009 Capital Budget
Our 2009 capital investment budget for properties we owned at February 1, 2009 is estimated to
be approximately $29.1 million. The budget will be funded from our estimated operating cash flows.
If our cash flows are not sufficient to fund all of our estimated capital expenditures, we may fund
any shortfall with bank borrowings and proceeds from the sale of our debt or equity securities or
sale of oil and natural gas properties, reduce our capital budget or effect a combination of these
alternatives. The amount and timing of our expenditures are subject to change based upon market
conditions, results of expenditures, new opportunities and other factors.
We routinely adjust our capital expenditure budget in response to changes in oil and natural
gas prices, drilling and acquisition costs, cash flow, drilling results and borrowing base
redeterminations under our revolving credit facility.
Proved Reserves as of December 31, 2008
Cawley, Gillespie & Associates, Inc., our independent petroleum engineers, estimated the total
proved reserves attributable to all of our oil and natural gas properties to be approximately 21.2
MMBbls of oil and approximately 71.8 Bcf of natural gas as of
December 31, 2008.
Approximately 64% of our proved reserves are oil and approximately 64% are categorized as
proved developed reserves.
About Our Business and Strategy
We have positioned our property portfolio on acreage in established geologic trends where we
use our engineering, operational, financial and technical expertise to provide consistent long-term
production and attractive returns on our investments. We prefer obtaining positions in long-lived
oil and natural gas reserves to properties that have shorter reserve lives. We manage financial,
reservoir, drilling and geological risks by emphasizing lower-risk acquisition, exploitation,
enhancement and development drilling opportunities over higher-risk exploration projects.
Furthermore, aggressive application of advanced technologies and production techniques, such as
horizontal drilling and multi-stage fracture stimulation techniques have allowed us to achieve
productivity in areas that we believe would not have been productive without the use of these
advanced technologies and production techniques.
Our experienced executive management team, together with our technical staff, has
significantly grown our asset base, accumulating large acreage positions and working interests in
high-quality oil and natural gas properties that demonstrate attractive returns on investment. From
2001 to 2008, we have replaced approximately 337% of our production. For the year ended December
31, 2008, our depletion per BOE was $15.56, and our related lifting costs, excluding production
taxes, were $9.98 per BOE. Our long-lived Permian Basin reserves demonstrate shallow decline
profiles, high margins, low replacement costs and consistent positive cash flows. We continue to
utilize this reliable stream of cash flows from our oil production to support the development of
our natural gas resource plays. We believe we are positioned in some of the most attractive areas
of both the Barnett Shale and Wolfcamp Carbonate plays. Chesapeake Energy Corporation, or
Chesapeake, as the operator of the majority of our interests in the Barnett Shale natural gas
resource play, provides substantial operating expertise in the development of this project. We
believe we have significant long-term growth potential through the development of our existing core
oil and natural gas properties.
(5)
Approximately 68% of our proved reserves are assigned to our Permian Basin long-lived oil
properties and 31% are assigned to our two emerging resource gas projects, the Barnett Shale gas
project and the Wolfcamp gas project. As of December 31, 2008, our standardized measure of
discounted future net cash flows was $307.9 million. The following table presents proved reserves
as of December 31, 2008 by our areas of operation.
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Proved Reserves as of December 31, 2008(1) |
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Oil |
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Natural Gas |
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Total |
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% of Total |
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(M Bbl) |
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(M M cf) |
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(M Boe) |
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M Boe |
Resource projects: |
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Barnett Shale |
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26,008 |
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4,335 |
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13 |
% |
New Mexico Wolfcamp |
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1 |
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34,742 |
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5,791 |
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18 |
% |
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Total resource projects |
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1 |
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60,750 |
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10,126 |
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31 |
% |
Permian Basin of West Texas |
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21,122 |
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8,931 |
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22,610 |
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68 |
% |
Onshore Gulf Coast of South Texas |
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83 |
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2,152 |
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442 |
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1 |
% |
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Total |
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21,206 |
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71,833 |
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33,178 |
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100 |
% |
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(1) |
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NYMEX prices, as of December 31, 2008, were $44.60 per Bbl and
$5.62 per MMBtu. |
In
2008, we spent $230.6 million on oil and natural gas related capital expenditures, which
includes $41.5 million for proved acquisitions, and our 2009 capital budget is $29.1 million. We
have primarily focused our efforts on achieving substantial growth in our production and proved
reserves including our growth gas resource plays in the north Texas Barnett Shale and New Mexico
Wolfcamp Carbonate regions. In 2009 we plan to complete 37 gross wells that were in progress at
December 31, 2008, drill 7 gross new wells and to perform approximately 22 gross well workovers, or
conversions-to-injection. We plan to allocate our $29.1 million capital budget for 2009 as follows:
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$10.2 million for the completion of wells that were in progress at year-end
in our north Texas Barnett Shale project; |
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$5.2 million for the completion of wells that were in progress at year-end,
pipeline construction, seismic and leasehold acquisitions in our New Mexico
Wolfcamp Carbonate project; |
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$12.1 million for the completion of wells that were in progress at year-end,
the drilling and completion of new wells and workovers of existing wells in our
Permian Basin of west Texas properties; and |
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$1.6 million for the drilling and completion of new wells in our Yegua/Frio
and Cotton Valley Reef projects and lease maintenance on our Utah/Colorado
project. |
Business Segments
Our operations are conducted in one business segment, oil and natural gas exploration and
production.
Our Strategy
Our strategy has not changed from prior years; however, the activities and acquisitions
described below are being impacted by the adverse economic environment developments discussed above
and elsewhere in this Annual Report on Form 10-K.
Conduct Exploitation Activities on Our Existing Assets. We seek to maximize economic return on
our existing assets by maximizing production rates and ultimate recovery, while managing
operational efficiency to minimize direct lifting costs. For the year ended December 31, 2008, our lease
operating
(6)
expense per BOE produced was approximately $9.98, excluding production taxes. Development
and production growth activities include infill and extension drilling of new wells, re-completion,
pay adds and re-stimulation of existing wells and implementation and management of enhanced oil
recovery projects such as waterflood operations. Operational efficiencies and cost reduction
measures include optimization of surface facilities, such as fluid handling systems, gas
compression or artificial lift installations. Efficiencies are also increased through aggressive
monitoring and management of electrical power consumption, injection water quality programs,
chemical and corrosion prevention programs and the use of production surveillance equipment and
software. In all instances, a proactive approach is taken to achieve the desired result while
ensuring minimal environmental impact.
Use of Horizontal Drilling and Fracture Stimulation Activities in Gas Resource Plays. We
believe the use of horizontal drilling and fracture stimulations has enabled us to develop reserves
economically, such as our Barnett Shale and Wolfcamp gas projects. The successful application of
these technologies has increased net production in the Wolfcamp to an average of 14.7 MMcf per day
and in the Barnett Shale to an average of 10.3 MMcf per day during the quarter ended December 31,
2008 since the inception of these projects. Our current budget calls for the completion of
approximately 31 gross (9.5 net) wells that were in progress at year-end in the Barnett Shale. In
the Wolfcamp Carbonate we anticipate completing 3 gross (1.8 net) wells that were in progress at
year-end and to refrac 3 gross (2.6 net) wells.
Use of Advanced Technologies and Production Techniques. We believe that 3-D seismic surveys,
horizontal drilling, fracture stimulation and other advanced technologies and production techniques
are useful tools that help improve normal drilling operations and enhance our production and
returns. We believe that our use of these technologies and production techniques in exploring for,
developing and exploiting oil and natural gas properties can reduce drilling risks, lower finding
costs, provide for more efficient production of oil and natural gas from our properties and
increase the probability of locating and producing reserves that might not otherwise be discovered.
Acquire Long-Lived Properties with Enhancement Opportunities. Our acquisition strategy is
focused on leveraging our geographical expertise in our core areas of operation and seeking assets
located in and around these areas. We selectively evaluate acquisition opportunities and expect
that they will continue to play a role in increasing our reserve base and future drilling
inventory. When identifying target assets, we focus primarily on reserve quality and assets in new
development plays with upside potential. Through this approach, we have traditionally targeted
smaller asset acquisitions which allow us to absorb, enhance and exploit properties without taking
on significant integration risk.
Conduct Exploratory Activities. Although we do not emphasize exploratory drilling, we will
selectively undertake exploratory projects that have known geological and reservoir characteristics
which are in close proximity to existing wells so data from the existing wells can be correlated
with seismic data on or near the prospect being evaluated, and that could have a potentially
meaningful impact on our reserves.
Drilling Activities in 2008
The following table shows our gross wells drilled, by geographic area, during 2008 and the
number of gross wells in process at December 31, 2008.
(7)
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Number of Gross |
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Number of |
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Wells Drilling or |
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Gross |
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Depth |
|
Gross |
|
Waiting on Completion |
|
Productive |
|
Gross |
Area |
|
Range (feet) |
|
Wells Drilled |
|
at December 31, 2008 |
|
Wells |
|
Dry Wells |
North Texas |
|
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|
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|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
Barnett Shale |
|
|
7,000 |
|
|
|
|
|
|
|
8,000 |
|
|
|
63 |
|
|
|
39 |
(1) |
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24 |
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Permian Basin of West Texas
and New Mexico |
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Carm-Ann |
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4,000 |
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4,500 |
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5 |
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5 |
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Harris |
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4,000 |
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4,500 |
|
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10 |
|
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10 |
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Fullerton |
|
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4,000 |
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5,000 |
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5 |
|
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5 |
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Wolfcamp Gas |
|
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4,300 |
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4,500 |
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23 |
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3 |
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20 |
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Diamond M Deep |
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7,000 |
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8,000 |
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9 |
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2 |
|
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7 |
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Onshore Gulf Coast of Texas |
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Frio/Yegua/Wilcox |
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5,000 |
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10,000 |
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2 |
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1 |
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1 |
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117 |
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45 |
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71 |
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1 |
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(1) |
|
Includes 13 wells that were included in the Barnett Shale Farmout Agreement, dated February
11, 2009, with Chesapeake Energy Corporation. See Note19- Subsequent Events. |
Drilling and Acquisition Costs
The table below shows our oil and natural gas property acquisition, exploration and
development costs for the periods indicated.
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Year Ended December 31, |
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2008 |
|
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2007 |
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2006 |
|
|
|
($ in thousands) |
|
Proved property acquisition costs |
|
$ |
41,481 |
|
|
$ |
|
|
|
$ |
27,370 |
|
Unproved property acquisition costs |
|
|
41,568 |
|
|
|
36,750 |
|
|
|
30,058 |
|
Exploration costs |
|
|
59,290 |
|
|
|
55,827 |
|
|
|
71,003 |
|
Development costs |
|
|
88,235 |
|
|
|
61,766 |
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|
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69,285 |
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$ |
230,574 |
|
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$ |
154,343 |
|
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$ |
197,716 |
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Current Drilling Projects
Summarized below are our more significant current projects, including our capital budget for
these projects in 2009:
Fort Worth Basin of North Texas
|
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|
Barnett Shale Gas Project, Tarrant County, Texas |
Our 2009 budget for the Barnett Shale project is approximately $10.2 million for the
completion of the 31gross (9.5 net) wells that were in progress at year-end including 5 gross (1.56
net) wells that were work-in-progress at the end of 2007.
Permian Basin of New Mexico
|
|
|
Wolfcamp Gas Project, Eddy and Chaves Counties, New Mexico
|
(8)
Our 2009 New Mexico budget is approximately $5.2 million for the completion of the 3 gross
(1.8 net) wells that were in progress at year-end, the re-frac workover of 3 gross (2.6 net)
existing wells, the installation of pipelines and related infrastructure, the acquisition and
maintenance of leasehold, and the processing and interpretation of 3-D seismic data.
Permian Basin of West Texas
Our significant producing properties in the Permian Basin of west Texas are described below.
|
|
|
Diamond M Canyon Reef Unit & Shallow Leases, Scurry County, Texas |
Our 2009 budget for the Diamond M Canyon Reef and Shallow projects is approximately $7.0
million for the completion of 2 gross (1.8 net) wells that were in progress at year-end, the
drilling and completion of 4 gross (3.5 net) new wells, and the workover or deepening of
approximately 7 gross (6.2 net) existing wells. Parallel is the operator of these properties with
an average working interest of approximately 88%.
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Carm-Ann San Andres Field, Andrews and Gaines Counties, Texas |
Our 2009 budget for the Carm-Ann San Andres project is approximately $0.9 million for lease
and well equipment, telemetry, and unitization costs. Parallel is the operator of these properties
with an average working interest of approximately 77%.
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Harris San Andres Field, Andrews and Gaines Counties, Texas |
Our 2009 budget for the Harris San Andres project is approximately $2.1 million for lease and
well equipment, telemetry, unitization costs and the workover of 7 gross (6.3 net) existing wells.
Parallel is the operator of these properties with an average working interest of approximately 90%.
|
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|
Fullerton San Andres Field, Andrews County, Texas |
Our 2009 budget for the Fullerton San Andres project is approximately $1.3 million for the
drilling of 1 gross (0.4 net) new well and the workover of 5 gross (4.3 net) existing wells.
Parallel owns an 85% average working interest in these properties.
Onshore Gulf Coast of South Texas
|
|
|
Yegua/Frio/Wilcox and Cook Mountain Gas Projects, Jackson, Wharton and Liberty
Counties, Texas |
|
|
Our 2009 budget for the south Texas projects is approximately $0.8 million for the drilling of
2 gross (0.5 net) new wells. |
Other Projects
|
|
|
East Texas Cotton Valley Reef Gas Project, Leon, Freestone and Anderson Counties,
Texas |
Our 2009 budget for the east Texas gas project is approximately $0.7 million for the
completion of 1 gross (0.2 net) well that was in progress at year-end.
|
|
|
Utah/Colorado Conventional Oil & Gas and Heavy Oil Sands Projects, Uinta Basin |
Our 2009 budget for the Utah/Colorado project is approximately $0.1 million for the
maintenance of leasehold. Parallel owns and operates 97.5% of this project.
(9)
Oil and Natural Gas Prices
The average wellhead prices we received for the oil and natural gas we produced in 2008, 2007
and 2006 are shown in the table below.
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Average Price Received for the |
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
Oil (Bbl) |
|
$ |
95.25 |
|
|
$ |
65.97 |
|
|
$ |
59.86 |
|
|
Natural gas (M cf) |
|
$ |
7.74 |
|
|
$ |
6.29 |
|
|
$ |
6.19 |
|
The average price we received during January 2009 for our oil sales was approximately $33.72
per Bbl. At the same date, the average price we were receiving for our natural gas was
approximately $5.57 per Mcf.
Future
oil and natural gas prices continue to trend downward. Although this
will have a negative impact on our future physical commodity sales
values, our derivative contracts will provide a measure of protection
by reducing these price fluctuations. We cannot provide any guidance
as to where future prices will settle in any given future month.
Employees and Consultants
At February 2, 2009, we had 46 full time employees. We also retain independent land,
geological, geophysical, engineering, drilling and financial consultants from time to time and
expect to continue to do so in the future. Additionally, we retain contract pumpers on a
month-to-month basis.
We consider our employee relations to be satisfactory. None of our employees are represented
by a union and we have not experienced work stoppages or strikes.
Wells Drilled
The following table shows our gross and net wells drilled during the three-year period ended
December 31, 2008.
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Exploratory Wells (1) |
|
Development Wells (2) |
Year Ended |
|
Productive |
|
Dry |
|
Productive |
|
Dry |
December 31, |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
2008 |
|
|
39 |
|
|
|
10.65 |
|
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|
1 |
|
|
|
0.13 |
|
|
|
77 |
|
|
|
37.73 |
|
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|
2007 |
|
|
36 |
|
|
|
13.93 |
|
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|
1 |
|
|
|
1.00 |
|
|
|
67 |
|
|
|
32.29 |
|
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|
1 |
|
|
|
0.37 |
|
|
2006 |
|
|
5 |
|
|
|
2.87 |
|
|
|
3 |
|
|
|
1.42 |
|
|
|
122 |
|
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|
68.35 |
|
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1 |
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0.08 |
|
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|
(1) |
|
An exploratory well is a well drilled to find and produce oil or natural gas in an unproved
area, to find a new reservoir in a field previously found to be productive of oil or natural
gas in another reservoir, or to extend a known reservoir. |
|
(2) |
|
A development well is a well drilled within the proved area of an oil or natural gas
reservoir to the depth of a stratigraphic horizon known to be productive. |
All of our drilling is performed on a contract basis by third-party drilling contractors. We
do not own any drilling equipment. We maintain a limited number of supervisory and field personnel
to oversee drilling and production operations. Our plans to drill additional wells are determined
in part by the anticipated availability of acceptable drilling equipment and crews. We do not
currently have any contractual commitments that ensure we will have adequate drilling equipment or
crews to achieve our
(10)
drilling plans. We believe that we currently can secure commitments from
drilling companies that will make equipment available to us for drilling wells on our operated projects. In the case of our
non-operated properties, we also believe that the operators of these other properties will be able
to secure equipment for drilling on our non-operated properties. However, we can provide no
assurance that our expectations regarding the availability of drilling equipment from these
companies will be met.
At February 2, 2009, we were participating in the completion of 4 gross (1.68 net) wells, 20
gross (8.40 net) wells were awaiting completion, 12 gross (3.78 net) wells were shut-in waiting on
pipelines and 2 gross (1.13 net) wells were in process of drilling, excluding 21 wells subject to
the Barnett Shale Farmout Agreement. See Note 19- Subsequent Events.
Volumes, Prices and Lifting Costs
The following table shows certain information about our oil and natural gas production
volumes, average sales prices per Mcf of natural gas and Bbl of oil and the average lifting
(production) cost per BOE for the three-year period ended December 31, 2008.
|
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|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
(in thousands, except per unit data) |
Production, Prices and Lifting Costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
1,027 |
|
|
|
1,051 |
|
|
|
1,137 |
|
Natural gas (M cf) |
|
|
10,944 |
|
|
|
7,422 |
|
|
|
6,539 |
|
BOE |
|
|
2,851 |
|
|
|
2,288 |
|
|
|
2,227 |
|
Oil price (per Bbl) (1) |
|
$ |
95.25 |
|
|
$ |
65.97 |
|
|
$ |
59.86 |
|
Natural gas price (per M cf) (1) |
|
$ |
7.74 |
|
|
$ |
6.29 |
|
|
$ |
6.19 |
|
BOE price (1) |
|
$ |
64.02 |
|
|
$ |
50.72 |
|
|
$ |
48.73 |
|
Average Lifting Cost (including production taxes) per BOE |
|
$ |
13.18 |
|
|
$ |
11.60 |
|
|
$ |
10.06 |
|
|
|
|
(1) |
|
Average price received at the wellhead for our oil and natural gas. |
In 2008, approximately 36% of the volume of our production was oil and 64% was natural gas.
The majority of the oil production is from our Permian Basin longer-lived oil assets. The majority
of the natural gas production is from our Barnett Shale and New Mexico Wolfcamp assets.
The following table summarizes our revenues by product sold for each year in the three year
period ended December 31, 2008.
|
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|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
Oil revenue |
|
$ |
97,799 |
|
|
$ |
69,315 |
|
|
$ |
68,076 |
|
Effect of oil hedges |
|
|
|
|
|
|
|
|
|
|
(11,512 |
) |
Natural gas revenue |
|
|
84,716 |
|
|
|
46,716 |
|
|
|
40,461 |
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
182,515 |
|
|
$ |
116,031 |
|
|
$ |
97,025 |
|
|
|
|
|
|
|
|
|
|
|
Our oil sales in 2008 represented approximately 54% of our combined oil and natural gas
revenues (not considering the effect of hedging) for the year ended December 31, 2008, as compared
to 60% in 2007, and 63% in 2006.
(11)
Markets and Customers
Our oil and natural gas production is sold at the well site on an as produced basis at
market-related prices in the areas where the producing properties are located.
In the table below, we show the purchasers and operators that accounted for 10% or more of our
revenues during the specified years.
|
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|
2008 |
|
2007 |
|
2006 |
Chesapeake Operating, Inc. |
|
|
22 |
% |
|
|
12 |
% |
|
|
(1) |
|
Conoco, Inc. |
|
|
18 |
% |
|
|
21 |
% |
|
|
20 |
% |
Dale Operating Company |
|
|
(1) |
|
|
|
(1) |
|
|
|
10 |
% |
Occidental Energy Marketing |
|
|
10 |
% |
|
|
(1) |
|
|
|
(1) |
|
Texland Petroleum, Inc. |
|
|
29 |
% |
|
|
30 |
% |
|
|
30 |
% |
Tri-C Resources, Inc. |
|
|
(1) |
|
|
|
(1) |
|
|
|
12 |
% |
We do not believe the loss of any one of our purchasers would materially affect our ability to
sell the oil and natural gas we produce because other purchasers are available in our areas of
operations. However, we also believe the current economic downturn has curtailed overall demand
for oil and natural gas produced by us and our competitors, a trend we expect will continue for the
foreseeable future.
Our future ability to market our oil and natural gas production depends upon the availability
and capacity of natural gas gathering systems and pipelines and other transportation facilities. We
are not obligated to provide a fixed or determinable quantity of oil under any existing
arrangements or contracts.
We manage the credit risk associated with our largest customers by using a credit risk
monitoring tool to actively monitor credit ratings, including S&P and Moodys, financial statement
filings, financial position, bankruptcy filings and current news.
Our business does not require us to maintain a backlog of products, customer orders or
inventory.
Office Facilities
Our principal executive offices are located in Midland, Texas, where we lease approximately
28,474 square feet of office space at 1004 North Big Spring, Midland, Texas 79701 under two
separate leases. Our total current rental rate is $22,401 per month. The first lease covering
22,200 square feet expires on February 28, 2010 and the second lease covering 6,274 square feet
expires on May 31, 2011.
We have three field offices and storage facilities that we own. These three offices are
located in Andrews and Snyder, Texas and Hagerman, New Mexico.
Competition
The oil and natural gas industry is highly competitive, particularly in the areas of acquiring
exploratory and development prospects and producing properties. The principal competitive factors
in the acquisition of oil and gas properties include the staff and data necessary to identify,
evaluate and acquire such properties and the financial resources necessary to acquire and develop
the properties. The principal means of competing for the acquisition of oil and natural gas
properties are the amount and terms of the consideration offered. Our competitors include major oil
companies, independent oil and natural gas firms and individual producers and operators. Many of
our competitors have financial resources, staffs and facilities much larger than ours.
(12)
We are also affected by competition for drilling rigs and the availability of related
equipment and securing of qualified labor to conduct our field operations. During periods of
relatively high oil and natural gas prices, the oil and natural gas industry typically experiences
shortages of drilling rigs, equipment, pipe and qualified field personnel. Although we are unable
to predict when or to what extent our exploration and development activities will be affected by
rig, equipment or labor shortages, we have in the past experienced delays in some of our planned
activities and operations because of these shortages.
Intense competition among independent oil and natural gas producers requires us to react
quickly to available exploration and acquisition opportunities. We try to position for these
opportunities by maintaining:
|
|
|
adequate capital resources for projects in our core areas of operations; |
|
|
|
|
the technological capabilities to conduct a thorough evaluation of a
particular project; and |
|
|
|
|
a small staff that can respond quickly to exploration and acquisition
opportunities. |
The principal resources we need for acquiring, exploring, developing, producing and selling
oil and natural gas are:
|
|
|
leasehold prospects under which oil and natural gas reserves may be
discovered or developed; |
|
|
|
|
drilling rigs and related equipment to explore for such reserves; |
|
|
|
|
data necessary to identify, evaluate and acquire properties and the
financial resources necessary to carry out the purchase and development of
the properties; and |
|
|
|
|
knowledgeable and experienced personnel to conduct all phases of oil and
natural gas operations. |
Oil and Natural Gas Regulations
Our operations are regulated by certain federal and state agencies. Oil and natural gas
production and related operations are or have been subject to:
|
|
|
price controls; |
|
|
|
|
taxes; and |
|
|
|
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environmental and other laws relating to the oil and natural gas industry. |
We cannot predict how existing laws and regulations may be interpreted by governmental
agencies or court rulings, whether additional laws and regulations will be adopted, or the effect
such interpretations or new laws and regulations may have on our business, financial condition or
results of operations.
Our oil and natural gas exploration, production and related operations are subject to
extensive rules and regulations that are enforced by federal, state and local governmental
agencies. Failure to comply with these rules and regulations can result in substantial penalties.
The regulatory burden on the oil and natural gas industry increases our cost of doing business and
affects our profitability. Because these rules and regulations are frequently amended or
reinterpreted, we are not able to predict the future cost or impact of compliance with these laws.
(13)
Texas and many other states require drilling permits, bonds and operating reports. Other
requirements relating to the exploration and production of oil and natural gas are also imposed.
These states also have statutes or regulations addressing conservation matters, including
provisions for:
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the unitization of pooling of oil and natural gas properties;
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the establishment of maximum rates of production from oil and natural gas
wells; and |
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the regulation of spacing, plugging and abandonment of wells. |
Sales of natural gas we produce are not regulated and are made at market prices. However, the
Federal Energy Regulatory Commission (FERC) regulates interstate and certain intrastate natural gas
transportation rates and services conditions, which affect the marketing of our natural gas, as
well as the revenues we receive for sales of our production. Since the mid-1980s, FERC has issued a
series of orders, culminating in Order Nos. 636, 636-A, 636-B and 636-C. These orders, commonly
known as Order 636, have significantly altered the marketing and transportation service, including
the unbundling by interstate pipelines of the sales, transportation, storage and other components
of the city-gate sales services these pipelines previously performed.
One of FERCs purposes in issuing the orders was to increase competition in all phases of the
natural gas industry. Order 636 and subsequent FERC orders issued in individual pipeline
restructuring proceedings has been the subject of appeals, the results of which have generally been
supportive of the FERCs open-access policy. In 1996, the United States Court of Appeals for the
District of Columbia Circuit largely upheld Order No. 636. Because further review of
certain of these orders is still possible, and other appeals remain pending, it is difficult
to predict the ultimate impact of the orders on Parallel and our natural gas marketing efforts.
Generally, Order 636 has eliminated or substantially reduced the interstate pipelines traditional
role as wholesalers of natural gas, and has substantially increased competition and volatility in
natural gas markets. While significant regulatory uncertainty remains, Order 636 may ultimately
enhance our ability to market and transport our natural gas, although it may also subject us to
greater competition.
Sales of oil we produce are not regulated and are made at market prices. The price we receive
from the sale of oil is affected by the cost of transporting the product to market. Effective
January 1, 1995, FERC implemented regulations establishing an indexing system for transportation
rates for interstate common carrier oil pipelines, which, generally, would index such rates to
inflation, subject to certain conditions and limitations. These regulations could increase the cost
of transporting oil by interstate pipelines, although the most recent adjustment generally
decreased rates. These regulations have generally been approved on judicial review. We are unable
to predict with certainty what effect, if any, these regulations will have on us. The regulations
may, over time, tend to increase transportation costs or reduce wellhead prices for oil.
We are also required to comply with various federal and state regulations regarding plugging
and abandonment of oil and natural gas wells.
Environmental Regulations
Various federal, state and local laws and regulations governing the discharge of materials
into the environment, or otherwise relating to the protection of the environment, health and
safety, affect our operations and costs. These laws and regulations sometimes:
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require prior governmental authorization for certain activities; |
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limit or prohibit activities because of protected areas or species; |
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impose substantial liabilities for pollution related to our operations or
properties; and |
(14)
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provide significant penalties for noncompliance. |
In particular, our exploration and production operations, our activities in connection with
storing and transporting oil and other liquid hydrocarbons, and our use of facilities for treating,
processing or otherwise handling hydrocarbons and related exploration and production wastes are
subject to stringent environmental regulations. As with the industry generally, compliance with
existing and anticipated regulations increases our overall cost of business. While these
regulations affect our capital expenditures and earnings, we believe that they do not affect our
competitive position in the industry because our competitors are also affected by the same
environmental regulatory programs. Since environmental regulations have historically been subject
to frequent change, we cannot predict with certainty the future costs or other future impacts of
environmental regulations on our future operations. A discharge of hydrocarbons or hazardous
substances into the environment could subject us to substantial expense, including the cost to
comply with applicable regulations that require a response to the discharge, such as claims by
neighboring landowners, regulatory agencies or other third parties for costs of:
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containment or cleanup; |
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penalties assessed or other claims sought for natural resource damages. |
The following are examples of some environmental laws that potentially impact our operations.
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Water. The Oil Pollution Act, or OPA, was enacted in 1990 and
amends provisions of the Federal Water Pollution Control Act of 1972 (FWPCA)
and other statutes as they pertain to prevention of and response to major oil
spills. The OPA subjects owners of facilities to strict, joint and
potentially unlimited liability for removal costs and certain other
consequences of an oil spill, where such spill is into navigable waters, or
along shorelines. In the event of an oil spill into such waters, substantial
liabilities could be imposed upon us. States in which we operate have also
enacted similar laws. Regulations are currently being developed under the OPA
and similar state laws that may also impose additional regulatory burdens on
us. |
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The FWPCA imposes restrictions and strict controls regarding the discharge of
produced waters, other oil and gas wastes, any form of pollutant, and, in some
instances, storm water runoff, into waters of the United States. The FWPCA
provides for civil, criminal and administrative penalties for any unauthorized
discharges and, along with the OPA, imposes substantial potential liability
for the costs of removal, remediation or damages resulting from an
unauthorized discharge. State laws for the control of water pollution also
provide civil, criminal and administrative penalties and liabilities in the
case of an unauthorized discharge into state waters. The cost of compliance
with the OPA and the FWPCA have not historically been material to our
operations, but there can be no assurance that changes in federal, state or
local water pollution control programs will not materially adversely affect us
in the future. Although no assurances can be given, we believe that compliance
with existing permits and compliance with foreseeable new permit requirements
will not have a material adverse effect on our financial condition or results
of operations. |
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Solid Waste. We generate non-hazardous solid waste that fall under
the requirements of the Federal Resource Conservation and Recovery Act and
comparable state statues. The EPA and the states in which we operate are
considering the adoption of stricter disposal standards for the type of
non-hazardous waste we generate. The |
(15)
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Resource Conservation and Recovery Act
also governs the generation, management, and disposal of hazardous wastes. At
present, we are not required to comply with a substantial portion of the
Resource Conservation and Recovery Act requirements because our operations
generate minimal quantities of hazardous wastes. However, it is anticipated
that additional wastes, which could include wastes currently
generated during operations, could in the future be designated as hazardous
wastes. Hazardous wastes are subject to more rigorous and costly disposal and
management requirements than are non-hazardous wastes. Such changes in the
regulations may result in us incurring additional capital expenditures or
operating expenses. |
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Wastes containing naturally occurring radioactive materials (NORM) may also
be generated in connection with our operations. Certain processes used to
produce oil and gas may enhance the radioactivity of NORM, which may be
present in oilfield wastes. NORM is not subject to regulation under the Atomic
Energy Act of 1954, or the Low Level Radioactive Waste Policy Act. NORM is
subject primarily to individual state radiation control regulations. In
addition, NORM handling and management activities are governed by regulations
promulgated by the Occupational Safety and Health Administration (OSHA).
These state and OSHA regulations impose certain requirements concerning work
protection; the treatment, storage and disposal of NORM waste; the management
of waste piles, containers and tanks containing NORM; and restrictions on the
uses of land with NORM contamination. |
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Superfund. The Comprehensive Environmental Response, Compensation,
and Liability Act, sometimes called CERCLA or Superfund, imposes liability,
without regard to fault or the legality of the original act, on certain
classes of persons in connection with the release of a hazardous substance
into the environment. These persons include the current owner or operator of
any site where a release historically occurred and companies that disposed or
arranged for the disposal of the hazardous substances found at the site.
CERCLA also authorizes the EPA and, in some instances, third parties to act
in response to threats to the public health or the environment and to seek to
recover from the responsible classes of persons the costs they incur. In the
course of our ordinary operations, we may have managed substances that may
fall within CERCLAs definition of a hazardous substance. We may be jointly
and severally liable under CERCLA for all or part of the costs required to
clean up sites where we disposed of or arranged for the disposal of these
substances. This potential liability extends to properties that we owned or
operated as well as to properties owned and operated by others at which
disposal of our hazardous substances occurred. |
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We currently own or lease numerous properties that for many years have been
used for exploring and producing oil and natural gas. Although we believe we
use operating and disposal practices standard in the industry, hydrocarbons or
other wastes may have been disposed of or released by us on or under
properties that we have owned or leased. In addition, many of these properties
have been previously owned or operated by third parties who may have disposed
of or released hydrocarbons or other wastes at these properties. Under CERCLA,
and analogous state laws, we could be required to remove or remediate
previously disposed wastes, including wastes disposed of or released by prior
owners or operators, to clean up contaminated property, including contaminated
groundwater, or to perform remedial plugging operations to prevent future
contamination. |
Recent scientific studies have suggested that emissions of certain gases, commonly referred to
as greenhouse gases, may be contributing to warming of the Earths atmosphere. Methane, a primary
(16)
component of natural gas, and carbon dioxide, a byproduct of the burning of fossil fuels, are
examples of greenhouse gases. In response to such studies, the U.S. Congress is actively
considering legislation to reduce emissions of greenhouse gases. In addition, at least nine states
in the Northeast and five states in the West including New Mexico have declined to wait on Congress
to develop and implement climate control legislation and have already taken legal measures to
reduce emissions of greenhouse gases,
primarily through the planned development of greenhouse gas
emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of
the U.S. Supreme Courts decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be
required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if
Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The
Courts holding in Massachusetts that greenhouse gases fall under the federal Clean Air Acts
definition of air pollutant may also result in future regulation of greenhouse gas emissions from
stationary sources under certain Clean Air Act programs. Passage of climate control legislation or
other regulatory initiatives by Congress or various states of the U.S. or the adoption of
regulations by the EPA or analogous state agencies that restrict emissions of greenhouse gases in
areas in which we conduct business could have an adverse effect on our operations and demand for
our products.
ITEM 1A. RISK FACTORS
The following risk factors should be considered carefully along with the other information
provided in this Annual Report on Form 10-K in reaching a decision regarding an investment in our
securities.
Risks Related to Our Business
General economic conditions could adversely impact our results of operations.
A further slowdown in the U.S. economy or other economic conditions affecting capital markets,
such as declining oil and gas prices, failing or weakened financial institutions, inability to
access cash in our bank accounts, inflation, deteriorating business conditions, interest rates and
tax rates, may adversely affect our business and financial condition by reducing overall public
confidence in our financial strength, by causing us to further reduce our capital expenditure
program and curtail planned drilling activities or by causing the oil field service sector of the
domestic oil and gas industry to reduce equipment, labor and services that would otherwise be
available to us. Further, some of our properties are operated by third parties whom we depend upon
for timely performance of drilling and other contractual obligations and, in some cases, for
distribution to us of our proportionate share of revenues from sales of oil and gas we produce. If
current economic conditions adversely impact our third party operators, we are exposed to the risk
that drilling operations or revenue disbursements to us could be delayed. This trickle down
effect could significantly harm our business, financial condition and results of operations.
The consequences of a recession may include a lower level of economic activity and uncertainty
regarding energy prices and the capital and commodity markets. A lower level of economic activity
might result in a decline in energy consumption, which may adversely affect our revenue, liquidity
and future growth. Instability in the financial markets, as a result of recession or otherwise,
also may affect the cost of capital and our ability to raise capital. These events increase the
likelihood that we could become highly vulnerable to further adverse general
economic consequences and industry conditions and that our cash flows and financial condition
may be materially adversely affected as a result thereof.
In addition, the instability and uncertainty in the financial markets has made it difficult
for us to follow through with drilling operations and other business activities that we had planned
on implementing before the current financial crisis. Lower oil and gas prices, the financial
markets and U.S. economy have altered our ability and willingness to continue drilling operations
at a pace consistent with 2007 and 2008 levels.
(17)
The economic situation could also have an impact on our customers and suppliers, causing them
to fail to meet their obligations to us, and on our operating partners, resulting in delays in
operations or failure to make required payments. Additionally, the current economic situation could
lead to reduced demand for oil and natural gas or further reductions in the prices of oil and
natural gas, or both, which could have a negative impact on our financial position, results of
operations and cash flows. While the ultimate outcome and impact of the current financial crisis
cannot be predicted, it may have a material adverse effect on our future liquidity and financial
condition.
Adverse capital and credit market conditions may significantly affect our ability to meet liquidity
needs, access to capital and cost of capital.
The capital and credit markets have been experiencing extreme volatility and disruption for
more than twelve months. In recent months, the volatility and disruption have reached unprecedented
levels. In some cases, the markets have exerted downward pressure on availability of liquidity and
credit capacity for certain issuers.
We need liquidity to pay our operating expenses and interest on our debt. Without sufficient
liquidity, we could be forced to curtail our operations, and our business will suffer. The
principal sources of our liquidity have been cash flow from our operations, bank borrowings and
proceeds from the sale of our debt and equity securities.
If cash flow from operations and bank borrowings do not satisfy our needs, we may have to seek
additional financing. The availability of additional financing will depend on a variety of factors
such as market conditions, the general availability of credit, the volume of trading activities,
the overall availability of credit to the exploration and production segment of the oil and natural
gas industry, our credit ratings and credit capacity, and the possibility that our lenders could
develop a negative perception of our long or short-term financial prospects if the level of our
business activity decreases significantly due to market downturns. Similarly, our access to funds
may be impaired if rating agencies take negative actions against us. Our internal sources of
liquidity may prove to be insufficient, and in such case, we may not be able to successfully obtain
additional financing on favorable terms, or at all.
Disruptions, uncertainty or volatility in the capital and credit markets may also limit our
access to capital required to operate our business, most significantly our drilling operations.
Such market conditions may limit our ability to: replace, in a timely manner, oil and natural gas
reserves that we produce; meet maturing liabilities; generate revenue to meet liquidity needs; and
access the capital necessary to grow our business. As such, we may be forced to delay raising
capital, issue more debt or equity securities than we prefer, or bear an unattractive cost of
capital which could decrease our profitability and significantly impair financing alternatives
available to
us. Our results of operations, financial condition, cash flows and capital position could be
materially adversely affected by disruptions in the financial markets.
Difficult conditions in the global capital markets and the economy generally may materially
adversely affect our business and results of operations and we do not expect these conditions to
improve in the near future.
Our results of operations are materially affected by conditions in the domestic capital
markets and the economy generally. The stress experienced by domestic capital markets that began in
the second half of 2008 has continued and substantially increased during the first quarter of 2009.
Recently, concerns over inflation, energy costs, geopolitical issues, the availability and cost of
credit, the U.S. mortgage market and a declining real estate market in the U.S. have contributed to
increased volatility and diminished expectations for the economy and the markets going forward.
These factors, combined with volatile oil and gas prices, declining business and consumer
confidence and increased unemployment, have precipitated an economic slowdown and recession. In
addition, the fixed-income markets are experiencing a period of extreme volatility which has
negatively impacted market liquidity conditions.
(18)
Initially, the concerns on the part of market participants were focused on the subprime
segment of the mortgage-backed securities market. However, these concerns have since expanded to
include a broad range of mortgage and asset-backed and other fixed income securities, including
those rated investment grade, the U.S. and international credit and interbank money markets
generally, and a wide range of financial institutions and markets, asset classes and sectors. As a
result, capital markets have experienced
decreased liquidity, increased price volatility, credit
downgrade events, and increased probabilities of default. These events and the continuing market
upheavals may have an adverse effect on us because our liquidity and ability to fund our capital
expenditures is dependent in part upon our bank borrowings and access to the public capital
markets. Our revenues are likely to decline in such circumstances and our profit margins could
erode. In addition, in the event of extreme prolonged market events, such as the global credit
crisis, we could incur significant losses. Even in the absence of a market downturn, we are exposed
to substantial risk of loss due to market volatility.
Factors such as business investment, government spending, the volatility and strength of the
capital markets, and inflation all affect the business and economic environment and, ultimately,
the amount and profitability of our business. In an economic downturn characterized by higher
unemployment, lower corporate earnings and lower business investment, our operations could be
negatively impacted. Purchasers of our oil and gas production may delay or be unable to make timely
payments to us. Adverse changes in the economy could affect earnings negatively and could have a
material adverse effect on our business, results of operations and financial condition. The current
mortgage crisis has also raised the possibility of future legislative and regulatory actions in
addition to the recent enactment of the Emergency Economic Stabilization Act of 2008 (the EESA)
that could further impact our business. We cannot predict whether or when such actions may occur,
or what impact, if any, such actions could have on our business, results of operations and
financial condition.
There can be no assurance that actions of the U.S. Government, Federal Reserve and other
governmental and regulatory bodies for the purpose of stabilizing the financial markets will
achieve the intended effect.
In response to the financial crises affecting the banking system and financial markets and
going concern threats to investment banks and other financial institutions, on October 3, 2008,
President Bush signed the EESA into law. Pursuant to the EESA, the U.S. Treasury has the authority
to, among other things, purchase up to $700 billion of mortgage-backed and other securities from
financial institutions for the purpose of stabilizing the financial markets. The Federal
Government, Federal Reserve and other governmental and regulatory bodies have taken or are
considering taking other actions to address the financial crisis. There can be no assurance as to
what impact such actions will have on the financial markets, including the extreme levels of
volatility currently being experienced. Such continued volatility could materially and adversely
affect our business, financial condition and results of operations, or the trading price of our
common stock.
The impairment of financial institutions could adversely affect us.
We have exposure to counterparties in the financial services industry, including commercial
banks that we rely upon for our credit facilities. In the event of default of one or more of these
counterparties, we may have exposure in the form of our ability to withdraw funds on short notice
to meet our obligations and short-term investments. We also have exposure to these financial
institutions in the form of derivative transactions in that the collectibility of amounts owed to
us by a defaulting counterparty may be delayed or impaired. However, our derivative instruments
provide rights of setoff of amounts we owe under our credit facilities against amounts owed to us
by a counterparty under our derivative transactions.
If the counterparties to the derivative instruments we use to hedge our business risks default or
fail to perform, we may be exposed to risks we had sought to mitigate, which could materially
adversely affect our financial condition and results of operations.
(19)
We use derivative instruments to mitigate our risks in various circumstances. We enter into a
variety of derivative instruments, including swaps, puts and collars with counterparties who are
also bank lenders under our credit facility. See Item 7A. Quantitative and Qualitative Disclosures
About Market Risk. If our counterparties fail or refuse to honor their obligations under these
derivative instruments, our
hedges of the related risk will be ineffective. This is a more
pronounced risk to us in view of the recent stresses suffered by financial institutions. Such
failure could have a material adverse effect on our financial condition and results of operations.
We cannot provide assurance that our counterparties will honor their obligations now or in the
future. A counterpartys insolvency, inability or unwillingness to make payments required under
terms of derivative instruments with us could have a material adverse effect on our financial
condition and results of operations. However, our derivative instruments allow us to setoff amounts
owed to us by a counterparty against amounts that are owed by us to a
counterparty under our credit facility. At the date of filing this Annual Report on Form 10-K with the Securities and Exchange
Commission, our counterparties included Citibank, N.A. and BNP Paribas. As of December 31, 2008, we
had a net derivative asset with Citibank, N.A. of $18.7 million and a net derivative asset with BNP
Paribas of $5.6 million.
The fluctuation and volatility of oil and natural gas prices may adversely affect our business, the
value of our mineral properties, our revenues and profitability.
Our business, the value of our oil and natural gas properties and our revenues and
profitability are substantially dependent on prevailing prices of oil and natural gas. Our ability
to borrow and to obtain additional capital on attractive terms is also substantially dependent upon
oil and natural gas prices. Volatile oil and natural gas prices make it difficult to estimate the
value of
producing properties for acquisition and often causes disruption in the market for acquiring oil
and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value.
Price volatility also makes it difficult to budget for acquisitions, development and exploitation
projects. Over the last two years oil prices have fluctuated from approximately $34.00 to
approximately $145.00 per barrel. Subsequent to June 30, 2008, the prices of oil and natural gas
have declined significantly. Between June 30, 2008 and December 31, 2008, oil prices fell 68% from
$140.00 per barrel to $44.60 per barrel, and natural gas prices fell 58% from $13.35 per Mcf to
$5.62 per Mcf. If commodity prices continue to decline our financial condition and results of
operation would be materially and adversely affected. In addition, any further and extended decline
in the price of oil and natural gas could have an adverse effect on our business, the value of our
properties, our borrowing capacity, revenues, profitability and cash flows from operations.
The volatility of the oil and natural gas industry may have an adverse impact on our operations.
Our revenues, cash flows and profitability are substantially dependent upon prevailing prices
for oil and natural gas. In recent years, oil and natural gas prices and, therefore, the level of
drilling, exploration, development and production, have been extremely volatile. Any significant or
extended decline in oil or natural gas prices will have a material adverse effect on our business,
financial condition and results of operations and could impair access to future sources of capital.
Volatility in the oil and natural gas industry results from numerous factors, over which we have no
control, including:
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the level of oil and natural gas prices, expectations about future oil and natural
gas prices and the ability of international cartels to set and maintain production
levels and prices; |
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the cost of exploring for, producing and transporting oil and natural gas; |
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the level and price of foreign oil and natural gas transportation; |
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available pipeline and other oil and natural gas transportation capacity; |
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weather conditions; |
(20)
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international political, military, regulatory and economic conditions; |
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the level of consumer demand; |
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the price and the availability of alternative fuels; |
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the effect of worldwide energy conservation measures; and |
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the ability of oil and natural gas companies to raise capital. |
Significant declines in oil and natural gas prices for an extended period may:
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impair our financial condition, liquidity, ability to finance planned
capital expenditures and results of operations; |
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reduce the amount of oil and natural gas that we can produce economically; |
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cause us to delay or postpone some of our capital projects; |
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reduce our revenues, operating income and cash flow; and |
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reduce the recorded value of our oil and natural gas properties. |
No assurance can be given that current levels of oil and natural gas prices will continue. We
expect oil and natural gas prices, as well as the oil and natural gas industry generally, to
continue to be volatile.
We must replace oil and natural gas reserves that we produce. Failure to replace reserves may
negatively affect our business.
Our future performance depends in part upon our ability to find, develop and acquire
additional oil and natural gas reserves that are economically recoverable. Our proved reserves
decline as they are depleted and we must locate and develop or acquire new oil and natural gas
reserves to replace reserves being depleted by production. No assurance can be given that we will
be able to find and develop or acquire additional reserves on an economic basis. If we cannot
economically replace our reserves, our results of operations may be materially adversely affected.
We are subject to uncertainties in reserve estimates and future net cash flows.
There is substantial uncertainty in estimating quantities of proved reserves and projecting
future production rates and the timing of development expenditures. No one can measure underground
accumulations of oil and natural gas in an exact way. Accordingly, oil and natural gas reserve
engineering requires subjective estimations of those accumulations. Estimates of other engineers
might differ widely from those of our independent petroleum engineers, and our independent
petroleum engineers may make material changes to reserve estimates based on the results of actual
drilling, testing, and production. As a result, our reserve estimates often differ from the
quantities of oil and natural gas we ultimately recover. Also, we make certain assumptions
regarding future oil and natural gas prices, production levels, and operating and development costs
that may prove incorrect. Any significant variance from these assumptions could greatly affect our
estimates of reserves, the economically recoverable quantities of oil and natural gas attributable
to any particular group of properties, the classifications of reserves based on risk of recovery,
and estimates of the future net cash flows. Some of our reserve estimates are made without the
benefit of a lengthy production history and are calculated using volumetric analysis. Those
estimates are less reliable than estimates based on a lengthy production history. Volumetric
analysis involves estimating the volume of a reservoir based on the net feet of pay and an
estimation of the productive area.
(21)
The present value of future net cash flows from our proved reserves is not necessarily the
same as the current market value of our estimated oil and natural gas reserves. We base the
estimated discounted future net cash flows from our proved reserves on prices and costs in effect
on the day of estimate. However, actual future net cash flows from our oil and natural gas
properties also will be affected by factors such as:
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actual prices we receive for oil and natural gas; |
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the amount and timing of actual production; |
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supply and demand of oil and natural gas; |
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limits of increases in consumption by natural gas purchasers; and |
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changes in governmental regulations or taxation. |
The timing of both our production and our incurrence of expenses in connection with the
development and production of oil and natural gas properties will affect the timing of actual
future net cash flows from proved reserves, and thus their actual present value. In addition, the
10% discount factor we use when calculating discounted future net cash flows may not be the most
appropriate discount factor based on interest rates in effect from time to time and risks
associated with us or the oil and natural gas industry in general.
Competition in the oil and natural gas industry is intense, and many of our competitors have
greater financial, technological and other resources than we do.
We operate in the highly competitive areas of oil and natural gas acquisition, development,
exploitation, exploration and production. The oil and natural gas industry is characterized by
rapid and significant technological advancements and introductions of new products and services
using new technologies. We face intense competition from independent, technology-driven companies
as well as from both major and other independent oil and natural gas companies in each of the
following areas:
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seeking to acquire desirable producing properties or new leases for future
exploration; |
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marketing our oil and natural gas production; |
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integrating new technologies; and |
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seeking to acquire the equipment and expertise necessary to develop and
operate our properties. |
Many of our competitors have financial, technological and other resources substantially
greater than ours, and some of them are fully integrated oil and natural gas companies. These
companies may be able to pay more for development prospects and productive oil and natural gas
properties and may be able to define, evaluate, bid for and purchase a greater number of properties
and prospects than our financial or human resources permit. Further, these companies may enjoy
technological advantages and may be able to implement new technologies more rapidly than we can.
Our ability to develop and exploit our oil and natural gas properties and to acquire additional
properties in the future will depend upon our ability to successfully conduct
operations, implement advanced technologies, evaluate and select suitable properties and
consummate transactions in this highly competitive environment.
We do not control all of our operations and development projects, which may adversely affect our
production, revenues and results of operations.
(22)
Substantially all of our business activities are conducted through joint operating agreements
under which we own partial interests in oil and natural gas wells. As of December 31, 2008, we
owned interests in 533 gross (472.36 net) oil and natural gas wells for which we were the operator
and 644 gross (306.79 net) oil and natural gas wells where we were not the operator. Included in
these wells are 258 gross (131.30 net) wells which are shut in or temporarily abandoned and 161
gross (134.29 net) injection wells. Furthermore, we are not the operator of any of our interests in
the Barnett Shale project.
As a result, the success and timing of our drilling and development
activities on properties operated by others depends upon a number of factors outside of our
control, including the operators:
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timing and amount of capital expenditures; |
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expertise and financial resources; |
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inclusion of other participants in drilling wells; and |
Further, we may not be in a position to remove the operator in the event of poor performance,
and we may not have control over normal operating procedures, expenditures or future development of
underlying properties. If drilling and development activities are not conducted on these properties
or are not conducted on a timely basis, we may be unable to increase our production or offset
normal production declines, which may adversely affect our production, revenues and results of
operations.
Our business is subject to many inherent risks, including operating risks, which may result in
substantial losses, and insurance may be unavailable or inadequate to protect us against these
risks.
Oil and natural gas drilling activities and production operations are highly speculative and
involve a high degree of risk. These operations are marked by unprofitable efforts because of dry
holes and wells that do not produce oil or natural gas in sufficient quantities to return a profit.
The success of our operations depends, in part, upon the ability of our management and technical
personnel. The cost of drilling, completing and operating wells is often uncertain. There is no
assurance that our oil and natural gas drilling or acquisition activities will be successful, that
any production will be obtained, or that any such production, if obtained, will be profitable.
Our operations are subject to all of the operating hazards and risks normally incident to
drilling for and producing oil and natural gas. These hazards and risks include, but are not
limited to:
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explosions, blowouts and fires; |
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pressure forcing oil or natural gas out of the wellbore at a dangerous
velocity coupled with the potential for fire or explosion; |
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failure of oilfield drilling and service equipment and tools; |
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changes in underground pressure in a formation that causes the surface to
collapse or crater; |
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pipeline ruptures or cement failures; |
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environmental hazards such as natural gas leaks, oil spills and discharges
of toxic gases; and |
(23)
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availability of needed equipment at acceptable prices, including steel
tubular products. |
Any of these risks can cause substantial losses resulting from:
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injury or loss of life; |
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damage to and destruction of property, natural resources and equipment; |
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pollution and other environmental damage; |
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regulatory investigations and penalties; |
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suspension of our operations; and |
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repair and remediation costs. |
As is customary in the industry, we maintain insurance against some, but not all, of these
hazards. We maintain general liability insurance and obtain Operators Extra Expense insurance on a
well-by-well basis. We carry insurance against certain pollution hazards, subject to our insurance
policys terms, conditions and exclusions. If we sustain an uninsured loss or liability, our
ability to operate could be materially adversely affected.
Our oil and natural gas operations are not subject to renegotiation of profits or termination
of contracts at the election of the federal government.
The oil and natural gas industry is capital intensive.
The oil and natural gas industry is capital intensive. We make substantial capital
expenditures for the acquisition, exploration for and development of oil and natural gas reserves.
Historically, we have financed capital expenditures primarily with cash generated by
operations, proceeds from borrowings and sales of our equity securities. In addition, we have sold
and may consider selling additional assets to raise additional operating capital. From time to
time,
we may also reduce our ownership interests in our projects in order to reduce our capital
expenditure requirements.
Our cash flow from operations and access to capital is subject to a number of variables,
including:
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the level of oil and natural gas we are able to produce from existing
wells; |
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the prices at which oil and natural gas are sold; and |
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our ability to acquire, locate and produce new reserves. |
Any one of these variables can materially affect our ability to borrow under our revolving
credit facility.
If our revenues or the borrowing base under our revolving credit facility decrease as a result
of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other
reason, we may have limited ability to obtain the capital necessary to undertake or complete future
drilling projects. We may, from time to time, seek additional financing, either in the form of
increased bank borrowings, sale of debt or equity securities or other forms of financing and there
can be no assurance as to the availability of any additional financing upon terms acceptable to us.
There are risks in acquiring producing properties, including difficulties in integrating acquired
properties into our business, additional liabilities and expenses associated with acquired
properties,
(24)
diversion of management attention, increasing the scope, geographic diversity and
complexity of our operations and incurrence of additional debt.
Our business strategy includes growing our reserve base through acquisitions. Our failure to
integrate acquired properties successfully into our existing business, or the expense incurred in
consummating future acquisitions, could result in unanticipated expenses and losses. In addition,
we may assume cleanup or reclamation obligations or other unanticipated liabilities in connection
with these acquisitions. The scope and cost of these obligations may ultimately be materially
greater than estimated at the time of the acquisition.
We are continually investigating opportunities for acquisitions. In connection with future
acquisitions, the process of integrating acquired operations into our existing operations may
result in unforeseen operating difficulties and may require significant management attention and
financial resources that would otherwise be available for the ongoing development or expansion of
existing operations. Our ability to make future acquisitions may be constrained by our ability to
obtain additional financing.
Possible future acquisitions could result in our incurring additional debt, contingent
liabilities and expense, all of which could have a material adverse effect on our financial
condition and operating results.
We could experience delays in securing drilling equipment and crews, which would cause us to fail
to meet our drilling plans and negatively impact our operations.
We utilize drilling contractors to perform all of the drilling on our projects. We maintain
a limited number of supervisory and field personnel to oversee drilling and production operations.
Our plans to drill additional wells are determined in large part by the anticipated availability of
acceptable drilling equipment and crews. We do not currently have any contractual commitments that
ensure we will have adequate drilling equipment or crews to achieve our drilling plans. If our
anticipated levels of drilling equipment are not made available to us, we will have to modify our
drilling plans, which would cause us to fail to meet our drilling plans and negatively impact our
operations. If we cannot meet our drilling plans, the value of your investment in us may decline.
The marketability of our natural gas production depends on facilities that we typically do not own
or control.
The marketability of our natural gas production depends in part upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We
generally deliver natural gas through natural gas gathering systems and natural gas pipelines that
we do not own. Our ability to produce and market natural gas on a commercial basis could be harmed
by any significant change in the cost or availability of such systems and pipelines.
Our producing properties are geographically concentrated.
A substantial portion of our proved oil and natural gas reserves are located in the Permian
Basin of west Texas and eastern New Mexico. Specifically, as of December 31, 2008, approximately
83% of the present value of our estimated future net revenues from our proved reserves relates to
our proved reserves located in the Permian Basin. As a result, we may be disproportionately exposed
to the impact of delays or interruptions of production from these wells due to mechanical problems,
damages to the current producing reservoirs, significant governmental regulation, including any
curtailment of production, or interruption of transportation of oil or natural gas produced from
the wells.
(25)
Our derivative activities create a risk of financial loss.
In order to manage our exposure to price risks in the marketing of our oil and natural gas, we
have in the past and expect to continue to enter into oil and natural gas price risk management
arrangements with respect to a portion of our expected production. We use derivative arrangements
such as swaps, puts and collars that generally result in a fixed price or a range of minimum and
maximum price limits over a specified time period. Certain derivative contracts may limit the
benefits we could realize if actual prices received are above the contract price. In a typical
derivative transaction utilizing a swap arrangement, we will have the right to receive from the
counterparty the excess of the fixed price specified in the contract over a floating price based on
a market index, multiplied by the quantity
identified in the derivative contract. If the floating
price exceeds the fixed price, we are required to pay the counterparty this difference multiplied
by the quantity identified in the derivative contract. Derivative arrangements could prevent us
from receiving the full advantage of increases in oil or natural gas prices above the fixed amount
specified in the derivative contract. In addition, these transactions may expose us to the risk of
financial loss in certain circumstances, including instances in which:
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production is less than the hedged volumes; |
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the counterparties to our future contracts fail to perform under the contract; or |
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a sudden, unexpected event materially impacts oil or natural gas prices. |
In the past, some of our derivative contracts required us to deliver cash collateral or other
assurances of performance to the counterparties in the event that our payment obligations exceeded
certain levels. Future collateral requirements are uncertain but will depend on arrangements with
our counterparties and highly volatile oil and natural gas prices.
In addition, increases in oil and natural gas prices negatively affect the fair value of
certain of our derivatives contracts as recorded in our balance sheet and, consequently, our
reported net income. Changes in the recorded fair value of certain of our derivatives contracts are
marked to market through earnings and the decrease in the fair value of these contracts during any
period could result in significant charges to earnings. The increase in oil and natural gas prices
will cause this negative effect on earnings to become more significant. We are currently unable to
estimate the effects on earnings in future periods, but the effects could be significant.
We are subject to complex federal, state and local laws and regulations that could adversely affect
our business.
Extensive federal, state and local regulation of the oil and natural gas industry
significantly affects our operations. In particular, our oil and natural gas exploration,
development and production activities are subject to stringent environmental regulations. These
regulations have increased the costs of planning, designing, drilling, installing, operating and
abandoning our oil and natural gas wells and other related facilities. These regulations may become
more demanding in the future. Matters subject to regulation include:
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permits for drilling operations; |
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drilling bonds; |
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spacing of wells; |
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unitization and pooling of properties; |
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environmental protection; |
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reports concerning operations; and |
(26)
Under these laws and regulations, we could be liable for:
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personal injuries; |
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property damage; |
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oil spills; |
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discharge of hazardous materials; |
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reclamation costs; |
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remediation and clean-up costs; and |
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other environmental damages. |
Failure to comply with these laws and regulations also may result in the suspension or
terminations of our operations and subject us to administrative, civil and criminal
penalties. Further, these laws and regulations could change in ways that substantially
increase our costs. Any of these liabilities, penalties, suspensions, terminations or
regulatory changes could make it more expensive for us to conduct our business or cause us
to limit or curtail some of our operations.
Declining oil and natural gas prices may cause us to record ceiling test write-downs.
We use the full cost method of accounting to account for our oil and natural gas
operations. This means that we capitalize the costs to acquire, explore for and develop oil
and natural gas properties. Under full cost accounting rules, capitalized costs, less
accumulated amortization and related deferred income taxes, shall not exceed an amount (the
ceiling) equal to the sum of: (i) The after tax present value of estimated future net
revenues computed by applying current prices of oil and gas reserves to estimated future
production of proved oil and gas reserves as of the date of the latest balance sheet
presented, less estimated future expenditures (based on current costs) to be incurred in
developing and producing the proved reserves computed using a discount factor of ten percent
and assuming continuation of existing economic conditions; (ii) the cost of properties not
being amortized; and (iii) the lower of cost or estimated fair value of unproven properties
included in the costs being amortized. If unamortized costs capitalized within a cost
center, less related deferred income taxes, exceed the ceiling, the excess shall be charged
to expense and separately disclosed during the period in which the excess occurs. Amounts
thus required to be written off shall not be reinstated for any subsequent increase in the
cost center ceiling. This non-cash write-off does not affect cash flow from operating
activities, but it does reduce stockholders equity.
The risk that we will be required to write down the carrying value of our oil and
natural gas properties increases when oil and natural gas prices decline. In addition,
write-downs may occur if we experience substantial downward adjustments to our estimated
proved reserves.
As a result of the steep decline in oil and natural gas prices during 2008, we
recognized an impairment of $300.5 million for the fiscal year ended December 31, 2008. We
cannot assure you that we will not experience further ceiling test write-downs in the
future.
Terrorist activities may adversely affect our business.
Terrorist activities, including events similar to those of September 11, 2001, or armed
conflict involving the United States may adversely affect our business activities and
financial condition. If events of this nature occur and persist, the resulting political and
social instability could adversely affect prevailing oil and natural gas prices and cause a
reduction in our revenues. In addition, oil and natural gas
(27)
production facilities,
transportation systems and storage facilities could be direct targets of terrorist attacks,
and our operations could be adversely impacted if infrastructure integral to our operations
is destroyed or damaged. Costs associated with insurance and other security measures may
increase as a result of these threats, and some insurance coverage may become more difficult
to obtain, if available at all.
We are highly dependent upon key personnel.
Our success is highly dependent upon the services, efforts and abilities of key members
of our management team. Our operations could be materially and adversely affected if one or
more of these individuals become unavailable for any reason.
We do not have employment agreements with any of our officers or other key employees.
Without these agreements, our ability to obtain and retain qualified officers and employees
may be adversely affected, especially in periods of competitive market conditions.
Our future growth and profitability will also be dependent upon our ability to attract
and retain other qualified management personnel and to effectively manage our growth. There
can be no assurance that we will be successful in doing so.
Part of our business is seasonal in nature.
Weather conditions affect the demand for and price of oil and natural gas and can also
delay drilling activities, temporarily disrupting our overall business plans. Demand for oil
and natural gas is typically higher during winter months than summer months. However, warm
winters can also lead to downward price trends. As a result, our results of operations may
be adversely affected by seasonal conditions.
Failure to maintain effective internal controls could have a material adverse effect on our
operations.
Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the
effectiveness of our internal control over financial reporting. Effective internal controls
are necessary for us to produce reliable financial reports. If, as a result of deficiencies
in our internal controls, we cannot provide reliable financial reports, our business
decision process may be adversely affected, our business and operating results could be
harmed, and investors could lose confidence in our reported financial information.
Our business can be adversely impacted by downward changes in oil and natural gas prices,
and most significantly by declines in oil prices.
Our revenues, cash flows and profitability are substantially dependent on prevailing
oil and natural gas prices, which are volatile. Declines in oil and natural gas prices would
not only reduce revenue, but could reduce the amount of oil and natural 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 natural gas prices do not
necessarily move in tandem. Because approximately 70% of our estimated future revenues from
our proved reserves as of December 31, 2008 are from oil production, we will be more
affected by movements in oil prices.
A shortage of available drilling rigs, equipment and personnel may delay or restrict our
operations.
The oil and natural gas industry is cyclical and, from time to time, there is a
shortage of drilling rigs, equipment, supplies or personnel. During these periods, the costs
and delivery times of drilling rigs, equipment and supplies are substantially greater. In
addition, demand for, and wage rates of, qualified drilling rig crews rise with increases in
the number of active rigs in service. Shortages of drilling rigs, equipment, supplies or
personnel may increase drilling costs or delay or restrict our
exploration and
(28)
development
operations, all or any one of which could harm our business financial condition and results
of operations.
Risks Related to Our Common Stock
We do not pay dividends on our common stock.
We have never paid dividends on our common stock, and do not intend to pay cash
dividends on the common stock in the foreseeable future. Net income from our operations, if
any, will be used for the
development of our business, including capital expenditures and to retire debt. Any
decisions to pay dividends on the common stock in the future will depend upon our
profitability at the time, the available cash and other factors. Our ability to pay
dividends on our common stock is further limited by the terms of our revolving credit
facility and the Indenture governing our 101/4% senior notes.
Our stockholders rights plan, provisions in our corporate governance documents and Delaware
law may delay or prevent an acquisition of Parallel, which could decrease the value of our
common stock.
Our certificate of incorporation, our bylaws and the Delaware General Corporation Law
contain provisions that may discourage other persons from initiating a tender offer or
takeover attempt that a stockholder might consider to be in the best interest of all
stockholders, including takeover attempts that might result in a premium to be paid over the
market price of our stock.
On October 5, 2000, our Board of Directors adopted a stockholder rights plan. The plan
is designed to protect Parallel from unfair or coercive takeover attempts and to prevent a
potential acquirer from gaining control of Parallel without fairly compensating all of the
stockholders. The plan authorized 50,000 shares of $0.10 par Series A Preferred Stock
Purchase Rights. A dividend of one Right for each share of our outstanding common stock was
distributed to stockholders of record at the close of business on October 16, 2000. If a
public announcement is made that a person has acquired 15% or more of our common stock, or a
tender or exchange offer is made for 15% of more of the common stock, each Right entitles
the holder to purchase from the company one one-thousandth of a share of Series A Preferred
Stock, at an exercise price of $26.00 per one one-thousandth of a share, subject to
adjustment. In addition, under certain circumstances, the rights entitle the holders to buy
Parallels stock at a 50% discount. We are authorized to issue 10.0 million shares of
preferred stock. There are no outstanding preferred shares as of December 31, 2008. Our
Board of Directors has total discretion in the issuance and the determination of the rights
and privileges of any shares of preferred stock which might be issued in the future, which
rights and privileges may be detrimental to the holders of the common stock. It is not
possible to state the actual effect of the authorization and issuance of a new series of
preferred stock upon the rights of holders of the common stock and other series of preferred
stock unless and until the Board of Directors determines the attributes of any new series of
preferred stock and the specific rights of its holders. These effects might include:
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restrictions on dividends on common stock and other series of
preferred stock if dividends on any new series of preferred stock have
not been paid; |
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dilution of the voting power of common stock and other series of
preferred stock to the extent that a new series of preferred stock has
voting rights, or to the extent that any new series of preferred stock
is convertible into common stock; |
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dilution of the equity interest of common stock and other series of
preferred stock; and |
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limitation on the right of holders of common stock and other series
of preferred stock to share in Parallels assets upon liquidation until
satisfaction of any liquidation preference attributable to any new
series of preferred stock. |
(29)
The issuance of preferred stock in the future could discourage, delay or prevent a
tender offer, proxy contest or other similar transaction involving a potential change in
control of Parallel that might be viewed favorably by stockholders.
Future sales of our common stock could adversely affect our stock prices.
Substantial sales of our common stock in the public market, or the perception by the
market that those sales could occur, may lower our stock price or make it difficult for us
to raise additional equity capital in the future. These potential sales could include sales
of our common stock by our directors and
officers, who beneficially owned approximately 3.10% of the outstanding shares of our
common stock as of February 17, 2009.
The price of our common stock may fluctuate which may cause our common stock to trade at a
substantially lower price than the price which you paid for our common stock.
The trading price of our common stock and the price at which we may sell securities in
the future is subject to substantial fluctuations in response to various factors, including
any of the following: our ability to successfully accomplish our business strategy; the
trading volume in our stock; changes in governmental regulations; actual or anticipated
variations in our quarterly or annual financial results; our involvement in litigation;
general market conditions; the prices of oil and natural gas; our ability to economically
replace our reserves; announcements by us and our competitors; our liquidity; our ability to
raise additional funds; and other events.
If securities analysts downgrade our stock or cease coverage of us, the price of our stock
could decline.
The trading market for our common stock relies in part on the research and reports that
industry or financial analysts publish about us or our business. We do not control these
analysts. Furthermore, there are many large, well-established, publicly traded companies
active in our industry and market, which may mean that it is less likely that we will
receive widespread analyst coverage. If one or more of the analysts who do cover us
downgrade our stock, our stock price would likely decline rapidly. If one or more of these
analysts cease coverage of our company, we could lose visibility in the market, which in
turn could cause our stock price to decline.
Risks Related to Our 101/4% Senior Notes and Our Other Indebtedness
We have a substantial amount of indebtedness, which may adversely affect our cash flow and
our ability to operate our business, remain in compliance with debt covenants and make
payments on our debt, including our 101/4% senior notes.
As of December 31, 2008, we had total debt of approximately $370.9 million (of which
$145.9 million consisted of our 101/4% senior notes due 2014 net of $4.1 million in
unamortized issue discount and $225.0 million consisted of borrowings under our revolving
credit facility, excluding letters of credit). Our level of debt could have important
consequences for you, including the following:
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we may have difficulty borrowing money in the future for
acquisitions, capital expenditures or to meet our operating expenses or
other general corporate obligations; |
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we will need to use a substantial portion of our cash flows to pay
principal and interest on our debt, which will reduce the amount of
money we have for operations, working capital, capital expenditures,
expansion, acquisitions or general corporate or other business
activities; |
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we may have a higher level of debt than some of our competitors,
which may put us at a competitive disadvantage; |
(30)
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we may be more vulnerable to economic downturns and adverse
developments in our industry or the economy in general, especially
declines in oil and natural gas prices; and |
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our debt level could limit our flexibility in planning for, or
reacting to, changes in our business and the industry in which we
operate. |
We may incur substantially more debt, which may intensify the risks described above,
including our ability to service our indebtedness.
We may be able to incur substantially more debt in the future. Although the Indenture
governing our 101/4% senior notes and the amended and restated credit agreement governing
our revolving credit facility contain restrictions on our incurrence of additional
indebtedness, these restrictions are subject to a number of qualifications and exceptions,
and under certain circumstances, indebtedness incurred in compliance with these restrictions
could be substantial. As of December 31, 2008, after taking into
consideration our outstanding letters of credit, we have approximately $4.6 million of additional borrowing
capacity under our revolving credit facility, subject to specific requirements, including
compliance with financial covenants. In addition, the Indenture governing our 101/4% senior
notes and our revolving credit facility do not prevent us from incurring obligations that do
not constitute indebtedness. To the extent new indebtedness is added to our current
indebtedness levels, the risks described above could substantially intensify.
To service our indebtedness, we will require a significant amount of cash. Our ability to
generate cash depends on many factors beyond our control, and any failure to meet our debt
obligations could harm our business, financial condition and results of operations.
Our ability to make payments on and to refinance our indebtedness, including the 101/4% senior notes, and to fund planned capital expenditures will depend on our ability to
generate cash from operations in the future. This, to a certain extent, is subject to
general economic, financial, competitive, legislative, regulatory and other factors that are
beyond our control, including the prices that we receive for oil and natural gas. We cannot
assure you that our business will generate sufficient cash flow from operations or that
future borrowings will be available to us under our revolving credit facility in an amount
sufficient to enable us to pay our indebtedness, including the notes, or to fund our other
liquidity needs.
If our cash flow and capital resources are insufficient to fund our debt obligations,
we may be forced to sell assets, seek additional equity or debt capital or restructure our
debt. The Indenture governing our 101/4% senior notes and the amended and restated credit
agreement governing our revolving credit facility restricts our ability to dispose of assets
and use the proceeds from the disposition. We cannot assure you that any of these remedies
could, if necessary, be effected on commercially reasonable terms, or at all. In addition,
any failure to make scheduled payments of interest and principal on our outstanding
indebtedness, including our revolving credit facility, would likely result in a reduction of
our credit rating, which could harm our ability to incur additional indebtedness on
acceptable terms. If we fail to meet our payment obligations under our revolving credit
facility, those lenders would be entitled to foreclose on substantially all of our assets
and liquidate those assets. Under those circumstances, our cash flow and capital resources
could be insufficient for payment of interest on and principal of our debt in the future,
including payments on our 101/4% senior notes, and any such alternative measures may be
unsuccessful or may not permit us to meet scheduled debt service obligations, which could
cause us to default on our obligations, impair our liquidity, or cause the holders of our 10
1/4% senior notes to lose a portion of or the entire value of their investment.
A default on our obligations could result in:
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our debt holders declaring all outstanding principal and interest due and
payable; |
(31)
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the lenders under our revolving credit facility terminating their
commitments to loan us money and foreclose against the assets securing their
loans to us; and |
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our bankruptcy or liquidation, which is likely to result in delays in the
payment of our 101/4% senior notes and in the exercise of enforcement remedies
under our 101/4% senior notes. |
In addition, provisions under the bankruptcy code or general principles of equity that
could result in the impairment of your rights include the automatic stay, avoidance of
preferential transfers by a
trustee or a debtor-in-possession, limitations of collectibility of unmatured interest or
attorneys fees and forced restructuring of our 101/4% senior notes.
Restrictive debt covenants in the Indenture and the amended and restated credit agreement
governing our revolving credit facility restrict our business in many ways.
The Indenture governing our 101/4% senior notes contains a number of significant
covenants that, among other things, restrict our ability to:
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transfer or sell assets; |
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make investments; |
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pay dividends, redeem subordinated indebtedness or make other
restricted payments; |
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incur or guarantee additional indebtedness or issue disqualified
capital stock; |
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create or incur liens; |
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incur dividend or other payment restrictions affecting certain
subsidiaries; |
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consummate a merger, consolidation or sale of all or substantially
all of our assets; |
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enter into transactions with affiliates; and |
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engage in businesses other than the oil and gas business. |
These covenants could limit our ability to obtain future financings, make needed
capital expenditures, withstand a future downturn in our business or the economy in general
or otherwise conduct necessary corporate activities. We may also be prevented from taking
advantage of business opportunities that arise because of the limitations that the
restrictive covenants impose on us. A breach of any of these covenants could result in a
default under the 101/4% senior notes which, if not cured or waived, could result in
acceleration of the 101/4% senior notes.
In addition, the amended and restated credit agreement governing our revolving credit
facility contains restrictive covenants and requires us to maintain specified financial
ratios and satisfy other financial condition tests. Our ability to meet those financial
ratios and tests can be affected by events beyond our control, and we cannot assure you that
we will meet those tests. A breach of any of these covenants could result in a default under
the facility. Upon the occurrence of an event of default, the lenders could elect to declare
all amounts outstanding to be immediately due and payable and terminate all commitments to
extend further credit. If we were unable to repay those amounts, the lenders could proceed
against the collateral granted to them to secure that indebtedness. We have pledged
substantially all of our assets as collateral under the revolving credit facility. If the
lenders accelerate the repayment of borrowings, we cannot assure you that we will have
sufficient assets to repay our revolving credit facility and our other indebtedness,
including the 101/4% senior notes.
(32)
Our borrowings under our revolving credit facility expose us to interest rate risk.
Our borrowings under our revolving credit facility are, and are expected to continue to
be, at variable rates of interest and expose us to interest rate risk. If interest rates
increase, our debt service obligations on the variable rate indebtedness would increase even
though the amount borrowed remained the same, and our net income would decrease.
We are subject to many restrictions under our revolving credit facility. If we default under
our revolving credit facility, the lenders could foreclose on, and acquire control of,
substantially all of our assets.
Our revolving credit facility limits the amounts we can borrow to a borrowing base
amount, determined by the lenders in their sole discretion, based upon projected revenues
from the oil and natural gas properties securing our loan. The lenders can unilaterally
adjust the borrowing base and the borrowings permitted to be outstanding under the revolving
credit facility. Any increase in the borrowing base requires the consent of all lenders. If
all lenders do not agree on an increase, then the borrowing base
will be the lowest borrowing base determined by any lender. Outstanding borrowings in excess of the borrowing
base must be repaid immediately, or we must pledge other oil and natural gas properties as
additional collateral. Given the current conditions in the credit markets
and lower commodity prices, it is possible that the borrowing base
under our bank credit facility may be reduced at the time of the next
redetermination of our borrowing base, which is scheduled to be April
1, 2009. We do not currently have any substantial properties that are not
pledged and no assurance can be given that we would be able to make any mandatory principal
prepayments required under the revolving credit facility.
The lenders under our revolving credit facility have liens on substantially all of our
assets. Additionally, the revolving credit facility restricts our ability to obtain
additional financing, make investments, lease equipment, sell assets and engage in business
combinations. We are also required to comply with certain financial covenants and ratios
under this facility. Although we were in compliance with these covenants at December 31,
2008, in the past we have had to request waivers from our banks because of our
non-compliance with certain financial covenants and ratios. Our ability to comply with these
restrictions and covenants in the future is uncertain and will be affected by the levels of
cash flow from our operations and events or circumstances beyond our control. As a result
of the liens held by our lenders, if we fail to meet our payment or other obligations under
this credit facility, including our failure to meet any of the required financial covenants
or ratios, the lenders would be entitled to foreclose on substantially all of our assts and
liquidate those assets. Our failure to comply with any of the restrictions and covenants
under the revolving credit facility could result in a default under both the revolving
credit facility and the Indenture governing our 101/4% senior notes, which could cause all
of our existing indebtedness to be immediately due and payable.
Our 101/4% senior notes are structurally subordinated to any of our secured indebtedness to
the extent of the assets securing such indebtedness.
Our obligations under the 101/4% senior notes are unsecured, but our obligations under
our revolving credit facility are secured by liens on substantially all of our assets.
Holders of this indebtedness and any other secured indebtedness that we may incur in the
future will have claims with respect to our assets constituting collateral for such
indebtedness that are prior to claims of holders of the 101/4% senior notes. In the event
of a default on such secured indebtedness or our bankruptcy, liquidation or reorganization,
those assets would be available to satisfy obligations with respect to the indebtedness
secured thereby before any payment could be made on the 101/4% senior notes. Accordingly,
any such secured indebtedness will effectively be senior to the 101/4% senior notes to the
extent of the value of the collateral securing the indebtedness. While the Indenture
governing the 101/4% senior notes places some limitations on our ability to create liens,
there are significant exceptions to these limitations that will allow us to secure some
kinds of indebtedness without equally and ratably securing the 101/4% senior notes,
including any future indebtedness we may incur under a credit facility. To the extent the
value of
(33)
the collateral is not sufficient to satisfy our secured indebtedness, the holders
of that indebtedness would be entitled to share with the holders of the 101/4% senior notes
and the holders of other claims against us with respect to our other assets. As of December
31, 2008, we had approximately $225.0 million in secured indebtedness outstanding under our
revolving credit facility, excluding letters of credit.
A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S.
bankruptcy or similar state laws, which would prevent the holders of our 101/4% senior
notes from relying on the subsidiary to satisfy our payment obligations under the 101/4%
senior notes.
Initially, there will be no subsidiary guarantees of the 101/4% senior notes, but in
the future such guarantees may occur. Federal and state statutes allow courts, under
specific circumstances, to void subsidiary guarantees, or require that claims under the
subsidiary guarantee be subordinated to all other debts of the subsidiary guarantor, and to
require creditors such as the noteholders to return payments
received from subsidiary guarantors. Under federal bankruptcy law and comparable provisions
of state fraudulent transfer laws, a subsidiary guarantee could be voided or claims in
respect of a subsidiary guarantee could be subordinated to all other debts of that
subsidiary guarantor if, for example, the subsidiary guarantor, at the time it issued its
subsidiary guarantee:
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was insolvent or rendered insolvent by making the subsidiary
guarantee; |
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was engaged in a business or transaction for which the subsidiary
guarantors remaining assets constituted unreasonably small capital; or |
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intended to incur, or believed that it would incur, debts beyond its
ability to pay them as they mature. |
A guarantee may also be voided, without regard to the above factors, if a court found
that the guarantor entered into the guarantee with the actual intent to hinder, delay or
defraud any present or future creditor or received less than reasonably equivalent value or
fair compensation for the subsidiary guarantee. A court would likely find that a guarantor
did not receive reasonably equivalent value or fair compensation for its guarantee if the
guarantor did not substantially benefit directly or indirectly from the issuance of the
guarantees.
The measures of insolvency for purposes of these fraudulent transfer laws will vary
depending upon the law applied in any proceeding to determine whether a fraudulent transfer
has occurred.
Generally, a subsidiary guarantor would be considered insolvent if:
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the sum of its debts, including contingent liabilities, was greater
than the fair saleable value of all of its assets; |
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the present fair saleable value of its assets was less than the
amount that would be required to pay its probable liability on its
existing debts, including contingent liabilities, as they become
absolute and mature; or |
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it could not pay its debts as they become due. |
To the extent a court voids a subsidiary guarantee as a fraudulent transfer or holds
the subsidiary guarantee unenforceable for any other reason, holders of 101/4% senior notes
would cease to have any direct claim against the subsidiary guarantor. If a court were to
take this action, the subsidiary guarantors assets would be applied first to satisfy the
subsidiary guarantors liabilities, if any, before any portion of its assets could be
distributed to us to be applied to the payment of the 101/4% senior notes. We cannot assure
you that a subsidiary guarantors remaining assets would be sufficient to satisfy the claims
of the holders of 101/4% senior notes related to any voided portions of the subsidiary
guarantees.
(34)
We may not have sufficient liquidity to repurchase the 101/4% senior notes upon a change of
control.
Upon the occurrence of a change of control, holders of 101/4% senior notes will have
the right to require us to repurchase all or any part of such holders 101/4% senior notes
at a price equal to 101% of the principal amount of the 101/4% senior notes, plus accrued
and unpaid interest, if any, to the date of repurchase. We may not have sufficient funds at
the time of the change of control to make the required repurchases, or restrictions under
our revolving credit facility may not allow such repurchases. In addition, an event
constituting a change of control (as defined in the indenture governing the 101/4% senior
notes) could be an event of default under our revolving credit facility that would, if it
should occur, permit the lenders to accelerate that debt and that, in turn, would cause an
event of default under the indenture governing the 101/4% senior notes, each of which could
have material adverse consequences for us and the holders of the 101/4% senior notes. The
source of any funds for any repurchase required as a result of a change of control will be
our available cash or cash generated from our business operations or other sources,
including borrowings, sales of assets, sales of equity or funds provided by a new
controlling entity. We cannot assure you, however, that sufficient funds would be available
at the time of any change of control to make any required repurchases of the 101/4% senior
notes tendered and to repay debt under our revolving credit facility.
ITEM 1B. UNRESOLVED STAFF COMMENTS
We have not received any written comments from the staff of the Securities and Exchange
Commission that remain unresolved.
ITEM 2. PROPERTIES
General
Our principal properties consist of working interests in developed and undeveloped oil
and natural gas leases and the reserves associated with those leases. Generally, developed
oil and natural gas leases remain in force so long as production is maintained. Undeveloped
oil and natural gas leaseholds are generally for a primary term of five or ten years. In
most cases, we can extend the term of our undeveloped leases by paying delay rentals or by
producing reserves that we discover under our leases.
(35)
The map below shows our areas of operations.
(36)
Producing Wells and Acreage
We have presented the table below to provide you with a summary of the producing oil
and natural gas wells and the developed and undeveloped acreage in which we owned an
interest at December 31, 2008. We have not included in the table acreage in which our
interest is limited to options to acquire leasehold interests, royalty or similar interests.
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Producing Wells(1) |
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Acreage |
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Oil(2) |
|
Gas |
|
Developed |
|
Undeveloped |
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Gross |
|
Net(3) |
|
Gross |
|
Net(3) |
|
Gross |
|
Net(4) |
|
Gross |
|
Net(4) |
Resource Projects |
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|
|
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|
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|
|
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|
|
|
|
|
|
|
|
|
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Barnett Shale |
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|
|
|
|
|
|
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90 |
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|
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22.40 |
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5,450 |
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|
1,401 |
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28,151 |
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8,936 |
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New Mexico |
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90 |
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51.74 |
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18,105 |
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13,386 |
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79,777 |
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64,115 |
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Total Resource Projects |
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|
180 |
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|
|
74.14 |
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23,555 |
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|
|
14,787 |
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|
|
107,928 |
|
|
|
73,051 |
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Permian Basin of West Texas |
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|
|
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|
|
|
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|
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Fullerton |
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170 |
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|
|
144.54 |
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|
|
|
|
|
|
|
|
|
|
3,683 |
|
|
|
3,155 |
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|
|
|
|
|
|
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Carm-Ann/N. Means Queen |
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95 |
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|
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81.69 |
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|
|
|
|
|
|
|
|
|
|
4,431 |
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|
|
3,949 |
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|
|
378 |
|
|
|
294 |
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Harris |
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|
84 |
|
|
|
74.94 |
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|
|
|
|
|
|
|
|
|
|
1,637 |
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|
|
1,476 |
|
|
|
3,428 |
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|
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3,217 |
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Diamond M |
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|
103 |
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|
|
91.10 |
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|
|
|
|
|
|
|
|
|
|
5,805 |
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|
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5,096 |
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|
|
|
|
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Other Permian |
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|
60 |
|
|
|
27.57 |
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|
|
13 |
|
|
|
10.80 |
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|
|
22,439 |
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|
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15,429 |
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|
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Total Permian Basin |
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512 |
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419.84 |
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13 |
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10.80 |
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37,995 |
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|
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29,105 |
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|
|
3,806 |
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|
|
3,511 |
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Onshore Gulf Coast of South Texas |
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Yegua/Frio/Wilcox |
|
|
3 |
|
|
|
0.62 |
|
|
|
27 |
|
|
|
6.48 |
|
|
|
4,332 |
|
|
|
1,895 |
|
|
|
2,643 |
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|
|
1,036 |
|
Cook Mountain |
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|
|
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|
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10 |
|
|
|
1.04 |
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|
|
1,482 |
|
|
|
166 |
|
|
|
74 |
|
|
|
14 |
|
|
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|
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Total Onshore Gulf Coast
of South Texas |
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|
3 |
|
|
|
0.62 |
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|
|
37 |
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|
|
7.52 |
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|
|
5,814 |
|
|
|
2,061 |
|
|
|
2,717 |
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|
|
1,050 |
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|
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|
|
|
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|
|
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|
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|
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|
Other Projects |
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|
|
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Cotton Valley |
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|
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|
|
|
|
|
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2 |
|
|
|
0.30 |
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|
|
1,121 |
|
|
|
100 |
|
|
|
19,726 |
|
|
|
3,544 |
|
Utah/Colorado |
|
|
11 |
|
|
|
0.34 |
|
|
|
|
|
|
|
|
|
|
|
160 |
|
|
|
156 |
|
|
|
179,932 |
|
|
|
175,786 |
|
|
|
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|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Total Other Projects |
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|
11 |
|
|
|
0.34 |
|
|
|
2 |
|
|
|
0.30 |
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|
|
1,281 |
|
|
|
256 |
|
|
|
199,658 |
|
|
|
179,330 |
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|
|
|
|
|
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|
|
|
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|
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|
|
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|
|
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|
|
|
|
|
|
|
|
|
|
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Grand Total |
|
|
526 |
|
|
|
420.80 |
|
|
|
232 |
|
|
|
92.76 |
|
|
|
68,645 |
|
|
|
46,209 |
|
|
|
314,109 |
|
|
|
256,942 |
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(1) |
|
Does not include 258 gross (131.30 net) wells that were shut in or
temporarily abandoned as of December 31, 2008. |
|
(2) |
|
Does not include 161 gross (134.29 net) injection wells as of December 31,
2008. |
|
(3) |
|
Net wells are computed by multiplying the number of gross wells by our
working interest in the gross wells. |
|
(4) |
|
Net acres are computed by multiplying the number of gross acres by our
working interest in the gross acres. |
At December 31, 2008, we owned interests in 533 gross (472.36 net) oil and natural gas
wells for which we were the operator and 644 gross (306.79 net) oil and natural gas wells
where we were not the operator.
The operator of a well has significant control over its location and the timing of its
drilling. In addition, the operator receives fees from other working interest owners as
reimbursement for general and administrative expenses for operating the wells.
Except for our oil and natural gas leases and related seismic data, we do not own any
patents, licenses, franchises or concessions which are significant to our oil and natural
gas operations.
For a more detailed description of our exploration and development activities, you
should read Item 1. Business Current Drilling Projects beginning on page 8 of this
Annual Report on Form 10-K.
(37)
Title to Properties
As is customary in the oil and natural gas industry, we make only a cursory review of
title to undeveloped oil and natural gas leases at the time they are acquired. These cursory
title reviews, while consistent with industry practices, are necessarily incomplete. We
believe that it is not economically feasible to review in depth every individual property we
acquire, especially in the case of producing property acquisitions covering a large number
of leases. Ordinarily, when we acquire producing properties, we focus our review efforts on
properties believed to have higher values and will sample the remainder. However, even an
in-depth review of all properties and records may not necessarily reveal existing or
potential defects nor will it permit a buyer to become sufficiently familiar with the
properties to assess fully their deficiencies and capabilities. In the case of producing
property acquisitions, inspections may not always be performed on every well, and
environmental problems, such as ground water contamination, are not necessarily observable
even when an inspection is undertaken. In the case of undeveloped leases or prospects we
acquire, before any drilling commences, we will usually cause a more thorough title search
to be conducted, and any material defects in title that are found as a result of the title
search are generally remedied before drilling a well on the lease commences. We believe that
we have good title to our oil and natural gas properties, some of which are subject to
immaterial encumbrances, easements and restrictions. The oil and natural gas properties we
own are also typically subject to consents to assignment, preferential purchase rights,
liens for current taxes not yet due and payable, royalty and other similar non-cost bearing
interests customary in the industry. We do not believe that any of these encumbrances or
burdens materially affect our ownership or the use of our properties.
Oil and Natural Gas Reserves
For the year ended December 31, 2008, our oil and natural gas reserves were estimated
by an independent engineering firm, Cawley, Gillespie & Associates, Inc., Fort Worth, Texas.
At December 31, 2008, our total estimated proved reserves were approximately 21.2
MMBbls of oil and approximately 71.8 Bcf of natural gas, or 33.2 MMBOE.
The information in the following table provides you with certain information regarding
our proved oil and natural gas reserves as estimated by Cawley, Gillespie & Associates, Inc.
at December 31, 2008.
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Proved Developed |
|
Proved Developed |
|
Proved |
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Total |
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|
Producing |
|
Non-Producing |
|
Undeveloped |
|
Proved |
Oil (MBbls) |
|
|
11,235 |
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|
|
902 |
|
|
|
9,069 |
|
|
|
21,206 |
|
Gas (MMcf) |
|
|
53,111 |
|
|
|
2,640 |
|
|
|
16,082 |
|
|
|
71,833 |
|
MBOE |
|
|
20,087 |
|
|
|
1,342 |
|
|
|
11,749 |
|
|
|
33,178 |
|
Proved oil and natural gas reserves are 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 (i.e., prices and costs as of the date the estimate is
made).
Proved developed oil and natural gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
(38)
Proved undeveloped oil and natural gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion.
The table below shows the production from our oil and natural gas properties for the
year ended December 31, 2008 and the proved reserves attributable to those properties as of
December 31, 2008.
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Reserves |
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|
Production |
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Total Proved |
|
|
Proved Developed |
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Natural |
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|
Natural |
|
|
|
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|
Natural |
|
|
|
Oil |
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|
Gas |
|
|
|
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|
Oil |
|
|
Gas |
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|
Oil |
|
|
Gas |
|
|
|
(MBbls) |
|
|
(MMcf) |
|
|
MBOE |
|
|
(MBbls) |
|
|
(MMcf) |
|
|
(MBbls) |
|
|
(MMcf) |
|
Resource Projects |
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|
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|
|
|
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|
Barnett Shale |
|
|
|
|
|
|
5,049 |
|
|
|
842 |
|
|
|
|
|
|
|
26,008 |
|
|
|
|
|
|
|
20,262 |
|
New Mexico Wolfcamp |
|
|
1 |
|
|
|
4,596 |
|
|
|
767 |
|
|
|
1 |
|
|
|
34,742 |
|
|
|
1 |
|
|
|
28,302 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Resource Projects |
|
|
1 |
|
|
|
9,645 |
|
|
|
1,609 |
|
|
|
1 |
|
|
|
60,750 |
|
|
|
1 |
|
|
|
48,564 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin of West Texas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fullerton |
|
|
518 |
|
|
|
91 |
|
|
|
533 |
|
|
|
7,628 |
|
|
|
1,208 |
|
|
|
7,286 |
|
|
|
1,143 |
|
Carm-Ann San |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Andres/N. Means Queen |
|
|
122 |
|
|
|
60 |
|
|
|
132 |
|
|
|
3,424 |
|
|
|
1,600 |
|
|
|
919 |
|
|
|
299 |
|
Harris |
|
|
185 |
|
|
|
38 |
|
|
|
191 |
|
|
|
5,093 |
|
|
|
677 |
|
|
|
1,617 |
|
|
|
269 |
|
Diamond M |
|
|
144 |
|
|
|
182 |
|
|
|
174 |
|
|
|
4,731 |
|
|
|
3,138 |
|
|
|
1,986 |
|
|
|
1,017 |
|
Other Permian Basin |
|
|
37 |
|
|
|
254 |
|
|
|
80 |
|
|
|
246 |
|
|
|
2,308 |
|
|
|
245 |
|
|
|
2,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Permian Basin |
|
|
1,006 |
|
|
|
625 |
|
|
|
1,110 |
|
|
|
21,122 |
|
|
|
8,931 |
|
|
|
12,053 |
|
|
|
5,036 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Gulf Coast of South Texas |
|
|
20 |
|
|
|
674 |
|
|
|
132 |
|
|
|
83 |
|
|
|
2,152 |
|
|
|
83 |
|
|
|
2,151 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
1,027 |
|
|
|
10,944 |
|
|
|
2,851 |
|
|
|
21,206 |
|
|
|
71,833 |
|
|
|
12,137 |
|
|
|
55,751 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimates of our proved reserves and future net revenues are made using sales prices
and costs, estimated to be in effect as of the date of our reserve estimates that are held
constant throughout the life of the properties, except to the extent a contract specifically
provides for escalation of prices or costs. The average prices, as adjusted for location
differentials, utilized in the estimation of our reserve calculations as of December 31,
2008 were $40.00 per Bbl of oil and $5.18 per Mcf of natural gas.
For additional information concerning our estimated proved oil and natural gas
reserves, you should read Item 7. Managements Discussion and Analysis-Critical Accounting
Policies and Practices and Note 17- Supplemental Oil and Natural Gas Reserve Data
(Unaudited).
The reserve data in this Annual Report on Form 10-K represent estimates only. Reservoir
engineering is a subjective process. There are numerous uncertainties inherent in estimating
our oil and natural gas reserves and their estimated values. Many factors are beyond our
control. Estimating underground accumulations of oil and natural gas cannot be measured in
an exact manner. The accuracy of any reserve estimate is a function of the quality of
available data, engineering and geological interpretation and judgment and the costs we
actually incur in the development of our reserves. As a result, estimates of different
engineers often vary. In addition, estimates of reserves are subject to revision by the
results of drilling, testing and production after the date of the estimates. Consequently,
reserve estimates are often different from the quantities of oil and natural gas that are
ultimately recovered. The meaningfulness of estimates is highly dependent upon the accuracy
of the assumptions upon which they were based.
The volume of production from oil and natural gas properties declines as reserves are
produced and depleted. Unless we acquire properties containing proved reserves or conduct
successful drilling activities, our proved reserves will decline as we produce our existing
reserves. Our future oil and natural gas production is highly dependent upon our level of
success in acquiring or finding additional reserves.
(39)
We do not have any oil or natural gas reserves outside the United States. Our oil and
natural gas reserves and production are not subject to any long term supply or similar
agreements with foreign governments or authorities.
Our estimated reserves have not been filed with or included in reports to any federal
agency other than the Securities and Exchange Commission.
ITEM 3. LEGAL PROCEEDINGS
On April 14, 2008, we were added as a defendant to a lawsuit filed in 2007, styled
Brady Briscoe vs. Capstar Drilling, L.P. (Capstar), Cause No. 21,287, in the 259th
District Court of Jones County, Texas. The plaintiff alleged that he was injured as the
result of an accident while he was working, as an employee of an unrelated third party, on a
drilling rig operated by Capstar. Capstar was conducting drilling operations for us. The
plaintiff asserted general allegations of negligence as to Capstar and, specifically, a
failure to properly equip its drilling rig, further alleging we were in charge of the
drilling rig and the operational details of the plaintiffs work. The plaintiff sued for an
amount of actual damages of up to $15.0 million, together with pre-judgment interest,
post-judgment interest and exemplary damages. Capstar recently settled with the plaintiff
and Capstar was dismissed from the lawsuit. If judgment is entered against us, we would be
entitled to a credit for the amount that the plaintiff has already received from Capstar.
On November 13, 2008, the plaintiff filed notice of non-suit, without prejudice, of all
claims and causes of action asserted against us.
On March 24, 2008, a lawsuit was filed in the 24th District Court of Jackson
County, Texas, against us and twenty-two other defendants in Cause No. 07-6-13069, styled
Tony Kubenka, Carolyn Kubenka, Dennis J. Kallus, David J. Kallus, Mary L. Kallus, Patricia
Kallus, Nova Deleon, Janie Figuerova, and Larkin Thedford, Plaintiffs v. Tri-C Resources,
Inc., Marie S. Adian, Laura E. Adian, Glenn A. Fiew, Lynn Kramer, Debra Boysen, Carol J.
Gleason, Alana Sue Curlee, Connie W. Marthiljohni, Claire E. Adian, Zachary D. Adian, Donald
R. Starkweather, Inc., D.A. Webernick, Danette Bundick, Johnny A. Webernick, Donna Gail
Glover, Sherry Shulze, William H. Webernick, Jr., TAC Resources, Inc., New Century
Exploration, Inc., Allegro Investments, Inc., Parallel Petroleum Corporation and Welper
Interests, LP. The nine plaintiffs in this lawsuit have named us and the other working
interest owners, including Tri-C Resources, Inc., the operator, as defendants. The
plaintiffs in this lawsuit allege that they are royalty owners under oil and gas leases
which are part of a pooled gas unit (the unit) located in Jackson County, Texas, and that
the defendants, including us, are owners of the leasehold estate under the plaintiffs
leases and others forming the unit. Plaintiffs also assert that one of the leases (other
than plaintiffs leases) forming part of the unit has been terminated and, as a result, the
defendants have not properly computed the royalties due to plaintiffs from unit production
and have failed to properly pay royalties due to them. Plaintiffs have sued for an
unspecified amount of damages, including exemplary damages, under theories of breach of
contract (including breach of express and implied covenants of their leases) and conversion,
and seek an accounting, a declaratory judgment to declare the rights of the parties under
the leases, and attorneys fees, interest and court costs. If a judgment adverse to the
defendants were entered, as a working interest owner in the leases comprising the unit, we
believe our liability would be proportionate to the ownership of the other working interest
owners in the leases. We have filed an answer denying any liability. Although an initial
exchange of discovery has occurred, we cannot predict the ultimate outcome of this matter,
but believe we have meritorious defenses and intend to vigorously contest this lawsuit. We
have not established a reserve with respect to plaintiffs claims.
We received a Notice of Proposed Adjustment from the Internal Revenue Service, or the
Service in May 2007 advising us of proposed adjustments to federal income tax of
approximately $2.0 million for the years 2004 and 2005. Subsequent discussions with the
Service placed the issues contested in a development status. In November 2007, the Service
issued a letter on the matter giving us 30 days to agree or disagree with a final
examination report. The final examination report reflected revisions of the previous
proposed adjustments resulting in a reduced $1.1 million of additional income tax and
interest
(40)
charges. The decrease in proposed tax was the result of information supplied by us
to the examiner as well as discussions of the applicable tax statutes and regulations. In
December 2007, we filed a protest
documenting our complete disagreement with the adjustments proposed on the final
examination report and requested a conference with the appeals office of the Service. The
examination office of the Service filed a response to our protest in February 2008 with the
appeals office. In response, the additional tax was further reduced by the examination
office to $720,000. In June and November of 2008, our representatives met with the
Services Appeals Officer to review specific issues related to the alternative minimum tax
items in dispute. During these meetings we submitted supplements to our initial protest in
further support of our position. Currently, the IRS appeals office is considering our
information as well as data supplied at the request of the appeals officer. We intend to
vigorously contest the adjustment proposed by the Service and believe that we will
ultimately prevail in our position. We have not recorded a liability for tax, interest, or
penalties related to this matter based on our analysis. If a liability for additional
income tax should later be determined to be more likely than not, we anticipate the
adjustment to increase the federal income tax liability would be offset by an increase to a
deferred tax asset and would not result in a charge to earnings. Any interest or penalties
resulting from a subsequent determination of increased tax liability would require a charge
to earnings. We believe that the effects of this matter would not have a material effect on
our results of operations for the fiscal quarter in which we actually incur or establish a
reserve account for interest or penalties.
We are also presently a named defendant in one other lawsuit arising out of our
operations in the normal course of business, which we believe is not material.
We are not aware of any legal or governmental proceedings against us, or contemplated
to be brought against us, under the various environmental protection statutes to which we
are subject, nor have we been a party to any bankruptcy, receivership, reorganization,
adjustment or similar proceeding.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
We did not submit any matter to a vote of our stockholders during the fourth quarter of
2008.
(41)
PART II
|
|
|
ITEM 5. |
|
MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES |
Market Information
Our
common stock trades on the Nasdaq Global Select Market under the symbol PLLL. The
following table shows, for the periods indicated, the high and low closing price per share
for our common stock as reported on the Nasdaq Global Select Market.
|
|
|
|
|
|
|
|
|
|
|
Closing Price Per Share |
|
|
High |
|
Low |
2006
|
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
21.13 |
|
|
$ |
15.67 |
|
Second Quarter |
|
$ |
25.56 |
|
|
$ |
18.47 |
|
Third Quarter |
|
$ |
26.39 |
|
|
$ |
18.90 |
|
Fourth Quarter |
|
$ |
20.96 |
|
|
$ |
16.34 |
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
23.31 |
|
|
$ |
16.00 |
|
Second Quarter |
|
$ |
24.69 |
|
|
$ |
21.79 |
|
Third Quarter |
|
$ |
22.88 |
|
|
$ |
16.76 |
|
Fourth Quarter |
|
$ |
20.96 |
|
|
$ |
16.65 |
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
19.88 |
|
|
$ |
13.15 |
|
Second Quarter |
|
$ |
23.22 |
|
|
$ |
19.21 |
|
Third Quarter |
|
$ |
20.79 |
|
|
$ |
8.62 |
|
Fourth Quarter |
|
$ |
8.87 |
|
|
$ |
1.61 |
|
The
closing price of our common stock on February 19, 2009 was $1.99 per share, as
reported on the Nasdaq Global Select Market.
As
of February 19, 2009, there were approximately 1,323 stockholders of record. This
number does not include any beneficial owners for whom shares of common stock may be held in
nominee or street name.
Dividends
We have not paid, and do not intend to pay in the foreseeable future, cash dividends on
our common stock. We intend to retain earnings to fund our capital expenditures and for
general corporate purposes. Any declaration of dividends will be at the discretion of our
Board of Directors and will depend upon the earnings, financial condition, capital
requirements, level of indebtedness, contractual restrictions with respect to payment of
dividends and other factors. Our revolving credit facility and the Indenture governing our
101/4% senior notes prohibit our ability to pay dividends on our common stock. See Risks
Related to Our Common Stock We do not pay dividends on our
common stock on page 29.
Sale of Unregistered Securities
At our annual meeting of stockholders held on June 22, 2004, our stockholders approved
the Parallel Petroleum Corporation 2004 Non-Employee Director Stock Grant Plan. Only
Directors of Parallel who are not employees of Parallel or any of its subsidiaries are
eligible to participate in this plan. Under this plan, each non-employee Director is
entitled to receive shares of common stock that are automatically granted on the first day
of July in each year. The actual number of shares received is
(42)
determined by dividing $25,000 by the average daily closing price of the common stock on the
Nasdaq Global Market for the ten consecutive trading days commencing fifteen trading days before
the first day of July of each year. On July 1, 2008, and in accordance with the terms of the plan,
a total of 4,612 shares of common stock were granted to four non-employee Directors as follows:
Jeffrey G. Shrader 1,153 shares; Edward A. Nash 1,153 shares; Martin B. Oring 1,153
shares; and Ray M. Poage 1,153 shares. The shares of common stock were issued without
registration under the Securities Act of 1933, as amended or, the Securities Act, in reliance on
the exemption provided by Section 4(2) of the Securities Act. Generally, shares issued under this
plan are not transferable as long as the non-employee Director holding the shares remains a
Director of Parallel. You can find more information about the 2004 Non-Employee Director Stock
Grant Plan on page F-36.
As a further part of the overall compensation of our non-employee Directors, we granted and
issued an additional 7,648 shares of common stock to our four non-employee Directors on June 12,
2008. These stock grants were awarded under our 2008 Long-Term Incentive Plan which was approved by
our stockholders at last years annual meeting held on May 28, 2008. Each non-employee Director was
awarded 1,912 shares of common stock, representing $40,000 divided by $20.91, the closing price of
our common stock on the date of grant. In addition to the stock grants described above, Edward A.
Nash was also awarded a one-time restricted stock grant of 10,000 shares of common stock. This
stock grant vests in four equal annual installments beginning on June 12, 2008, the date of grant.
The shares of common stock were issued without registration under the Securities Act in reliance on
the exemption provided by Section 4(2). You can find more information about the 2008 Long-Term
Incentive Plan on page F-37.
Repurchase of Equity Securities
Neither we nor any affiliated purchaser repurchased any of our equity securities during the
fiscal year ended December 31, 2008.
(43)
ITEM 6. SELECTED FINANCIAL DATA
In the table below, we provide you with selected historical financial data for each of the
years in the five-year period ended December 31, 2008. We have prepared this information using our
audited Consolidated Financial Statements for the five-year period ended December 31, 2008. It is
important that you read this financial data along with our audited Consolidated Financial
Statements and related notes, and Managements Discussion and Analysis of Financial Condition and
Results of Operations under Item 7 below. The selected financial data provided are not necessarily
indicative of our future results of operations or financial performance.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2008(1) |
|
2007 |
|
2006(2) |
|
2005 |
|
2004 |
|
|
(in thousands, except per share and per unit data) |
Consolidated Income Statement Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
182,515 |
|
|
$ |
116,031 |
|
|
$ |
97,025 |
|
|
$ |
66,150 |
|
|
$ |
35,837 |
|
Operating expenses |
|
$ |
392,761 |
|
|
$ |
67,066 |
|
|
$ |
56,606 |
|
|
$ |
32,805 |
|
|
$ |
23,571 |
|
Net income (loss) |
|
$ |
(131,894 |
) |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
$ |
(1,589 |
) |
|
$ |
2,271 |
|
Cumulative preferred stock dividend |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(271 |
) |
|
$ |
(572 |
) |
Net income (loss) |
|
$ |
(131,894 |
) |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
$ |
(1,860 |
) |
|
$ |
1,699 |
|
|
Income (loss) per common share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(3.18 |
) |
|
$ |
(0.12 |
) |
|
$ |
0.73 |
|
|
$ |
(0.06 |
) |
|
$ |
0.07 |
|
Diluted |
|
$ |
(3.18 |
) |
|
$ |
(0.12 |
) |
|
$ |
0.71 |
|
|
$ |
(0.06 |
) |
|
$ |
0.07 |
|
|
Weighted
average common stock and common stock equivalents outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
41,471 |
|
|
|
38,120 |
|
|
|
35,888 |
|
|
|
32,253 |
|
|
|
25,323 |
|
Diluted |
|
|
41,471 |
|
|
|
38,120 |
|
|
|
36,756 |
|
|
|
32,253 |
|
|
|
25,688 |
|
|
Cash dividends common stock |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
Consolidated Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
550,576 |
|
|
$ |
563,093 |
|
|
$ |
442,818 |
|
|
$ |
253,008 |
|
|
$ |
170,671 |
|
Total liabilities |
|
$ |
443,530 |
|
|
$ |
327,831 |
|
|
$ |
259,036 |
|
|
$ |
163,506 |
|
|
$ |
110,677 |
|
Long-term debt, less current maturities |
|
$ |
370,890 |
|
|
$ |
205,383 |
|
|
$ |
165,000 |
|
|
$ |
100,000 |
|
|
$ |
79,000 |
|
Total stockholders equity |
|
$ |
107,046 |
|
|
$ |
235,262 |
|
|
$ |
183,782 |
|
|
$ |
89,502 |
|
|
$ |
59,994 |
|
|
Consolidated Statement of Cash Flow Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
121,041 |
|
|
$ |
74,119 |
|
|
$ |
68,186 |
|
|
$ |
35,359 |
|
|
$ |
17,415 |
|
Investing activities |
|
$ |
(258,297 |
) |
|
$ |
(164,897 |
) |
|
$ |
(194,548 |
) |
|
$ |
(83,190 |
) |
|
$ |
(68,777 |
) |
Financing activities |
|
$ |
165,743 |
|
|
$ |
92,684 |
|
|
$ |
125,854 |
|
|
$ |
49,468 |
|
|
$ |
38,765 |
|
|
Operating Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Product Sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
1,027 |
|
|
|
1,051 |
|
|
|
1,137 |
|
|
|
923 |
|
|
|
729 |
|
Gas (M cf) |
|
|
10,944 |
|
|
|
7,422 |
|
|
|
6,539 |
|
|
|
3,592 |
|
|
|
2,690 |
|
BOE |
|
|
2,851 |
|
|
|
2,288 |
|
|
|
2,227 |
|
|
|
1,522 |
|
|
|
1,177 |
|
Average
sales price(3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
95.25 |
|
|
$ |
65.97 |
|
|
$ |
59.86 |
|
|
$ |
51.78 |
|
|
$ |
39.05 |
|
Gas (per M cf) |
|
$ |
7.74 |
|
|
$ |
6.29 |
|
|
$ |
6.19 |
|
|
$ |
8.54 |
|
|
$ |
5.85 |
|
Proved reserves |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
21,206 |
|
|
|
28,434 |
|
|
|
28,721 |
|
|
|
21,192 |
|
|
|
18,916 |
|
Gas (M cf) |
|
|
71,833 |
|
|
|
57,234 |
|
|
|
58,896 |
|
|
|
25,237 |
|
|
|
16,825 |
|
(44)
|
|
|
(1) |
|
Includes $300.5 million impairment of oil and natural
gas properties. See Note 5- Oil and Natural Gas Properties |
|
(2) |
|
Results include $9.0 million of equity in income of pipeline and gathering systems
representing our share of net gain on sale of certain pipeline assets. |
|
(3) |
|
Excludes the effects of hedging. |
|
|
|
ITEM 7. |
|
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion and analysis is intended to assist you in understanding our financial
position and results of operations for each year in the three-year period ended December 31, 2008.
You should read the following discussion and analysis in conjunction with our selected financial
data and our accompanying audited Consolidated Financial Statements and the related notes to those
financial statements included elsewhere in this report.
The following discussion and analysis contains forward-looking statements. For a description
of limitations inherent in forward-looking statements, see Cautionary Statement Regarding
Forward-Looking Statements on page (i).
Overview and Strategy
We are a Midland, Texas-based independent oil and natural gas exploration and production
company focused on the acquisition, development and exploitation of long-lived oil and natural gas
reserves and, to a lesser extent, exploring for new oil and natural gas reserves. The majority of
our current producing properties are in the Permian Basin of west Texas and New Mexico, the Fort
Worth Basin of north Texas, and the onshore Gulf Coast area of south Texas.
Our primary objective is to increase stockholder value by increasing reserves, production,
cash flow and earnings. We attempt to target our investments in properties expected to produce
consistently over the longer term, as contrasted to investments in properties having high rates of
production in early years followed by rapid production declines. We also attempt to reduce our
financial risks by dedicating a smaller portion of our capital to high risk projects, while
reserving the majority of our available capital for acquisitions, exploitation and development
drilling opportunities. Obtaining positions in long-lived oil and natural gas reserves are given
priority over properties that might provide more cash flow in the early years of production, but
which have shorter reserve lives. We also attempt to further reduce risk by emphasizing acquisition
possibilities over high risk exploration projects.
Rather than emphasizing high risk exploration activities, we focus on established geologic
trends where we can utilize the engineering, operational, financial and technical expertise of our
entire staff. Although we expect to continue participating in exploratory drilling activities from
time to time, reducing financial, reservoir, drilling and geological risks and diversifying our
property portfolio are important criteria in the execution of our business plan. In summary, our
current business plan:
|
|
|
focuses on projects having less geologic risk; |
|
|
|
|
emphasizes acquisition, exploitation, development and enhancement
activities; |
|
|
|
|
includes the utilization of horizontal and fracture stimulation technologies
on certain types of reservoirs; |
|
|
|
|
focuses on acquiring producing properties; and |
|
|
|
|
expands the scope of operations by diversifying our exploratory and
development efforts, both in and outside of our primary areas of operation. |
(45)
In addition to directing our exploration and development activities towards lower-risk
development opportunities, we continually seek ways to maintain our expenses at levels we believe
to be compatible with the size of our overall operations, utilize advanced technologies, serve as
operator in appropriate circumstances, and reduce operating costs.
The extent to which we are able to implement and follow through with our business plan is
influenced by:
|
|
|
the prices we receive for the oil and natural gas we produce; |
|
|
|
|
the results of reprocessing and reinterpreting our 3-D seismic data; |
|
|
|
|
the results of our drilling activities; |
|
|
|
|
the costs of obtaining high quality field services; |
|
|
|
|
our ability to find and consummate acquisition opportunities; |
|
|
|
|
our ability to negotiate and enter into work to earn arrangements, joint
ventures or other similar arrangements on terms acceptable to us; and |
|
|
|
|
sources and availability of funds to conduct operations and complete
acquisitions. |
Significant changes in the prices we receive for our oil and natural gas, or the occurrence of
unanticipated events beyond our control, such as the recent and dramatic downturn in the financial
markets, can cause us to defer or deviate from our business plans, including the amounts we have
budgeted for our activities. In this regard, please read Item 1. Business Developments in 2008
and 2009 and - 2009 Capital Budget.
Operating Performance
Our operating performance is influenced by several factors, the most significant of which are
the prices we receive for our oil and natural gas and the quantities of oil and natural gas that we
are able to produce. The world price for oil has overall influence on the prices that we receive
for our oil production. The prices received for different grades of oil are based upon the world
price for oil, which is then adjusted based upon the particular grade. Typically, light oil is sold
at a premium, while heavy grades of crude are discounted. Natural gas prices we receive are
influenced by:
|
|
|
seasonal demand; |
|
|
|
|
weather; |
|
|
|
|
hurricane conditions in the Gulf of Mexico; |
|
|
|
|
availability of pipeline transportation to end users; |
|
|
|
|
proximity of our wells to major transportation pipeline infrastructures; and |
|
|
|
|
to a lesser extent, world oil prices. |
Additional factors influencing our overall operating performance include:
|
|
|
production expense; |
|
|
|
|
overhead requirements; |
|
|
|
|
costs of capital; and |
|
|
|
|
effects of our derivative contracts. |
(46)
Results of Operations
Our oil and natural gas reserves at the end of 2008 were approximately 33.2 MMBoe with a
reserves to production ratio of approximately 11.6 to 1. Our reserve to production ratio was 16.6
to 1 in 2007. The drop in this ratio from 2007 to 2008 was primarily
the result of the decline in commodity prices in 2008. As described on page 21 of this Annual Report on Form 10-K, the
failure to replace oil and natural gas reserves may negatively affect our business. We monitor this
risk by comparing the quantity of our oil and natural gas reserves at the end of each year to our
production for that year. This comparison, which is made in the form of a reserves to production
ratio, helps us measure our ability to offset produced volumes with new reserves that will be
produced in the future. The reserves to production ratio is calculated by dividing the total proved
reserves at the end of a year by the actual production for the same year. The annual change in this
ratio provides us with an indication of our performance in replenishing annual production volumes.
The reserves to production ratio is a statistical indicator that has limitations. The ratio is
limited because it can vary widely based on the extent and timing of new discoveries and property
acquisitions. In addition, the ratio does not take into account the cost or timing of future
production of new reserves and commodity pricing. For that reason, the ratio does not, and is not
intended to, provide a measurement of value. For the year ended December 31, 2007, our production
was 54% natural gas and 46% oil, as compared to approximately 64% natural gas and 36% oil for the
year ended December 31, 2008.
Our business activities are characterized by frequent, and sometimes significant, changes in
our:
|
|
|
reserve base; |
|
|
|
|
sources of production; |
|
|
|
|
product mix (gas versus oil volumes); and |
|
|
|
|
the prices we receive for our oil and natural gas production. |
Year-to-year or other periodic comparisons of the results of our operations can be difficult
and may not fully and accurately describe our condition.
The following table shows selected operating data and operating income comparisons for each of
the three years ended December 31, 2008.
(47)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands, except per unit data) |
|
Production Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
1,027 |
|
|
|
1,051 |
|
|
|
1,137 |
|
Natural gas (Mcf) |
|
|
10,944 |
|
|
|
7,422 |
|
|
|
6,539 |
|
BOE |
|
|
2,851 |
|
|
|
2,288 |
|
|
|
2,227 |
|
BOE per day |
|
|
7.8 |
|
|
|
6.3 |
|
|
|
6.1 |
|
Sale Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)(1) |
|
$ |
95.25 |
|
|
$ |
65.97 |
|
|
$ |
59.86 |
|
Natural gas (per Mcf)(1) |
|
$ |
7.74 |
|
|
$ |
6.29 |
|
|
$ |
6.19 |
|
BOE Price(1) |
|
$ |
64.02 |
|
|
$ |
50.72 |
|
|
$ |
48.73 |
|
BOE Price(2) |
|
$ |
64.02 |
|
|
$ |
50.72 |
|
|
$ |
43.56 |
|
Operating Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
97,799 |
|
|
$ |
69,315 |
|
|
$ |
68,076 |
|
Effect of oil hedges |
|
|
|
|
|
|
|
|
|
|
(11,512 |
) |
Natural gas |
|
|
84,716 |
|
|
|
46,716 |
|
|
|
40,461 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
182,515 |
|
|
|
116,031 |
|
|
|
97,025 |
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
|
28,454 |
|
|
|
22,200 |
|
|
|
16,819 |
|
Production taxes |
|
|
9,135 |
|
|
|
5,545 |
|
|
|
5,577 |
|
Production tax refund |
|
|
(1,958 |
) |
|
|
(1,209 |
) |
|
|
|
|
General and administrative |
|
|
11,907 |
|
|
|
10,415 |
|
|
|
9,523 |
|
Depreciation, depletion and amortization |
|
|
44,691 |
|
|
|
30,115 |
|
|
|
24,687 |
|
Impairment of oil and natural gas properties |
|
|
300,532 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
392,761 |
|
|
|
67,066 |
|
|
|
56,606 |
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
$ |
(210,246 |
) |
|
$ |
48,965 |
|
|
$ |
40,419 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes hedge transactions. |
|
(2) |
|
Includes hedge transactions. |
Critical Accounting Policies and Practices
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States requires us to make estimates and use assumptions that can affect the
reported amounts of assets, liabilities, revenues or expenses. Certain accounting policies that
require significant management estimates and that are deemed critical to our results of operations
or financial position are discussed below. Our management reviews our critical accounting policies
with the Audit Committee of our Board of Directors.
Use of Critical Accounting Estimates in the Preparation of Consolidated Financial
Statements. The preparation of our consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America (GAAP) requires management
to make certain estimates and assumptions. These estimates and assumptions affect the reported
amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the
balance sheet date and the amounts of revenues and expenses recognized during the reporting period.
We analyze our estimates based on historical experience and various other assumptions that we
believe to be reasonable under the circumstances. However, actual results could differ from such
estimates. We define a critical accounting estimate as one that is both important to our financial
condition and results of operations and requires us to make difficult, subjective or complex
judgments or estimates about matters that are uncertain.
(48)
Significant estimates include volumes of oil and natural gas reserves, abandonment
obligations, impairment of undeveloped properties, income taxes, bad debts, derivatives,
contingencies and litigation.
Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion
and the ceiling test, have a number of inherent uncertainties. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and geological
interpretation and judgment. Results of drilling, testing, and production subsequent to the date
of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often
different from the quantities of oil and natural gas that are ultimately recovered. In addition,
reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such
prices have been volatile in the past and can be expected to be volatile in the future.
Full Cost and Impairment of Assets. We account for our oil and natural gas exploration
and development activities using the full cost method of accounting. Under this method, all costs
incurred in the acquisition, exploration and development of oil and natural gas properties are
capitalized. Costs of non-producing properties, wells in process of being drilled and significant
development projects are excluded from depletion until such time as the related project is
developed and proved reserves are established or impairment is determined.
At the end of each quarter, capitalized costs, less accumulated amortization and related
deferred income taxes, are limited to an amount (the ceiling) equal to the sum of: (i) The after
tax present value of estimated future net revenues computed by applying current prices of oil and
gas reserves to estimated future production of proved oil and gas reserves as of the date of the
latest balance sheet presented, less estimated future expenditures (based on current costs) to be
incurred in developing and producing the
proved reserves computed using a discount factor of ten percent and assuming continuation of
existing economic conditions; (ii) the cost of properties not being amortized; and (iii) the lower
of cost or estimated fair value of unproven properties included in the costs being amortized. If
unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the
ceiling, the excess shall be charged to expense and separately disclosed during the period in which
the excess occurs. Amounts thus required to be written off shall not be reinstated for any
subsequent increase in the cost center ceiling. A ceiling test write-down is a non-cash charge to
earnings. It reduces earnings and impacts stockholders equity in the period of occurrence and may
result in lower depreciation, depletion and amortization expense in future periods. At December
31, 2008, the net book value of our oil and natural gas properties, less related deferred income
taxes, was above the calculated ceiling. As a result, we were required to record an impairment of
our oil and natural gas properties under the full cost method of
accounting in the amount of $300.5 million for the year ended December 31, 2008. See Note 5- Oil and Natural Gas Properties.
The risk that we will be required to write down the carrying value of oil and natural gas
properties increases when oil and natural gas prices decline. If commodity prices decline further,
it is possible that we could incur additional impairments in future periods.
Depletion. Provision for depletion of oil and natural gas properties under the full
cost method is calculated using the unit of production method based upon estimates of proved oil
and natural gas reserves with oil and natural gas production being converted to a common unit of
measurement based upon relative energy content. Investments in unproved properties and major
development projects are not amortized until proved reserves associated with the projects can be
determined or until impairment occurs. The cost of any impaired property is transferred to the
balance of oil and natural gas properties subject to depletion. The amortizable base includes
estimated future development costs and where significant, dismantlement, restoration and
abandonment costs, net of estimated salvage value. Oil and natural
gas properties included $137.2
million and $86.4 million at December 31, 2008 and 2007, respectively, of unevaluated properties
not subject to depletion.
(49)
In arriving at rates under the unit of production method, the quantities of recoverable oil
and natural gas reserves are established based on estimates made by our geologists and engineers
and require significant judgment as does the projection of future production volumes and levels of
future costs, including future development costs. In addition, considerable judgment is necessary
in determining when unproved properties become impaired and in determining the existence of proved
reserves once a well has been drilled. All of these judgments may have significant impact on the
calculation of depletion expense. There have been no material changes in our methodology of
calculating the depletion of oil and natural gas properties under the full cost method during the
three years ended December 31, 2008.
Proved Reserve Estimates. The discounted present value of our proved oil and natural
gas reserves is a major component of the ceiling calculation, and represents the component that
requires the most subjective judgments. Estimates of reserves are forecasts based on engineering
data, projected future rates of production and the timing of future expenditures. The process of
estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise
determinations, particularly for new discoveries. Different reserve engineers may make different
estimates of reserve quantities based on the same data. Our year-end reserve estimates are prepared
by independent petroleum engineers.
The passage of time provides more qualitative information regarding estimates of reserves, and
revisions are made to prior estimates to reflect updated information. However, there can be no
assurance that more significant revisions will not be necessary in the future. If future revisions
significantly reduce previously estimated reserve quantities, it could result in a full cost
ceiling write-down. In addition to the impact of the estimates of proved reserves in calculating
the ceiling test, estimates of proved reserves are also a significant component of the calculations
of depreciation, depletion and amortization.
While estimates of the quantities of proved reserves require substantial subjective judgment,
the associated prices of oil and natural gas reserves that are included in the discounted present
value of the reserves do not require judgment. Accounting principles generally accepted in the
United States require that prices and costs in effect as of the last day of the period are held
constant indefinitely. Accordingly, the resulting value is not indicative of the true fair value of
the reserves. Oil and natural gas prices have historically been cyclical and, on the last day of a
quarter, can be either substantially higher or lower than prices we actually receive in the
long-term, which are a barometer for true fair value.
Income Taxes. We provide for income taxes in accordance with Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). This standard takes into
account the differences between financial statement treatment and tax treatment of certain
transactions. Deferred tax assets and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying amounts of existing assets and
liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. Our deferred tax calculation requires us to
make certain estimates about our future operations. Changes in state, federal and foreign tax laws,
as well as changes in our financial condition or the carrying value of existing assets and
liabilities, could affect these estimates. The effect of a change in tax rates is recognized as
income or expense in the period that includes the enactment date. Additionally, the amount and
availability of our loss carryforwards (and certain other tax attributes) are subject to a variety
of interpretations and restrictive tests. The utilization of such carryforwards could be limited or
lost upon certain changes in ownership and the passage of time. Although we believe it is more
likely than not that we will be able to utilize all our loss carryforwards available to us, no
assurance can be given concerning the realization of such loss carryforwards, or whether or not
such loss carryforwards will be available in the future.
Asset Retirement Obligations. Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations (SFAS 143) requires us to record the fair value of
an asset retirement obligation as a liability in the period in which it incurs a legal obligation
associated with the retirement of tangible long-lived assets and to capitalize an equal amount as a
cost of the asset,
(50)
depreciating it over the life of the asset. Subsequent to the initial
measurement of the asset retirement obligation, the obligation is adjusted at the end of each
quarter to reflect the passage of time, changes in the estimated future cash flows underlying the
obligation, changes in the estimated timing of the cash flows, acquisition or construction of
assets, and settlement of obligations.
Stock Based Compensation. We account for stock based compensation in accordance with
the Financial Accounting Standards Board (FASB) SFAS No. 123 (revised 2004), Share-Based Payment,
(SFAS 123 (R)). We adopted SFAS 123(R) effective January 1, 2006, applying the modified
prospective method, whereby compensation cost associated with the unvested portion of awards
granted during the period of June 2001 to December 2002 were recognized over the remaining vesting
period. Under this method, prior periods were not revised for comparative purposes.
Litigation and Other Contingency Reserves. We estimate our reserves related to
litigation and other contingencies based on the facts and circumstances specific to the litigation
and contingency and our past experience with similar claims. The actual outcome of litigation and
contingencies could differ significantly from estimated amounts.
Allowance for Doubtful Accounts. We maintain an allowance for doubtful accounts for
estimated losses resulting from the inability of some of our customers to make required payments.
These estimated allowances are periodically reviewed, on a case by case basis, analyzing the
customers payment history and information regarding customers creditworthiness known to us. In
addition, we record a reserve based on the size and age of all receivable balances against which we
do not have specific reserves. If the financial condition of our customers was to deteriorate,
resulting in their inability to make payments, additional allowances may be required.
Derivatives. The Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS
133), as amended by Statement of Financial Accounting Standards No. 138, Accounting for Certain
Derivative Instruments and Certain Hedging Activities on Amendment of FASB Statement No. 133
(SFAS 138) that requires all derivative instruments to be recorded on the balance sheet at their
respective fair values. We adopted SFAS 133 on January 1, 2001.
To measure fair value we adopted SFAS No. 157, Fair Value
Measurements (SFAS 157), effective January 1,
2008 for all financial assets and liabilities. In determining the fair
value of our derivative contracts, we evaluate our counterparty and
third party service provider valuations and adjust for credit risk
when appropriate. We classify our fair value measurements as Level 3
if we do not have sufficient corroborating market evidence for volatility to support
classifying these assets and liabilities as Level 2. See Note 9-
Derivatives.
During the period from January 1, 2003 to June 30, 2004, new derivative contracts were
designated as cash flow hedges. These contracts remained designated as cash flow hedges through
their settlement. Accordingly, the effective portion of the unrealized gains or losses was recorded
in other comprehensive loss until the settlement of the contract position occurred. At settlement
of these contracts, the cash value paid was recorded in revenue along with oil and natural gas
sales, or in interest expense along with the interest expense that we incurred under our credit
facilities. As of December 31, 2006, we had no remaining contracts which were designated as
hedges.
Although we have designated our derivative contracts differently in different periods, the
purpose of all of our derivative contracts is to provide a measure of stability in our oil and
natural gas receipts and interest rate payments and to manage exposure to commodity price and
interest rate risk under existing sales contracts.
(51)
Years Ended December 31, 2008 and December 31, 2007
The following discussion compares our result for the year ended December 31, 2008 to the year
ended December 31, 2007. Unless otherwise indicated, references to 2008 and 2007 within this
section refer to the respective annual periods.
Our oil and natural gas revenues and production product mix are shown in the following table
for 2008 and 2007.
Oil and Gas Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
Production |
|
|
2008 |
|
2007 |
|
2008 |
|
2007 |
Oil (Bbls) |
|
|
54 |
% |
|
|
60 |
% |
|
|
36 |
% |
|
|
46 |
% |
Natural gas (M cf) |
|
|
46 |
% |
|
|
40 |
% |
|
|
64 |
% |
|
|
54 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table shows our production volumes, product sale prices and operating revenues
for the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
Year Ended December 31, |
|
|
Increase |
|
|
Increase |
|
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
(in thousands, except per unit data) |
|
Production Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
1,027 |
|
|
|
1,051 |
|
|
|
(24 |
) |
|
|
(2 |
)% |
Natural gas (M cf) |
|
|
10,944 |
|
|
|
7,422 |
|
|
|
3,522 |
|
|
|
47 |
% |
BOE |
|
|
2,851 |
|
|
|
2,288 |
|
|
|
563 |
|
|
|
25 |
% |
BOE per day |
|
|
7.8 |
|
|
|
6.3 |
|
|
|
1.5 |
|
|
|
24 |
% |
Sale Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
95.25 |
|
|
$ |
65.97 |
|
|
$ |
29.28 |
|
|
|
44 |
% |
Natural gas (per M cf) |
|
$ |
7.74 |
|
|
$ |
6.29 |
|
|
$ |
1.45 |
|
|
|
23 |
% |
BOE price |
|
$ |
64.02 |
|
|
$ |
50.72 |
|
|
$ |
13.30 |
|
|
|
26 |
% |
Operating Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
97,799 |
|
|
$ |
69,315 |
|
|
$ |
28,484 |
|
|
|
41 |
% |
Natural gas |
|
|
84,716 |
|
|
|
46,716 |
|
|
|
38,000 |
|
|
|
81 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
182,515 |
|
|
$ |
116,031 |
|
|
$ |
66,484 |
|
|
|
57 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenues
Average wellhead realized crude oil prices increased $29.28 per Bbl, or 44% to $95.25 per Bbl
in 2008 as compared to 2007. This price increase caused an increase in revenue of approximately
$30.1 million. Oil production declined 24,000 Bbls due primarily to natural declines in the
Andrews, Fullerton and south Texas areas which was partially offset by drilling activity and the
additional interest acquired in June 2008 in the Diamond M area which resulted in a production
increase of approximately 63,700 Bbls. The decrease in production caused a decrease in revenue of
$(1.6) million when applying 2007 pricing.
Natural gas revenues
Average realized natural gas prices increased $1.45 per Mcf, or 23%, to $7.74 per Mcf in 2008
as compared to 2007. The price increase caused an increase in revenue of approximately $15.9
million.
Natural gas production increased by 3,522 MMcf which was due primarily from the drilling
activity in the two resource plays, the New Mexico Wolfcamp and Barnett Shale areas. Additional
interest was also
(52)
acquired in June 2008 in the Diamond M area. Increase in production was offset
with natural declines in the south Texas area. The increase in production caused an increase in
revenue of $22.1 million when applying 2007 pricing.
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
Year Ended December 31, |
|
|
Increase |
|
|
Increase |
|
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
|
|
|
|
($ in thousands) |
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
$ |
28,454 |
|
|
$ |
22,200 |
|
|
$ |
6,254 |
|
|
|
28 |
% |
Production taxes |
|
|
9,135 |
|
|
|
5,545 |
|
|
|
3,590 |
|
|
|
65 |
% |
Production tax refund |
|
|
(1,958 |
) |
|
|
(1,209 |
) |
|
|
(749 |
) |
|
|
62 |
% |
General and administrative |
|
|
11,907 |
|
|
|
10,415 |
|
|
|
1,492 |
|
|
|
14 |
% |
Depreciation, depletion and amortization |
|
|
44,691 |
|
|
|
30,115 |
|
|
|
14,576 |
|
|
|
48 |
% |
Impairment of oil and natural gas properties |
|
|
300,532 |
|
|
|
|
|
|
|
300,532 |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
392,761 |
|
|
$ |
67,066 |
|
|
$ |
325,695 |
|
|
|
486 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
Lease operating costs increased approximately $6.3 million, or 28%, to $28.5 million in 2008
as compared to 2007. Lifting cost (excluding production taxes) increased to $9.98 per BOE in 2008
compared to $9.70 per BOE in 2007. Overall costs are up for the Diamond M area as a result of the
acquisition of the additional interest in June 2008. In addition we spent approximately $808,000
on additional workovers in the Fullerton area. Costs for the Barnett Shale and New Mexico Wolfcamp
areas are up due to the new wells drilled. Ad valorem taxes increased in 2008 by approximately
$538,000 from 2007.
Production taxes
Production tax increased $3.6 million, in 2008 compared to 2007 primarily due to a $66.5
million increase in revenue. Production taxes were 5.0% of revenue for 2008 compared to 4.8% of
revenue for 2007. The rate increase is related to higher natural gas production and higher tax
rates in the New Mexico area. Production taxes in future periods will be a function of product
mix, production volumes, product prices and tax rates.
A production tax refund was received in June 2007 in the amount of $1.2 million for natural
gas production taxes on non-operated wells in the Wilcox area of south Texas for production during
the period from March 2005 through January 2007. During the fourth quarter 2008 production tax
refunds were received in the amount of approximately $1.5 million for oil and approximately
$482,000 for natural gas on non-operated wells in the Fullerton and Barnett Shale areas,
respectively for production during the period from March 2007 through August 2008. The refunds
were received by the operator of these wells after the operators application for tax abatement was
approved by state regulatory agencies. The reduction in our production tax expense was recognized
when approval of the application for tax abatement was granted by the various state agencies.
General and Administrative
Total general and administrative expenses increased 14%, or approximately $1.5 million, in
2008 compared to 2007. This increase was primarily due to increased stock based compensation
expense of approximately $1.1 million, and an increase in staffing and salary cost of approximately
$569,000 over 2007. General and administrative expenses capitalized to the full cost pool were $1.9
million in 2008 compared to $1.5 million in 2007. On a BOE basis, general and administrative costs
decreased to $4.18 per BOE in 2008 from $4.55 per BOE in 2007.
(53)
Depreciation, depletion and amortization
Depreciation, depletion and amortization expense increased 48%, or $14.6 million, in 2008
compared to 2007. Total depreciation, depletion and amortization expense per BOE was $15.68 for
2008 and $13.16 for 2007. This increase is primarily attributable to an overall increase in actual
and anticipated drilling costs and related oilfield service costs. Increased cost levels affected
the depletable amounts of capitalized costs in 2008. Our drilling over the past year have been
focused on our natural gas resource projects which have higher associated per BOE drilling and
development costs than our drilling projects in the Permian Basin of west Texas and onshore gulf
coast of south Texas due to the use of horizontal drilling and multi-stage stimulation techniques.
This factor, along with a reduction in reserve estimates due to commodity prices at year-end
December 31, 2008, have led to a significant increase in our depletion rate per BOE.
Impairment of oil and natural gas properties
Due
to lower commodity prices an impairment expense of $300.5 million was recognized in the
fourth quarter of 2008. No impairment was recognized in 2007.
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
Year Ended December 31, |
|
|
Increase |
|
|
Increase |
|
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
($ in thousands) |
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges |
|
$ |
32,018 |
|
|
$ |
(36,776 |
) |
|
$ |
68,794 |
|
|
|
187 |
% |
Interest and other income |
|
|
278 |
|
|
|
197 |
|
|
|
81 |
|
|
|
41 |
% |
Interest expense, net of capitalized interest |
|
|
(23,750 |
) |
|
|
(19,177 |
) |
|
|
(4,573 |
) |
|
|
24 |
% |
Cost of debt retirement |
|
|
(286 |
) |
|
|
(760 |
) |
|
|
474 |
|
|
|
(62 |
)% |
Other expense |
|
|
(12 |
) |
|
|
(118 |
) |
|
|
106 |
|
|
|
(90 |
)% |
Equity in income (loss) of pipelines
and gathering system ventures |
|
|
380 |
|
|
|
(311 |
) |
|
|
691 |
|
|
|
(222 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
8,628 |
|
|
$ |
(56,945 |
) |
|
$ |
65,573 |
|
|
|
(115 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges
We recorded a gain of $32.0 million in 2008 for derivatives not classified as hedges, as
compared to a loss of $(36.8) million in 2007. We settled $35.9 million in derivatives payments
during 2008 compared to $16.6 during 2007. During 2008, the gain was
due primarily to a decrease in oil and natural gas prices which
increased the value of our derivatives. During 2008, the gain was due
primarily to a decrease in oil and natural gas prices which increased
the value of our derivatives. During 2007, the loss was due primarily
to an increase in oil and natural gas prices which decreased the
value of our derivatives.
See Note 9- Derivative Instruments.
Interest expense
Interest expense increased 24%, or $4.6 million, in 2008 as compared to 2007. The higher
interest expense was primarily due to higher average outstanding debt balances during 2008. This
was partially offset with a lower average interest rate in 2008. Capitalized interest for 2008 was
approximately $81,000 and $423,000 during 2007. Our weighted average interest rate decreased to
7.92% for 2008, from 8.92% for 2007.
Cost of debt retirement
Until July 31, 2007, we had a $50.0 million term loan available to us under our Second Lien
Term Loan Agreement, or the Second Lien Agreement. Upon completion of our senior notes offering,
described below under Liquidity and Capital Resources Senior Notes, we paid off and terminated
this
(54)
facility with $50.2 million of the net proceeds from the offering. As a result, we charged to
earnings $760,000 of previously capitalized debt issuance cost. In 2008, we expensed the remaining
unamortized bank fees of $286,000 associated with the change in participating banks in our
revolving credit facility.
Equity in income (loss) of pipelines and gathering system ventures
For 2008, our equity investment recorded a net gain of $380,000 which was attributable to a
$381,000 gain associated with the Hagerman Gas Gathering System and a loss of $(1,000) associated
with the West Fork Pipeline II. This compared to a loss of $(601,000) for the Hagerman Gas
Gathering System for 2007. This increase in earnings is the result of increased volumes flowing
through the Hagerman Gas Gathering System during the first part of the 2008. In June 2008, we
acquired all of the assets of the Hagerman Gas Gathering System. Subsequent to this acquisition,
the results of operations of the Hagerman Gas Gathering System are included in our operating income
and not as an equity gain/loss item in our Consolidated Statement of Operations. See Note 10-
Investment in Gas Gathering Systems.
In 2007, we received final disbursements associated with the sale of the partnership assets in
West Fork Pipeline I and West Fork Pipeline V of $161,000 and $126,000 respectively. The sale of
these investments occurred in 2006.
Income taxes, deferred
Income
tax benefit was $69.7 million in 2008, compared to a benefit of $3.3 million in 2007.
Income tax expense for 2009 will be dependent on our earnings and is expected to be approximately
35% of income before income taxes. In 2008 and 2007 our effective
rate was approximately 35% and 42%,
respectively. The 2007 tax rate was higher due to the recognition of a State NOL which we did not
believe would be recognized until 2007 when Texas issued final rules related to its new Texas
Margin Tax legislation.
Basic and diluted net loss
We
had basic and diluted net loss per share of $(3.18) and $(0.12), for 2008 and 2007,
respectively. Basic and diluted weighted average common shares outstanding increased from
approximately 38.1 million shares in 2007 to approximately 41.5 million shares in 2008. The
increase in weighted average common shares was primarily due to our public offering of 3.0 million
shares of common stock in December 2007.
Years Ended December 31, 2007 and December 31, 2006
The following discussion compares our result for the year ended December 31, 2007 to the year
ended December 31, 2006. Unless otherwise indicated, references to 2007 and 2006 within this
section refer to the respective annual periods.
Percentages of our oil and natural gas revenues and production, by product mix, are shown in
the following table for 2007 and 2006.
Oil and Gas Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues(1) |
|
Production |
|
|
2007 |
|
2006 |
|
2007 |
|
2006 |
Oil (Bbls) |
|
|
60 |
% |
|
|
58 |
% |
|
|
46 |
% |
|
|
51 |
% |
Natural gas (M cf) |
|
|
40 |
% |
|
|
42 |
% |
|
|
54 |
% |
|
|
49 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes the effects of derivative transactions accounted for as hedges. |
(55)
The following table shows our production volumes, product sale prices and operating revenues
for the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
Year Ended December 31, |
|
|
Increase |
|
|
Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
(in thousands, except per unit data) |
|
|
|
|
|
Production Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
1,051 |
|
|
|
1,137 |
|
|
|
(86 |
) |
|
|
(8 |
)% |
Natural gas (M cf) |
|
|
7,422 |
|
|
|
6,539 |
|
|
|
883 |
|
|
|
14 |
% |
BOE |
|
|
2,288 |
|
|
|
2,227 |
|
|
|
61 |
|
|
|
3 |
% |
BOE per day |
|
|
6.3 |
|
|
|
6.1 |
|
|
|
0.2 |
|
|
|
3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sale Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)(1) |
|
$ |
65.97 |
|
|
$ |
59.86 |
|
|
$ |
6.11 |
|
|
|
10 |
% |
Natural gas (per M cf)(1) |
|
$ |
6.29 |
|
|
$ |
6.19 |
|
|
$ |
0.10 |
|
|
|
2 |
% |
BOE price(1) |
|
$ |
50.72 |
|
|
$ |
48.73 |
|
|
$ |
1.99 |
|
|
|
4 |
% |
BOE price(2) |
|
$ |
50.72 |
|
|
$ |
43.56 |
|
|
$ |
7.16 |
|
|
|
16 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
$ |
69,315 |
|
|
$ |
68,076 |
|
|
$ |
1,239 |
|
|
|
2 |
% |
Effect of oil hedges |
|
|
|
|
|
|
(11,512 |
) |
|
|
11,512 |
|
|
|
(100 |
)% |
Natural gas |
|
|
46,716 |
|
|
|
40,461 |
|
|
|
6,255 |
|
|
|
15 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
116,031 |
|
|
$ |
97,025 |
|
|
$ |
19,006 |
|
|
|
20 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes hedge transactions. |
|
(2) |
|
Includes hedge transactions. |
Oil revenues
Average wellhead realized crude oil prices increased $6.11 per Bbl, or 10%, to $65.97 per Bbl
for 2007, as compared to 2006. This price increase resulted in increased revenues by approximately
$6.4 million in 2007, as compared to 2006. Oil production decreased 8% attributable to a decline
of approximately 43,000 Bbls, 41,000 Bbls and 33,000 Bbls in the Diamond M Deep, Carm-Ann and south
Texas area, respectively comparing 2007 to 2006. These decreases were a result of natural declines
and limited developmental activity occurring within these areas. These decreases were partially
offset with increases in the Harris field where we benefited from our development programs in 2006
and late 2007. The decrease in oil production reduced revenue approximately $5.2 million for 2007.
Natural gas revenues
Average realized wellhead natural gas prices received were up slightly to $6.29 per Mcf for
2007 from $6.19 per Mcf received for 2006. This slight price increase accounted for an increase in
revenue of approximately $742,000. Natural gas production increased 14% primarily due to new wells
in the New Mexico Wolfcamp area where volumes were up 1.7 Bcf and the Barnett Shale area where
volumes were up approximately 628,000 Mcf. These increases were offset by a production decline of
approximately 1.2 Bcf in our south Texas wells comparing 2007 to 2006. The net increase in natural
gas volumes increased revenue approximately $5.5 million for 2007.
Oil hedges
We settled all remaining derivatives classified as cash flow hedges in December 2006.
Therefore, oil hedge losses were $0 in 2007 compared to a loss of approximately $11.5 million in
2006. We continue to employ derivative contracts in the form of oil and natural collars and swaps
which are intended to mitigate the effects of commodity price volatility. These derivative
contracts are not designated or
(56)
accounted for as cash flow hedges and, therefore, the changes in their fair values and any
settlement amounts are recorded to other income (expense) as described below.
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
Year Ended December 31, |
|
|
Increase |
|
|
Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
($ in thousands) |
|
|
|
|
|
Lease operating expense |
|
$ |
22,200 |
|
|
$ |
16,819 |
|
|
$ |
5,381 |
|
|
|
32 |
% |
Production taxes |
|
|
5,545 |
|
|
|
5,577 |
|
|
|
(32 |
) |
|
|
(1 |
)% |
Production tax refund |
|
|
(1,209 |
) |
|
|
|
|
|
|
(1,209 |
) |
|
|
N/A |
|
General and administrative |
|
|
10,415 |
|
|
|
9,523 |
|
|
|
892 |
|
|
|
9 |
% |
Depreciation, depletion and amortization |
|
|
30,115 |
|
|
|
24,687 |
|
|
|
5,428 |
|
|
|
22 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
67,066 |
|
|
$ |
56,606 |
|
|
$ |
10,460 |
|
|
|
18 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
Lease operating expenses were higher in 2007 when compared to 2006 partly due to new wells.
Of the $5.4 million increase, $2.3 million of these charges are on wells that were completed in
2007 or completed late in 2006. Therefore, the costs are higher for 2007 compared to 2006. Well
repair, workover expenses, salt water disposal and compressor expense increased approximately $4.0
million for 2007 compared to 2006. Overall higher costs for well repair and workover result from
our refocused efforts on lease maintenance and away from developmental activity during 2007 on our
oil properties. Salt water disposal and compression charges increased significantly during 2007
resulting from new well activity in the south New Mexico area and Barnett Shale area. These
amounts are included in the previously discussed $2.3 million increase for new wells. Lifting
costs (excluding production taxes) were $9.70 per BOE in 2007 compared to $7.55 per BOE in 2006.
Production taxes
Production taxes showed no significant change even though revenue increased $7.5 million from
2006 to 2007. The expected increase was offset by qualifying lower severance tax rates used during
2007. The lower severance tax rates were a result of certain properties qualifying for state tax
incentive programs. The lower tax rates will continue on a forward basis until the term of the tax
incentives are expired.
A production tax refund was received in June 2007 in the amount of $1.2 million for natural
gas production taxes on non-operated wells in the Wilcox area of south Texas for production during
the period from March 2005 through January 2007. This refund was received by the operator of these
wells only after the operators application for tax abatement was approved by state regulatory
agencies. The reduction in our production tax expense was recognized only when approval of the
application for tax abatement was granted by state regulatory authorities.
General and administrative
General and administrative expenses increased 9% or $892,000 in 2007 over 2006. During
2007, salaries increased by $488,000. This was due to a larger staff and increased salary rates
when compared to 2006. Also, we incurred increased legal fees in 2007 in the amount of $413,000.
This increase in legal fees was primarily related to general corporate matters. In addition, we
incurred increased costs of $334,000 associated with accounting and reporting requirements.
Offsetting the above general and administrative expense increases were the following two
items. First, during the second quarter of 2006, we determined that stock options to purchase
30,000 shares of
common stock that had been granted in 2003 to four of our employees under our 1998 Stock
Option Plan, were not available for issuance under the plan. In June 2006, the Board of Directors
authorized us to
(57)
enter into settlement and release agreements with the four employees. Under these
agreements, we made a one-time lump sum cash payment to each employee in an amount equal to the
spread between the exercise price of the options and the closing price of our stock on June 21,
2006. The total cash payments were approximately $511,000. This amount was charged to general and
administrative expense during the second quarter of 2006. Secondly, during the second quarter of
2007, we revised our estimates of expected forfeitures of stock options granted to directors due to
the resignation of a director and the subsequent forfeiture of 40,000 stock options held by him.
As a result we reduced our estimate of the grant date fair value of shares expected to ultimately
vest under our stock option plan by approximately $283,000.
Depreciation, depletion and amortization
Depreciation, depletion and amortization expense increased 22%, or $5.4 million, for 2007 as
compared to 2006. Depletion per BOE was $13.02 for 2007 and $10.88 for 2006. This increase was
attributable to an overall increase in actual and anticipated drilling costs and related oilfield
service costs. Increased cost levels affect both the depletable amounts of capitalized costs in
2007 and the depletion attributable to amounts of estimated future development costs on proved
undeveloped properties. Throughout 2006 and 2007, the majority of our drilling activity was in our
natural gas resource projects in the Permian Basin of west Texas and the Barnett Shale areas.
These areas have higher associated per BOE drilling and development costs due to the use of
horizontal drilling and multi-stage stimulation techniques. These factors, when combined with the
increase in the absolute level of our capital expenditures during this time period led to a
significant increase in our depletion rate per BOE from 2006 to 2007.
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
Year Ended December 31, |
|
|
Increase |
|
|
Increase |
|
|
|
2007 |
|
|
2006 |
|
|
(Decrease) |
|
|
(Decrease) |
|
|
|
($ in thousands) |
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges |
|
$ |
(36,776 |
) |
|
$ |
2,802 |
|
|
$ |
(39,578 |
) |
|
|
(1,412 |
)% |
Gain (loss) on ineffective portion of hedges |
|
|
|
|
|
|
626 |
|
|
|
(626 |
) |
|
|
(100 |
)% |
Interest and other income |
|
|
197 |
|
|
|
158 |
|
|
|
39 |
|
|
|
25 |
% |
Interest expense, net of capitalized interest |
|
|
(19,177 |
) |
|
|
(12,360 |
) |
|
|
(6,817 |
) |
|
|
55 |
% |
Cost of debt retirement |
|
|
(760 |
) |
|
|
|
|
|
|
(760 |
) |
|
|
N/A |
|
Other expense |
|
|
(118 |
) |
|
|
(189 |
) |
|
|
71 |
|
|
|
(38 |
)% |
Equity in income (loss) of pipelines
and gathering system ventures |
|
|
(311 |
) |
|
|
8,593 |
|
|
|
(8,904 |
) |
|
|
(104 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(56,945 |
) |
|
$ |
(370 |
) |
|
$ |
(56,575 |
) |
|
|
15,291 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges
We recorded a loss of $36.8 million in 2007 for derivatives not classified as hedges as
compared to a gain of $2.8 million for 2006. The greatest impact of the change in fair market
valuation was within our crude oil contracts due to the significant increase in oil prices during
2007. We settled in cash a net of $16.6 million in derivative contracts during the year ended
December 31, 2007.
The ineffective portion of our hedges was a gain of approximately $626,000 in 2006. As of
December 31, 2006, all cash flow hedge contracts were settled.
Interest expense
Interest expense increased in 2007 as the result of increased borrowings and an increase in
our weighted average interest rate. Our bank debt decreased from $165.0 million to $60.0 million
during 2007. However, interest expense increased $6.6 million as a result of our $150.0 million
senior notes offering in July 2007 and an increase in the average interest rate on our revolving
credit facility in 2007. Our weighted average interest rate increased to 8.92% from 8.33% for 2007
and 2006, respectively.
(58)
Capitalized interest on work in progress decreased interest expense by $423,000 in 2007, a
decrease of $214,000 compared to 2006.
Cost of debt retirement
Cost of debt retirement represent the write off of previously capitalized debt issuance costs
associated with our Second Lien Agreement that was retired with the proceeds of our senior notes
offering.
Equity in income (loss) of pipelines and gathering system ventures
Since 2004, we had invested in four pipelines and gathering system joint ventures. During
2006, the assets of two of these ventures were sold. As a result, we recognized our share of net
gains on sale of $9.0 million in 2006.
During 2006, we and two other unaffiliated parties formed a joint venture known as the
Hagerman Gas Gathering System, which was formed for the purpose of constructing, owning and
operating a gas gathering system in New Mexico.
The loss associated with our equity investments totaled $311,000 in 2007 versus a gain of $8.6
million in 2006. The gains realized in 2006 were the result of the sale of our interests in two
pipeline joint ventures. We did not sell any interests in pipeline joint ventures during 2007. In
addition, the Hagerman Gas Gathering System in New Mexico was operational for the entire twelve
months of 2007 versus a few months in 2006. During 2006 and the first nine months 2007, production
levels and related transportation volumes were not sufficient for profitable operation of this
system. This resulted in an increase in our equity loss for this investment of $601,000. We also
received final payout settlements for the divestiture of our investments in West Fork Pipeline
Company I and West Fork Pipeline Company V of $161,000 and $126,000 respectively in the fourth
quarter of 2007.
Income tax
Income tax was a benefit of $3.3 million in 2007 compared to an expense of $13.9 million in
2006. Income tax expense for 2008 will be dependent on our earnings and is expected to be
approximately 35% of income before income taxes.
Included in the $3.3 million income tax benefit amount was a net state tax benefit of the
$592,000. Prior to 2007, we had not recognized a tax credit for state net operating loss
carryovers due to the uncertainty about their ultimate realization. However, with the State of
Texas revising its state tax laws in 2007 and our election to utilize the credit, we recognized
this credit as we now expect to realize this benefit over future periods. See Note 12- Income
Taxes.
Basic and diluted net income
We had basic net income (loss) per share of $(0.12) and $0.73 and diluted net income (loss)
per share of $(0.12) and $0.71 for 2007 and 2006, respectively. Basic weighted average common
shares outstanding increased from approximately 35.9 million shares in 2006 to approximately 38.1
million shares in 2007. The increase was primarily due to our public offering of 3.0 million
shares of common stock in December 2007 and the exercise of employee and nonemployee stock options
during 2007.
Liquidity and Capital Resources
Primary cash requirements we have are for exploration, development and acquisition of oil and
natural gas properties, payment of derivative loss settlements and repayment of principal and
interest on our debt. Our capital resources consist primarily of cash flows from our oil and
natural gas properties, bank borrowings supported by our oil and natural gas reserves, proceeds
from derivative gain settlements, proceeds from sales of debt and equity securities and, to a
lesser extent, proceeds from sales of non-core
(59)
assets. Our level of earnings and cash flows depend
on many factors, including the prices we receive for oil and natural gas we produce. Although we
expect these same capital resources to support our future activities, we continually review and
consider alternative methods of financing.
Working capital increased approximately $61.8 million as of December 31, 2008 compared with
December 31, 2007. Current assets exceeded current liabilities by $28.5 million at December 31,
2008. The working capital increase was due primarily to the increase in cash of $28.5 million. As
of December 31, 2008, and December 31, 2007, we had approximately $36.3 million and $7.8 million,
respectively, in cash and cash equivalents. We also experienced an increase in short term
derivative value of $32.4 million, when the deferred tax asset and liability are taken into
account. This change in value was largely due to the decreases in pricing of crude oil and natural
gas. Finally, reductions in accrued liabilities of $7.4 million due to a reduction in drilling and
completion activities, commodity pricing and timing of payments also contributed to the increase in
working capital. These increases were partially offset with a decrease in oil and natural gas
sales receivables of $7.1 million which was adversely affected by the lower oil and natural gas
prices. Also, a decrease in accounts receivable primarily associated with a joint venturer paying
down its outstanding amounts offset the increase in working capital
by $3.6 million. We actively manage our cash flow by monitoring
joint owner and purchaser receivables, major purchaser credit ratings
and financial information along with actively managing spending
levels as needed in the existing economic climate.
We maintain our cash in bank deposit and brokerage accounts which, at times, may exceed
federally insured limits. As of December 31, 2008 accounts were guaranteed by the Federal Deposit
Insurance Corporation (FDIC) up to $250,000. As of December 31, 2008, we had deposits in excess of
the FDIC and SIPC limits in the amount of $26.7 million. In addition we had short-term investments
in United States Treasury bills of $5.0 million at December 31, 2008 versus no similar investments
at December 31, 2007.
The following table summarizes our cash flows from operating, investing and financing
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
($ in thousands) |
Operating activities |
|
$ |
121,041 |
|
|
$ |
74,119 |
|
|
$ |
68,186 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing activities |
|
$ |
(258,297 |
) |
|
$ |
(164,897 |
) |
|
$ |
(194,548 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing activities |
|
$ |
165,743 |
|
|
$ |
92,684 |
|
|
$ |
125,854 |
|
Cash flow from operating activities increased primarily due to the increased average price the
Company received for its oil and natural gas sales throughout 2008 as well as the increase in
production compared to 2007. The increase of cash flow from operating
activities over net income is primarily due to the impairment of oil
and natural gas properties, partially offset by the gain on
derivatives caused by lower oil prices and the recognized income tax
benefit for the year ended December 31, 2008. See Results of Operations beginning on
page 47 for a more complete
discussion of these changes.
Cash used in investing activities increased by approximately $93.4 million in 2008 compared to
2007 primarily as a result of the $35.5 million acquisition of the additional interest in the
Diamond M field in Snyder, Texas, an increase in settlements of our derivative contracts in the
amount of $19.3
million, an increase of short term investments in U.S Treasuries of $5.0 million and increased
investments in our resource gas plays by approximately $15.7 million in 2008.
(60)
Cash provided by financing activities increased in 2008 compared to 2007 primarily as a result
of an increase in borrowings against our revolving credit facility of approximately $73.0 million,
including the $62.5 million draw down to enhance our liquidity as described below.
Our 2009 capital investment budget will be funded from our operating cash flows. If our cash
flows are not sufficient to fund all of our estimated capital expenditures, we may fund any
shortfall with
available cash, short-term investments, bank borrowings, proceeds from the sale of
our debt or equity securities or sale of our oil and natural gas properties, reduce our capital
budget or effect a combination of these alternatives. The amount and timing of our expenditures are
subject to change based upon market conditions, results of expenditures, new opportunities and
other factors. In response to recent market conditions, our 2009 capital expenditure budget will be
$29.1 million compared to the $230.6 million we spent on oil and natural gas related capital
expenditures. Although we cannot predict the outcome of our planned 2009 capital spending, we do
not anticipate significant change in our 2009 production levels compared to our 2008 production
levels. Cash flow from operating activities will be highly dependent on the success of this
spending as well as on commodity pricing.
If our revenues or the borrowing base under our revolving credit facility decrease as a result
of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other
reason, we may have limited ability to obtain the capital necessary to undertake or complete future
drilling projects. Our borrowing base is scheduled to be re-determined on April 1, 2009
and given the current conditions in the credit markets and lower commodity prices our
borrowing base may be reduced to an amount less than our outstanding borrowings at which time
we would have to immediately repay any excess of our outstanding borrowings over our borrowing base. We may,
from time to time, seek additional financing, either in the form of
increased bank borrowings, sale of debt or equity securities or other forms of financing and there
can be no assurance as to the availability of any additional financing upon terms acceptable to us.
To strengthen our liquidity in the current market environment we drew an additional $62.5 million
against the revolving credit facility during the month of October 2008. See Note 11- Credit
Arrangements.
Shelf Registration Statement
On November 6, 2007, the United States Securities and Exchange Commission declared effective a
shelf registration statement on Form S-3 filed by us to register $250.0 million of securities for
potential future issuance. The available balance of our $250.0 million universal shelf registration
statement was $194.5 million as of December 31, 2008. In the future, we may, in one or more
offerings, offer and attempt to sell debt securities and additional equity securities under our
shelf registration statement. Net proceeds, terms and pricing of the offering of securities issued
under the shelf registration statement will be determined at the time of the offerings, if any.
However, our shelf registration statement does not provide assurance that we will or could sell any
such securities. Our ability to utilize our shelf registration statement for the purpose of
issuing, from time to time, any debt securities, preferred stock, common stock or warrants depends
upon, among other things, market conditions and the existence of investors who wish to purchase our
securities at prices acceptable to us. However, because of current economic conditions, as well as
the recent prices of our outstanding common stock, the type and amount of any securities offering
under the registration statement may be limited.
Revolving Credit Facility
Our Fourth Amended and Restated Credit Agreement, dated May 16, 2008, as amended by the First
Amendment to Fourth Amended and Restated Credit Agreement, dated October 31, 2008, and as further
amended by Second Amendment to Fourth Amended and Restated Credit Agreement, or the Revolving
Credit Agreement, with a group of bank lenders provides us with a revolving line of credit having
a borrowing base limitation of $230.0 million at December 31, 2008. The total amount that we can
borrow and have outstanding at any one time is limited to the lesser of $600.0 million or the
borrowing base established by the lenders. At December 31, 2008, the principal amount outstanding
(61)
under our revolving credit facility was $225.0 million, excluding $445,000 reserved for our letters
of
credit. We have pledged substantially all of our producing oil and natural gas properties to
secure the repayment of our indebtedness under the Revolving Credit Agreement.
The Revolving Credit Agreement allows us to borrow, repay and reborrow amounts available under
the revolving credit facility. The amount of the borrowing base is based primarily upon the
estimated value of our oil and natural gas reserves. The borrowing base amount is redetermined by
the lenders semi-annually on or about April 1 and October 1 of each year or at other times required
by the lenders or at our request. If, as a result of the lenders redetermination of the borrowing
base, the outstanding principal amount of our loans exceeds the borrowing base, we must either
provide additional
collateral to the lenders or repay the outstanding principal of our loans in an
amount equal to the excess. Except for the principal payments that may be required because of our
outstanding loans being in excess of the borrowing base, interest only is payable monthly.
As of December 31, 2008, our group of bank lenders included Citibank, N.A., BNP Paribas,
Compass Bank, Bank of Scotland plc, Bank of America, N.A., Texas Capital Bank, N.A., Western
National Bank and West Texas National Bank. None of the bank lenders held more than 21% of our
outstanding loans at December 31, 2008.
Loans made to us under this revolving credit facility bear interest based on the base rate of
Citibank, N.A. or the LIBOR rate, at our election.
The base rate is generally equal to the sum of (a) Citibanks prime rate as announced by it
from time to time and (b) a specified margin, the amount of which depends upon the outstanding
principal amount of our loans. If the principal amount outstanding is equal to or greater than 75%
of the borrowing base, the margin is 0.25%. If the borrowing base usage is less than 75%, the
margin is zero percent.
The LIBOR rate is generally equal to the sum of (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered in one, two, three, six or twelve month interest
periods for deposits of $1.0 million, and (b) a margin ranging from 2.50% to 3.00%, depending upon
the outstanding principal amount of our loans. If the principal amount outstanding is equal to or
greater than 75% of the borrowing base, the margin is 3.00%. If the principal amount outstanding is
equal to or greater than 50%, but less than 75% of the borrowing base, the margin is 2.75%. If the
principal amount outstanding is less than 50% of the borrowing base, the margin is 2.50%.
The interest rate we are required to pay on our borrowings, including the applicable margin,
may never be less than 4.75%. At December 31, 2008, our base rate, plus the applicable margin, was
4.75% on $225.0 million, the outstanding principal amount of our revolving loan on that date.
In the case of base rate loans, interest is payable on the last day of each month. In the case
of LIBOR loans, interest is payable on the last day of each applicable interest period.
If the total outstanding borrowings under the revolving credit facility are less than the
borrowing base, we are required to pay an unused commitment fee to the lenders in an amount equal
to 0.25% of the daily average of the unadvanced portion of the borrowing base. The fee is payable
quarterly.
If the borrowing base is increased, we are also required to pay a fee of 0.375% on the amount
of any such increase.
All outstanding principal and accrued and unpaid interest under the revolving credit facility
is due and payable on December 31, 2013. The maturity date of our outstanding loans may be
accelerated by the lenders upon the occurrence of an event of default under the Revolving Credit
Agreement.
(62)
The Revolving Credit Agreement presently contains financial covenants and other restrictions,
some of which prohibit us from:
|
|
|
creating, incurring, assuming or permitting to exist any lien, security
interest or other encumbrance on any of our assets or properties, except
specified permitted liens; |
|
|
|
|
selling, leasing, transferring or otherwise disposing of any of our assets,
except (a) our oil and natural gas properties between scheduled determinations
of the borrowing base having an aggregate value not exceeding the lesser of
(i) 5% of the value of all of our proved producing oil and natural gas
reserves, or (ii) $20.0 million; (b) extracted petroleum hydrocarbons sold in
the ordinary course of our business; (c) worthless or obsolete equipment; (d)
transfers to us or any subsidiary; and (e) our assets and the assets of any
subsidiary having an aggregate fair market value not exceeding
$10.0 million; |
|
|
|
allowing our current ratio (as adjusted for available borrowing and
unrealized derivative losses) to be less than 1.0 to 1.0 as of the end of any
fiscal quarter; |
|
|
|
|
allowing our ratio of consolidated funded debt to consolidated EBITDA for any fiscal
quarter (calculated at the end of each fiscal quarter using the results of the
immediately preceding twelve-month period) to exceed 4.25 to 1.00 as of December 31,
2008 and for any test period during 2009 and 2010, or 4.00 to 1.00 during the year 2011
and thereafter. See Note 19- Subsequent Events; |
|
|
|
|
allowing our adjusted consolidated net worth to be less than the sum of (a)
$175.0 million, plus (b) 75% of the net proceeds from the sale of any equity
securities, plus (c) 50% of our consolidated net income for each fiscal quarter
determined on a cumulative basis from January 1, 2008; |
|
|
|
|
forming or acquiring any new subsidiary or consolidating or merging with or
into any other entity, except for certain intra-company consolidations or
mergers where we are the surviving entity; |
|
|
|
|
becoming liable in respect of any indebtedness, or guaranteeing or otherwise
in any manner becoming liable for indebtedness, liabilities or other
obligations of any other person, except for (a) indebtedness incurred in
connection with our revolving credit facility; (b) taxes, assessments and
government charges; (c) obligations arising out of interest rate management
transactions permitted under our revolving credit facility; (d) indebtedness
evidenced by our 101/4% senior notes due 2014 not to exceed the aggregate
principal amount of $150.0 million; (e) indebtedness incurred in the ordinary
course of business that is not more than 60 days past due; or (f) other
indebtedness not exceeding $1.0 million in the aggregate; |
|
|
|
|
declaring, paying or making any loans, advances, distributions or dividends
to our equity owners, or purchasing, acquiring, redeeming or retiring any stock
or other security issued by us, except for certain purchases of the notes and
certain intra-company dividends or distributions from our subsidiaries to us; |
|
|
|
|
making or permitting to remain outstanding any loans or advances to any
person or entity, except (a) advances made in the ordinary course of our
business; (b) other loans or advances to a third party not to exceed $1.0
million in the aggregate; or (c) intra-company loans; |
|
|
|
|
discounting, or selling with recourse, or selling for less than market
value, any of our notes receivable or accounts receivable; |
(63)
|
|
|
|
permitting any material change in the character of our business; |
|
|
|
|
entering into transactions with our affiliates, except transactions upon
terms that are no less favorable than could be obtained in a transaction
negotiated at arms length with an unrelated third party; |
|
|
|
|
entering into commodity hedging or interest rate management transactions,
except transactions required by our revolving credit facility, consented to by
our lenders, or transactions designed to hedge, provide a floor price for, or
swap crude oil or natural gas, provided certain conditions are satisfied; |
|
|
|
|
making any investments in any person or entity, except (a) investments with
maturities of not more than 180 days in direct obligations of the United States
of America or any agency thereof; (b) investments in certain certificates of
deposit; (c) our existing investments at May 16, 2008; (d) investments after
May 16, 2008 in Hagerman Gas Gathering System, not to exceed $5.0 million in
the aggregate; (e) investments in any subsidiary; (f) other investments not to
exceed $5.0 million in the aggregate during any calendar year when aggregated
with loans and advances permitted to be made or remain outstanding under our
revolving credit facility; |
|
|
|
|
permitting any material amendment or alteration to our organizational or
governing documents; |
|
|
|
|
permitting any plan subject to ERISA to (a) engage in any prohibited
transaction as such term is defined in Section 4975 of the Internal Revenue
Code of 1986, as amended; (b) incur any accumulated funding deficiency as
such term is defined in Section 302 of ERISA; or (c) terminate in a manner
which could result in the imposition of a lien on its property pursuant to
Section 4068 of ERISA; |
|
|
|
|
permitting any change in accounting method or fiscal year; |
|
|
|
|
allowing our subsidiaries to issue or sell to any third party any equity
interest in them, or any option, warrant or other right to acquire any such
equity interest; |
|
|
|
|
making any amendment or entering into any agreement to amend or otherwise
change the Indenture governing our 101/4% senior notes due 2014, failing to
comply with the terms of the Indenture, or, except as specifically required by
the Indenture, making any prepayment of amounts owing under such notes; or |
|
|
|
|
permitting or incurring any lease obligations which would cause the
aggregate amount of all payments pursuant to all such leases to exceed $1.0
million in any twelve month period during the life of such leases, except for
oil and gas related leases. |
As of December 31, 2008 we were in compliance with our Revolving Credit Agreement.
Senior Notes
Purchase Agreement. On July 26, 2007, we entered into a Purchase Agreement among us
and Jefferies & Company, Inc., Merrill, Lynch Pierce Fenner and Smith Incorporated and BNP Paribas
Securities Corp., or the Initial Purchasers, relating to the sale and issuance of $150.0 million
principal amount of 101/4% Senior Notes due 2014, or the senior notes. The Purchase Agreement
contains customary representations and warranties of the parties and indemnification and
contribution provisions. The Initial Purchasers or their respective affiliates have provided, and
may in the future from time to time provide, financial advisory, investment banking or commercial
banking services to us or our affiliates, for which they have received, and we expect will receive,
customary fees. In particular, an affiliate of BNP Paribas
(64)
Securities Corp. acts as agent and
lender under our revolving credit facility and, prior to its termination, our Second Lien
Agreement, and has received and will continue to receive fees for their services.
On July 31, 2007, we completed the private offering of the senior notes in the principal
amount of $150.0 million. The net proceeds, after payment of typical transaction expenses, of the
senior notes of approximately $143.5 million were used first to retire all of our indebtedness
under our Second Lien Agreement, with the remainder being applied to the repayment of indebtedness
under our revolving credit facility. The senior notes were recorded at the principal amount net of
underwriters discount and related expenses of $4.8 million.
Indenture. On July 31, 2007, we issued the senior notes pursuant to an Indenture
dated July 31, 2007 between us and Wells Fargo Bank, National Association, as Trustee in a
transaction exempt from the registration requirements under the Securities Act of 1933, or the
Securities Act. The senior notes were sold within the United States only to qualified
institutional buyers in reliance on Rule 144A under the Securities Act and to Institutional
Accredited Investors pursuant to Rule 501(a)(1), (2), (3) or (7) under the Securities Act.
We used the net proceeds from the issuance to repay outstanding indebtedness under our
existing Revolving Credit Agreement and Second Lien Agreement.
Interest on the senior notes of 101/4% per annum on the principal amount of the senior notes is
payable semi-annually on February 1 and August 1 of each year to holders of record at the close of
business on the preceding January 15 and July 15, respectively, commencing on February 1, 2008.
Considering the discount on the senior notes, the effective interest rate is 10.92%. The senior
notes will mature on August 1, 2014. The senior notes are our unsecured senior obligations and
rank equally in right of
payment with all of our existing and future senior indebtedness and are effectively
subordinated in right of payment to all of our existing and future secured indebtedness, including
debt of our senior credit agreement.
On or after August 1, 2011, we may redeem all or a part of the senior notes at any time or
from time to time at the following redemption prices (expressed as percentages of the principal
amount) plus accrued and unpaid interest on the senior notes, if any, to the applicable redemption
date, if redeemed during the twelve-month period beginning August 1 of the years indicated:
|
|
|
|
|
Year |
|
Redemption Price |
2011 |
|
|
105.125 |
% |
2012 |
|
|
102.563 |
% |
2013 |
|
|
100.000 |
% |
Prior to August 1, 2010, we may on one or more occasions redeem up to an aggregate amount
equal to 35% of the aggregate principal amount of the senior notes, at a redemption price of
110.25% of the principal amount of the senior notes, plus accrued and unpaid interest, if any, to
the redemption date, with the net cash proceeds of one or more equity offerings; provided, that
(i) at least 65% in aggregate principal amount of the senior notes originally issued remains
outstanding immediately after the occurrence of such redemption (excluding senior notes held by us
or any of our subsidiaries) and (ii) each such redemption occurs within 90 days of the date of the
closing of the related equity offering.
In addition, at any time prior to August 1, 2011, we may redeem all or part of the senior
notes at a redemption price equal to:
(i) 100% of the principal amount thereof, plus
(ii) a make-whole premium, and accrued and unpaid interest, if any, to, the
redemption date. Generally, the make-whole premium is an amount equal to the greater of
(a) 1% of the principal amount of the senior notes being redeemed or (b) the excess of the
present
(65)
value of the redemption price of such notes as of August 1, 2011 plus all required
interest payments due through August 1, 2011 (computed at a discount rate equal to a
specified U.S. Treasury Rate plus 50 basis points), over the principal amount of the
senior notes being redeemed.
If we experience a change of control, we will be required to make an offer to repurchase the
senior notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid
interest to the date of repurchase. Generally, a change of control means:
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the sale or other disposition of all or substantially all of our assets; |
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the adoption by the Board of Directors of a plan of liquidation or
dissolution; |
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any person becomes the owner of more than 50% of our voting stock; |
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the first day on which a majority of the members of the Board of Directors
of Parallel are not continuing directors; or |
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certain mergers and consolidations with or into any other person. |
Upon an event of default, the Trustee or the holders of at least 25% in principal amount of
the outstanding senior notes may declare the entire principal of, premium, if any, accrued and
unpaid interest, if any, and liquidated damages, if any, on all the senior notes to be due and
payable immediately. Subject to certain qualifications, an event of default includes, generally:
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default for 30 days in the payment when due of interest on the senior notes; |
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default in the payment when due of the principal of the senior notes; |
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our failure to comply with the covenants or agreements in the Indenture; |
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defaults on indebtedness under other mortgages, indentures or instruments
which results from our failure to pay the principal or interest on such
indebtedness or which results in the acceleration of such indebtedness prior to
its maturity and the principal amount of any such indebtedness aggregates $10.0
million or more; |
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our failure to pay final judgments in excess of $10.0 million; |
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any subsidiary guarantee is held in any judicial proceeding to be
unenforceable or invalid; and |
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certain events of bankruptcy or insolvency with respect to us or certain of
our subsidiaries. |
Subject to certain exceptions and qualifications, the Indenture restricts our ability and any
future subsidiaries to:
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transfer or sell assets; |
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make investments; |
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pay dividends, redeem subordinated indebtedness or make other restricted
payments; |
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incur or guarantee additional indebtedness or issue disqualified capital
stock; |
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create or incur liens; |
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incur dividend or other payment restrictions affecting certain subsidiaries; |
(66)
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consummate a merger, consolidation or sale of all or substantially all of
our assets; |
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enter into transactions with affiliates; and |
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engage in businesses other than the oil and gas business. |
As of December 31, 2008 we were in compliance with the covenants in the Indenture.
Registration Rights Agreement. On July 31, 2007, we also entered into a Registration
Rights Agreement with the Initial Purchasers relating to the senior notes. We agreed to use our
commercially
reasonable efforts to prepare and, not later than 180 days after the date of original
issue of the senior notes, file an exchange offer registration statement with the Securities and
Exchange Commission with respect to an offer to exchange the senior notes for substantially identical notes that are registered under
the Securities Act. We filed an exchange offer registration statement with the SEC on January 4,
2008. We also agreed to use our reasonable best efforts to have such registration statement
declared effective by the SEC within 210 days after July 31, 2007. The registration statement
became effective on January 29, 2008. Additionally, we further agreed to promptly commence the
exchange offer after such registration statement is declared effective by the SEC and to keep such
exchange offer open for at least 20 business days after notice is mailed to the holders of the
senior notes. We also agreed to use our reasonable best efforts to keep the exchange offer
registration statement effective and to amend and supplement the prospectus contained therein.
All of our obligations under the Registration Rights Agreement were satisfied on March 4, 2008
when we completed the exchange of freely tradable senior notes for the restricted senior notes
initially issued under the Indenture.
Debt Ratings. We receive debt credit ratings from Standard & Poors Ratings Group,
Inc. (S&P) and Moodys Investors Service, Inc. (Moodys), which are subject to regular reviews.
S&Ps rating for Parallel is B with a negative outlook. Moodys Long-Term Corporate rating is B3
with a negative outlook. S&P and Moodys consider many factors in determining our ratings,
including production growth opportunities, liquidity, debt levels and asset and reserve mix. A
reduction in our debt ratings could negatively impact our ability to obtain additional financing or
the interest rate, fees and other terms associated with such additional financing. As of December
31, 2008, we were in compliance with all of the debt covenants covering our senior notes.
Commodity Price and Interest Rate Risk Management Transactions and Effects of Derivative
Instruments
The purpose of our derivative transactions is to provide a measure of stability in our cash
flows. The derivative trade arrangements we have employed include collars, costless collars, floors
or purchased puts, oil and interest rate swaps. In 2003, we designated our derivative trades as
cash flow hedges under the provisions of SFAS 133, as amended. Although our purpose for entering
into derivative trades has remained the same, contracts entered into after June 30, 2004 have not
been designated as cash flow hedges.
Since January 1, 2007, we had no derivatives in place that were designated as cash flow
hedges. All commodity derivative contracts at December 31, 2008 were accounted for by
mark-to-market accounting whereby changes in fair value are charged to earnings. Changes in the
fair values of derivatives are recorded in our Consolidated Statements of Operations as these
changes occur in Other income (expense), net. To the extent commodity prices in 2009 and beyond
increase, we will report a loss on these derivatives but if there are no further changes in prices,
our revenue will be correspondingly higher (than if there had been no price increase) when the
production is sold.
All interest rate swaps that we have entered into for 2008 and future years are accounted for
by mark-to-market accounting as prescribed in SFAS 133.
(67)
We are exposed to credit risk in the event of nonperformance by the counterparties to our
derivative trade instruments. We actively monitor our credit risks related to financial
institutions and counterparties including monitoring credit agency ratings, financial position and
current news to mitigate this credit risk. We minimize credit risk in derivative instruments by
entering into transactions with counterparties that are parties to our credit facility.
We adopted SFAS No. 157, Fair Value Measurements (SFAS 157), effective January 1, 2008 to
measure the fair value of our derivatives, which had no significant effect on our financial
position or operating results. As defined in SFAS 157, fair value is the price that would be
received to sell an asset
or paid to transfer a liability in an orderly transaction between market
participants at the measurement date (exit price).
This statement requires fair value measurements to be classified and disclosed in categories
of Level 1, Level 2 or Level 3, with Level 1 reflecting fair value measurements based on the most
observable and active markets. During periods of market disruption, including periods of volatile
oil and natural gas prices, rapid credit contraction or illiquidity, it may be difficult to value
certain of our derivative instruments if trading becomes less frequent and/or market data becomes
less observable. There may be certain asset classes that were in active markets with observable
data that become illiquid due to the current financial environment. In such cases, more derivative
instruments may fall to Level 3 and thus require more subjectivity and management judgment. As
such, valuations may include inputs and assumptions that are less observable or require greater
estimation as well as valuation methods which are more sophisticated or require greater estimation
thereby resulting in valuations with less certainty. Further, rapidly changing commodity and
unprecedented credit and equity market conditions could materially impact the valuation of
derivative instruments as reported within our consolidated financial statements and the
period-to-period changes in value could vary significantly. Decreases in value may have a material
adverse effect on our results of operations or financial condition. You should read Note 9-
Derivative Instruments for additional information about the different categories of our fair
value measurements under SFAS 157.
Management of risk requires, among other things, policies and procedures to properly record
and verify a number of transactions and events. We have devoted resources to develop our risk
management policies and procedures and expect to continue to do so in the future. Nonetheless, our
policies and procedures may not be comprehensive. Many of our methods for managing risk and
exposures are based upon the use of observed historical market behavior or statistics based on
historical models. As a result, these methods may not fully predict future exposures, which can be
significantly greater than our historical measures indicate. Other risk management methods depend
upon the evaluation of information regarding markets, or other matters that are publicly available
or otherwise accessible to us. This information may not always be accurate, complete, up-to-date or
properly evaluated and our risk management policies and procedures may leave us exposed to
unidentified or unanticipated risk, which could negatively affect our business. For more
information about our derivative instruments and price risk management transactions, please read
Quantitative and Qualitative Disclosures About Market Risk under Item 7A in this Annual Report on Form 10-K, beginning on page 74.
Future Capital Requirements
Our capital expenditure budget for 2009 is approximately $29.1 million and is highly dependent
on future oil and natural gas prices. The timing of most of our capital expenditures is
discretionary because we have not made any significant long-term capital expenditure commitments.
Consequently, we have a significant degree of flexibility to adjust the level of such expenditures
according to market conditions. In addition to the impact that oil and natural gas prices will have
on our budget, these expenditures will also be subject to:
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our internally generated cash flows; |
(68)
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the availability of additional borrowings under our revolving credit
facility or from other sources; |
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the availability of supplies and services; |
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additional sources of funding; and |
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our future drilling successes. |
Contractual Obligations, Commitments and Off-Balance Sheet Arrangements
We have contractual obligations and commitments that affect our financial condition. However,
based on our assessment of the provisions and circumstances of our contractual obligations and
commitments in existence at December 31, 2008, we do not believe there will be an adverse effect on
our consolidated results of operations, financial condition or liquidity. The following table is a
summary of our significant contractual obligations as of December 31, 2008.
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Obligation Due in Period |
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Contractual Cash Obligations |
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2009 |
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2010 |
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2011 |
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2012 |
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2013 |
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After 5 years |
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Total |
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($ in thousands) |
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Revolving Credit Facility (secured)(1) |
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$ |
10,688 |
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$ |
10,688 |
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$ |
10,688 |
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$ |
10,688 |
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$ |
235,688 |
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$ |
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$ |
278,440 |
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Senior Notes (unsecured)(2) |
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15,375 |
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15,375 |
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15,375 |
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15,375 |
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15,375 |
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165,375 |
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242,250 |
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Office Lease (Dinero Plaza) |
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271 |
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107 |
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31 |
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409 |
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Asset Retirement Obligations(3) |
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158 |
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1,966 |
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129 |
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296 |
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40 |
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8,790 |
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11,379 |
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Derivative Obligations |
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3,004 |
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2,821 |
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2,315 |
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8,140 |
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Put Premium Obligations(4) |
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646 |
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2,341 |
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1,689 |
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4,676 |
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Hagerman Gas Gathering System earn out(5) |
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532 |
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532 |
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Total |
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$ |
30,142 |
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$ |
33,298 |
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$ |
30,759 |
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$ |
26,359 |
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$ |
251,103 |
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$ |
174,165 |
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$ |
545,826 |
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(1) |
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Outstanding principal of $225.0 million due December 31, 2013 and estimated interest
obligation calculated using the interest rate at December 31, 2008 of 4.75%. See Note 11-
Credit Arrangements. |
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(2) |
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Outstanding principal of $150.0 million due August 1, 2014 and interest obligation calculated
at an interest rate of 101/4%. |
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(3) |
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Asset retirement obligations of oil and natural gas assets, excluding salvage value and
accretion. |
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(4) |
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The put premium obligations above represent the undiscounted obligation to our counterparty.
We have recognized $97,000 of interest for the year ended December 31, 2008 and will recognize
$394,000 of additional interest associated with the put premium obligations over the remaining
life of the contracts. |
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(5) |
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Estimated earn out obligation due an unaffiliated third party based on the operation
efficiency of the Hagerman Gas Gathering System. |
Deferred taxes are not included in the table above. The utilization of net operating loss
carryforwards combined with our plans for development and acquisitions may offset any major cash
outflows. However, the ultimate timing of the settlements cannot be precisely determined.
The amounts above include principal payment obligations under the revolving credit facility
and senior notes noted in the table above, and interest payments on such indebtedness. See Note 11-
Credit Arrangements.
Our contractual obligations include long-term debt, operating leases, drilling commitments,
and derivative obligations. From time-to-time, we enter into off-balance sheet arrangements and
transactions
(69)
that can give rise to material off-balance sheet obligations. As of December 31, 2008,
the material off-balance sheet arrangements and transactions that we had entered into included (i)
undrawn letters of credit, (ii) operating lease agreements and, (iii) contractual obligations for
which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts
that are sensitive to future changes in commodity prices. Other than the off-balance sheet
arrangements described above, we have no transactions, arrangements or other relationships with
unconsolidated entities or other persons that are reasonably likely to materially affect our
liquidity or availability of or requirements for capital resources.
Trends and Outlook
Our business is influenced by trends that affect the oil and natural gas industry. In
particular, recent declines in oil and natural gas prices and recent economic trends could
adversely affect our business, liquidity, results of operations and financial condition.
Our business is increasingly subject to the adverse trends that have taken place in the global
capital markets recently. The recent events in the credit and stock markets indicate a high
likelihood of a continuation of, and probable further expansion of, the economic weakness in the
U.S. economy that began over one year ago. The spillover of deepening fears about our banking
system may adversely impact investor confidence in us, our banking relationships, and the liquidity
and financial condition of third parties with whom we conduct operations.
We expect to face the continuing challenges of weakness in the U.S. real estate market and
increased mortgage delinquencies, investor anxiety over the U.S. economy, rating agency downgrades
of various financial issuers, unresolved issues with structured investment vehicles, deleveraging
of financial institutions and hedge funds and dislocation in the inter-bank market. If significant,
continued volatility, changes in interest rates, defaults, market liquidity, declines in equity
prices, and the strengthening or weakening of foreign currencies against the U.S. dollar,
individually or in tandem, could have a material adverse effect on our liquidity, results of
operations, financial condition or cash flows through realized losses, and impairments.
In response to deteriorating market conditions we:
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revised our 2009 capital expenditures downward to $29.1 million of which: |
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$10.2 million for the completion of wells that were in progress at
year-end in our North Texas Barnett Shale project; |
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$5.2 million for the completion of wells that were in progress at
year-end, pipeline construction, seismic and leasehold acquisitions in our
New Mexico Wolfcamp Carbonate project; |
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$12.1 million for the completion of wells that were in progress at
year-end, the drilling and completion of new wells and workovers of
existing wells in our Permian Basin of West Texas properties; and |
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$1.6 million for the drilling and completion of new wells in our
Yegua/Frio and Cotton Valley Reef projects and lease maintenance on our
Utah/Colorado project |
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drew an additional $62.5 million under our Revolving Credit Agreement and
invested the majority of the $62.5 million in a demand deposit money market
account for the purpose of strengthening our liquidity; |
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did not request an increase in our borrowing base at the present time
because of the associated interest rate and fee increases; and |
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entered into the Barnett shale Farmout Agreement described on
page 4. |
(70)
Although we expect to experience a reduction in the level of our activity in 2009, we believe
the steps we have taken to date in response to the global slowdown in the oil and natural gas
industry will positively impact our ability to follow through with our business strategy without
being forced to implement additional significant countermeasures, such as work force layoffs. Other
potential steps that could be implemented in light of the current recession, if we deem it
necessary, could include selling assets or entering into more farmout and joint venture agreements
with industry partners to reduce our costs.
The oil and natural gas industry is capital intensive. We make, and anticipate that we will
continue to make, substantial capital expenditures in the exploration for, development and
acquisition of oil and natural gas reserves. Historically, our capital expenditures have been
financed primarily with:
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internally generated cash from operations; |
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proceeds from bank borrowings; |
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industry joint venture arrangements; |
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proceeds from sales of equity and debt securities; and |
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proceeds from sales of non-core assets. |
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The continued availability of these capital sources depends upon a number of variables,
including: |
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our proved reserves; |
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the volumes of oil and natural gas we produce from existing wells; |
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the prices at which we sell oil and natural gas; |
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our ability to acquire, locate and produce new reserves; and |
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events occurring within the global capital markets. |
Each of these variables materially affects our borrowing capacity. We may from time to time
seek additional financing in the form of:
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increased bank borrowings; |
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additional sales of our debt or equity securities; |
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sales of non-core properties; |
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other forms of financing; or |
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a combination of any of the above. |
Except for the existing revolving credit facility we have with our bank lenders, we do not
currently have any agreements for any future financing and there can be no assurance as to the
availability or terms of any such future financing.
Oil and Natural Gas Price Trends
Changes in oil and natural gas prices significantly affect our revenues, financial condition,
cash flows and borrowing capacity. Markets for oil and natural gas have historically been volatile
and we expect this trend to continue. Prices for oil and natural gas typically fluctuate in
response to relatively minor changes in supply and demand, market uncertainty, seasonal, political
and other factors beyond our
(71)
control. We are unable to accurately predict the prices we receive for
our oil and natural gas. Accordingly, any significant or sustained declines in oil or natural gas
prices may materially adversely affect our
financial condition, liquidity, ability to obtain
financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil
or natural gas that we can produce economically. A decline in oil or natural gas prices could have
a material adverse effect on the estimated value and estimated quantities of our oil and natural
gas reserves, our ability to fund our operations and our financial condition, cash flow, results of
operations and access to capital.
Our capital expenditure budgets are highly dependent on future oil and natural gas prices.
For the twelve months ended December 31, 2008, the average realized sales price for our oil
and natural gas was $64.02 per BOE. For the year ended December 31, 2007, our average realized
sales price was $50.72 per BOE.
Production Trends
Like all other oil and natural gas exploration and production companies, we experience natural
production declines. We recognize that oil and natural gas production from a given well naturally
decreases over time and that a downward trend in our overall production could occur unless these
natural declines are offset by additional production from drilling, workover or recompletion
activity, or acquisitions of producing properties. If any production declines we experience are
other than a temporary trend, and if we cannot economically replace our reserves, our results of
operations may be materially adversely affected and our stock price may decline. Our future growth
will depend upon our ability to continue to add oil and natural gas reserves in excess of
production at a reasonable cost.
While we have achieved increased production and revenue in our New Mexico Wolfcamp and Barnett
Shale projects as a result of our significant investments in these areas, production growth in our
Barnett Shale investments has been restricted due to limited pipeline capacity.
In recent periods, we have concentrated our drilling and development efforts on our resource
natural gas projects in our Barnett Shale and New Mexico Wolfcamp projects. Due to limited
development, our production has decreased in accordance with normal decline curves for our
principal Permian Basin oil properties and south Texas gas properties.
Lease Operating Expense Trends
The level of drilling, workover and maintenance costs in the primary areas in which we operate
and produce continues at a historically high level. Service rates charged by oil field service
companies have increased significantly during recent periods and electrical cost has also
increased. These increased cost levels have affected our per BOE lease operating expense. While we
do not expect a continued increase in service costs since activities have slowed due to oil and
natural gas prices, service cost increases are possible and could significantly impact our lease
operating expense.
Interest Expense Trends
As a result of having increased our borrowings by $62.5 million at the end of the fourth
quarter of 2008, we expect a corresponding increase in our annual interest expense. An increase in
interest rates would also negatively impact our interest expense.
Inflation
Although certain of our costs and expenses are affected by general inflation, inflation does
not normally have a significant effect on our business. Our costs and expenses tend to react to
activity levels in our industry and commodity price movements.
(72)
Recent Accounting Pronouncements
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair
Value Measurements (SFAS 157). SFAS 157 defines fair value as used in numerous accounting
pronouncements, establishes a framework for measuring fair value in accordance with generally
accepted accounting principles and expands disclosure requirements related to the use of fair value
measures in financial statements. We adopted SFAS 157 effective January 1, 2008 and the adoption
did not have a significant effect on our financial position or operating results.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets
and Financial Liabilities, Including an Amendment of FASB Statement No. 115, (SFAS 159) which
became effective on January 1, 2008. SFAS 159 permits entities to measure eligible financial
assets, financial liabilities and firm commitments at fair value, on an instrument-by-instrument
basis, that are otherwise not permitted to be accounted for at fair value under other generally
accepted accounting principles. The fair value measurement election is irrevocable and subsequent
changes in fair value must be recorded in earnings. This statement did not have any effect on our
financial position or operating results as we did not elect to apply the fair value method.
In April 2007, the FASB issued FASB Staff Position FIN 39-1, Amendment of FASB Interpretation
No. 39 (FSP FIN 39-1). FSP FIN 39-1 clarifies that a reporting entity that is party to a master
netting arrangement can offset fair value amounts recognized for the right to reclaim cash
collateral (a receivable) or the obligation to return cash collateral (a payable) against fair
value amounts recognized for derivative instruments that have been offset under the same master
netting arrangement. FSP FIN 39-1 was effective for financial statements issued for fiscal years
beginning after November 15, 2007. Adoption of FSP FIN 39-1 did not have a material impact on our
consolidated financial statements.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (SFAS
141(R)), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and
requirements for how an acquirer recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree
and the goodwill acquired. The Statement also establishes disclosure requirements that will enable
users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is
effective for acquisitions that occur in an entitys fiscal year that begins after December 15,
2008, which will be our fiscal year 2009. The impact, if any, will depend on the nature and size of
business combinations that we consummate after the effective date.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statementsan amendment of ARB No. 51 (SFAS 160). SFAS 160 requires that accounting
and reporting for minority interests will be recharacterized as noncontrolling interests and
classified as a component of equity. SFAS 160 also establishes reporting requirements that provide
sufficient disclosures that clearly identify and distinguish between the interests of the parent
and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare
consolidated financial statements, except not-for-profit organizations, but will affect only those
entities that have an outstanding noncontrolling interest in one or more subsidiaries or that
deconsolidate a subsidiary. This statement is effective as of the beginning of our first fiscal
year beginning after December 15, 2008, which will be our fiscal year 2009. Based upon our balance
sheet, the statement would have no impact.
In February 2008, the FASB issue Financial Staff Positions (FSP) FAS 157-2, Effective Date of
FASB Statement No. 157 (FSP FAS 157-2), which delays the effective date of SFAS 157, for all
nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at
fair value in the financial statements on a recurring basis (at least annually), SFAS 157
establishes a framework for measuring fair value and expands disclosures about fair value
measurements. FSP FAS 157-2 is effective for the Company beginning
January 1, 2009. We do not anticipate that this pronouncement
will have a material impact on our results of
operations or consolidated financial position.
(73)
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities, an amendment of FASB Statement No. 133 (SFAS 161). This statement is
intended to improve transparency in financial reporting by requiring enhanced disclosures of an
entitys derivative instruments and hedging activities and their effects on the entitys financial
position, financial performance, and cash flows. SFAS 161 applies to all derivative instruments
within the scope of SFAS 133, Accounting for Derivative Instruments and Hedging Activities (SFAS
133), as well as related hedged items, bifurcated derivatives, and nonderivative instruments that
are designated and qualify as hedging instruments. Entities with instruments subject to SFAS 161
must provide expanded disclosures.
SFAS 161 is effective prospectively for financial statements issued for fiscal years and
interim periods beginning after November 15, 2008, with early application permitted. This statement
will have no impact on our financial results. We will apply SFAS 161 beginning January 1, 2009.
In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting
Principles (SFAS 162), which becomes effective for the Company 60 days following the SECs
approval of the Public Company Accounting Oversight Board amendments to AU Section 411, The
Meaning of Present Fairly in Conformity With General Accepted
Accounting Principles. This standard
identifies the sources of accounting principles and the framework for selecting the principles used
in the preparation of financial statements that are presented in conformity with generally accepted
accounting principles (GAAP). We do not anticipate that this pronouncement will have a material
impact on our results of operations or consolidated financial position.
In June 2008, the FASB issued FASB Staff
Position No. EITF 03-6-1 Determining
Whether Instruments Granted in Share-Based Payment Transactions Are
Participating Securities (FSP
EITF 03-6-1), which addresses whether instruments granted in share-based payment transactions are
participating securities prior to vesting and, therefore, need to be included in the net income
allocation in computing basic net income per share under the two class method prescribed under SFAS
128, Earnings per Share. FSP 03-6-1 is effective for financial statements issued for fiscal years
beginning after December 15, 2008 and, to the extent applicable, must be applied retrospectively by
adjusting all prior-period net income per share data to conform to the provisions of the standard.
The adoption of FSP EITF 03-6-1 is not expected to have a material effect on the Companys earnings
per share calculations.
In December 2008, the Securities and Exchange Commission published a Final Rule,
Modernization of Oil and Gas Reporting. The new
rule
permits the use of new technologies to determine proved reserves if those technologies have been
demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also will
allow companies to disclose their probable and possible reserves to investors. In addition, the new
disclosure requirements require companies to: (a) report the independence and qualifications of its
reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare
reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an
average price based upon the prior 12-month period rather than
year-end prices. The use of average prices will affect future
impairment and depletion calculaions.
The new disclosure requirements are effective for annual reports on Forms 10-K for fiscal
years ending on or after December 31, 2009. A company may not apply the new rules to
disclosures in quarterly reports prior to the first annual report in which the revised disclosures
are required. The Company has not yet determined the impact of this
Final Rule, which will vary depending on changes in commodity prices,
on its disclosures, financial position or results of operations.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Below, we have provided certain quantitative and qualitative information about market risks
and our derivative instruments at December 31, 2008 from which we may incur future earnings, gains
or losses from changes in market interest rates and oil and natural gas prices.
(74)
Derivative transactions, like other financial transactions, involve a variety of significant
risks. The specific risks presented by a particular derivative transaction necessarily depend upon
the terms of the transaction and our particular circumstances. In general, however, all derivative
transactions involve some combination of market risk, credit risk, funding risk and operational
risk.
Market risk is the risk that the value of a transaction will be adversely affected by
fluctuations in the level or volatility of, or correlation or relationship between, one or more
market prices, rates or
indices or other market factors or by illiquidity in the market for the relevant transaction or in
a related market.
Credit risk is the risk that a counterparty will fail to perform its obligations to us when
due.
Funding risk is the risk that, as a result of mismatches or delays in the timing of cash flows
due from or to our counterparties in derivative transactions or related hedging, trading,
collateral or other transactions, we or our counterparty will not have adequate cash available to
fund current obligations.
Operational risk is the risk of loss to us arising from inadequacies in or failures of our
internal systems and controls for monitoring and quantifying the risks and contractual obligations
associated with derivative transactions, for recording and valuing derivative and related
transactions, or for detecting human error, systems failure or management failure.
Depending upon the terms of a specific transaction, there may be other risks which could be
significant. Highly customized derivative transactions, in particular, may increase liquidity risk
and introduce other significant risk factors of a complex nature. Highly leveraged transactions may
experience substantial gains or losses in value as a result of relatively small changes in the
value or level of an underlying or related market factor.
Another important consideration in evaluating the risks and contractual obligations associated
with a particular derivative transaction is that a derivative transaction may be modified or
terminated only by mutual consent of the parties to the transaction and subject to agreement on
individually negotiated terms. Accordingly, it may not be possible for us to modify, terminate or
offset our obligations or our exposure to the risks associated with a transaction prior to its
scheduled termination date.
Derivative transactions are not obligations of or guaranteed or insured by the U.S.
Government, the Federal Deposit Insurance Corporation, the Federal Reserve Board or any other
federal, state or other governmental agency.
Derivative transactions are not deposits of our counterparties or any of their affiliates.
Non-derivative Financial Instruments
We borrow funds under fixed rate and variable rate debt instruments that give rise to interest
rate risk. Our objective in borrowing under fixed or variable rate debt is to satisfy capital
requirements while minimizing our costs of capital. See Note 11-
Credit Arrangements for a discussion of our debt instruments.
Derivative Financial Instruments
We utilize interest rate and commodity price derivative contracts to hedge interest rate and
commodity price risks in accordance with parameters recommended by management and approved by our
Board. Our management recommends the timing, type and extent of hedge transactions.
(75)
Interest Rate Sensitivity as of December 31, 2008
Although we are currently protected from interest rate volatility up to $250.0 million through
our senior notes and our interest rate swaps, we are exposed to interest rate volatility on lending
above this level. Our only financial instruments sensitive to changes in interest rates are our
bank debt and interest rate swaps. As the interest rate is variable and reflects current market
conditions, the carrying value of our bank debt approximates the fair value. The table below shows
principal cash flows and related
interest rates by expected maturity dates. Refer to Note 9- Derivative Instruments for further
discussion of our debt that is sensitive to interest rates.
|
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|
|
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|
|
2013 and |
|
|
|
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
after |
|
Total |
Revolving Credit Facility (secured) |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
225,000 |
|
|
$ |
225,000 |
|
Interest rate |
|
|
4.75 |
% |
|
|
4.75 |
% |
|
|
4.75 |
% |
|
|
4.75 |
% |
|
|
4.75 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
Senior notes |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
150,000 |
|
|
$ |
150,000 |
|
Interest rate |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
10.25 |
% |
|
|
|
|
At December 31, 2008, we had outstanding bank loans in the aggregate principal amount of
$225.0 million at a base interest rate of 4.75%, including
applicable margin. Under our amended revolving
credit facility, we may elect an interest rate based upon the agent banks base lending rate, plus
a margin ranging from 0% to 0.25%, or the LIBOR rate, plus a margin
ranging from 2.50% to 3.00% per
annum, depending upon the outstanding principal amount of the loans. The interest rate we are
required to pay, including the applicable margin, may never be less than 4.75%. A change in the
interest rate of one percent could cause an approximate $1.3 million change in interest expense on
an annual basis on the current amount of borrowings, when factoring in the interest rate protection
we have with our interest rate swaps. As the interest rate is variable and reflects current market
conditions, the carrying value of our bank debt approximates the fair value.
At December 31, 2008, we had outstanding senior notes in the aggregate principal amount of
$150.0 million bearing interest at a rate of 101/4% per annum. The carrying value of our 101/4% senior
notes at December 31, 2008 is approximately $145.9 million and their estimated fair value is
approximately $99.0 million. Fair value is estimated based on market trades at or near December
31, 2008. Interest on our senior notes and their carrying value are not affected by changes in
interest rates. However, the fair value of the senior notes increases as interest rates decrease
and their fair value decreases as interest rates increase. Because we have no present plan or
intent to redeem the senior notes, changes in their fair value are not expected to have any effect
on our cash flow in the foreseeable future.
We have employed fixed interest rate swap contracts with BNP Paribas and Citibank, NA based on
the 90-day LIBOR rates at the time of the contracts. These contracts are accounted for by
markto- market accounting as prescribed in SFAS 133. We receive interest based on a 90-day
LIBOR rate and pay the fixed rates shown below. We view these contracts as protection against
future interest rate volatility. As of December 31, 2008, the fair market value of these interest
rate swaps was a liability of approximately $8.1 million.
(76)
A recap for the period of time, notional amounts, fixed interest rates and the fair market
value of these contracts as of December 31, 2008 follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
|
Weighted Average |
|
Estimated |
|
Period of Time |
|
Amounts |
|
|
Fixed Interest Rates |
|
Fair Market Value |
|
|
|
($ in millions) |
|
|
|
|
|
|
($ in thousands) |
|
January 1, 2009 through December 31, 2009 |
|
$ |
100 |
|
|
|
4.22 |
% |
|
$ |
(3,004 |
) |
January 1, 2010 through October 31, 2010 |
|
$ |
100 |
|
|
|
4.71 |
% |
|
|
(2,517 |
) |
November 1, 2010 through December 31, 2010 |
|
$ |
50 |
|
|
|
4.26 |
% |
|
|
(216 |
) |
January 1, 2011 through December 31, 2011 |
|
$ |
100 |
|
|
|
4.67 |
% |
|
|
(2,315 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
(8,052 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Price Sensitivity
Our major market risk exposure is in the pricing applicable to our oil and natural gas
production. Market risk refers to the risk of loss from adverse changes in oil and natural gas
prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and
spot prices applicable to the region in which we produce natural gas. Historically, prices
received for oil and natural gas production have been volatile and unpredictable. We expect
pricing volatility to continue. NYMEX closing oil prices ranged from a low of $50.48 per barrel to
a high of $98.18 per barrel during the twelve months ended December 31, 2007. NYMEX closing
natural gas prices during the twelve months ended December 31, 2007 ranged from a low of $5.38 per
Mcf to a high of $8.64 per Mcf. During the twelve months ended December 31, 2008 NYMEX closing oil
prices ranged from a low of $33.87 to a high of $145.29. NYMEX closing natural gas prices during
the twelve months ended December 31, 2008 ranged from a low of $5.29 per Mcf to a high of $13.58
per Mcf. A significant decline in the prices of oil or natural gas could have a material adverse
effect on our financial condition and results of operations.
We employ various derivative instruments in order to minimize our exposure to the
aforementioned commodity price volatility. As of December 31, 2008, we had employed collars and
puts in order to protect against this price volatility. Although all of the contracts that we have
entered into are viewed as protection against this price volatility, all contracts are accounted
for by the mark-to-market accounting method as prescribed in SFAS 133.
At December 31, 2008 we had crude oil collar and put derivative contracts in place covering
future oil production of approximately 1.8 million barrels. Crude oil futures prices have
stabilized since December 31, 2008. If prices stay at current levels, the settlement price will be
below the price range of the collar contracts, thus causing our counterparties to make payments at
settlement date for these contracts. In addition, at current price levels, the settlement price
will cause our counterparty to pay us at settlement date for our put contracts.
At December 31, 2008 we had natural gas collar derivative contracts in place covering future
natural gas production of approximately 3.3 Bcf. Natural gas futures prices have continued to
decrease since December 31, 2008 and as prices have decreased, we could receive larger payments
from our counterparties for these natural gas derivative contracts at settlement date than are
currently recorded as of December 31, 2008.
Changes in commodity prices will affect the fair value of our derivative contracts as recorded
on our balance sheet during future periods and, consequently, our reported net earnings. The
changes in the recorded fair value of the commodity derivatives are marked to market through
earnings. If commodity prices decrease, this commodity price change could have a positive impact
to our earnings. Conversely, if commodity prices increase, this commodity price change could have
a negative effect on earnings. Each derivative contract is evaluated separately to determine its
own fair value. Due to the current volatility of
(77)
both crude oil and natural gas prices, we are
currently unable to estimate the effects on earnings in future periods, but based on the volume of
our future oil and natural gas production covered by commodity derivative contracts, the effects
may be material. A 10% change in commodity prices would have changed our commodity derivative
valuation contracts by approximately $3.7 million.
Descriptions of our active commodity derivative contracts as of December 31, 2008 are set
forth below:
Put Options. Puts are options to sell assets. For any put transaction, the
counterparty is required to make a payment to the Company if the reference floating price for any
settlement period is less than the put or floor price for such contract.
In June 2008, we entered into multiple put contracts with BNP Paribas and in October 2008 we
entered into a put contract with Citibank, N.A. In lieu of making premium payments for the puts at
the
time of entering into our put contracts, we deferred payment until the settlement dates of the
contracts. Future premium payments will be netted against any payments that the counterparty may
owe to us based on the floating price. Due to the deferral of the premium payments, we will pay a
total amount of premiums of $4.68 million, which is $491,000 greater than if the premiums had been
paid at the time of entering into the contracts. The $491,000 difference is recorded as a discount
to the put premium obligations and recognized as interest expense over the terms of the contracts
using the effective interest method. Through December 31, 2008, we have accrued $97,000 of
interest expense. Accordingly, the recorded balance of the put premium obligations at December 31,
2008 is $4.28 million.
A summary of our put positions at December 31, 2008 is as follows:
|
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|
|
|
|
|
|
|
|
|
|
Barrels of |
|
|
|
|
|
|
Estimated |
|
Period of Time |
|
Oil |
|
|
Floor |
|
|
Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
January 1, 2009 through December 31, 2009 |
|
|
109,500 |
|
|
$ |
100.00 |
|
|
$ |
5,112 |
|
January 1, 2010 through December 31, 2010 |
|
|
280,100 |
|
|
$ |
84.36 |
|
|
|
6,405 |
|
January 1, 2011 through December 31, 2011 |
|
|
146,000 |
|
|
$ |
100.00 |
|
|
|
5,139 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
16,656 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Collars. Collars are contracts which combine both a put option or floor and a call
option or ceiling. These contracts may or may not involve payment or receipt of cash at
inception, depending on the ceiling and floor pricing. Citibank, N.A. and BNP Paribas are the
counterparties used for oil and natural gas collar contracts.
A
summary of our collar positions at December 31, 2008 is as follows:
(78)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels of |
|
|
NYMEX Oil Prices |
|
|
Estimated |
|
Period of Time |
|
Oil |
|
|
Floor |
|
|
Ceiling |
|
|
Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
January 1, 2009 through December 31, 2009 |
|
|
766,500 |
|
|
$ |
65.71 |
|
|
$ |
82.93 |
|
|
$ |
10,942 |
|
January 1, 2010 through October 31, 2010 |
|
|
486,400 |
|
|
$ |
63.44 |
|
|
$ |
78.26 |
|
|
|
2,449 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
M M Btu of |
|
WAHA Gas Prices |
|
|
|
|
|
|
Natural Gas |
|
Floor |
|
Ceiling |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1, 2009 through December 31, 2009 |
|
|
3,285,000 |
|
|
$ |
7.06 |
|
|
$ |
9.93 |
|
|
|
6,611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
20,002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our Consolidated Financial Statements and supplementary financial data are included in this
Annual Report on Form 10-K beginning on page F-1.
We have prepared these financial statements in conformity with generally accepted accounting
principles. We are responsible for the fairness and reliability of the financial statements and
other financial data included in this report. In the preparation of the financial statements, it is
necessary for us to make informed estimates and judgments based on currently available information
on the effects of certain events and transactions.
Our independent public accountants, BDO Seidman, LLP, are engaged to audit our financial
statements and to express an opinion thereon. Their audit is conducted in accordance with the
standards of the Public Company Accounting Oversight Board (United States) to enable them to report
whether the financial statements present fairly, in all material respects, our financial position
and results of operations in accordance with accounting principles generally accepted in the United
States.
The Audit Committee of our Board of Directors is composed of four Directors who are not our
employees. This committee meets periodically with our independent public accountants and
management. Our independent public accountants have full and free access to the Audit Committee to
meet, with and without management being present, to discuss the results of their audits and the
quality of our financial reporting.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There were no changes in or disagreements with accountants on accounting and financial
disclosure as of December 31, 2008 and 2007.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
As of the end of the period covered by this Annual Report on Form 10-K, the effectiveness of
our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange
Act of 1934, as amended) was evaluated by our management, with the participation of our Chief
Executive Officer, Larry C. Oldham (principal executive officer), and our Chief Financial Officer,
Steven D. Foster (principal financial officer), in accordance with rules of the Securities Exchange
Act of 1934, as amended. Based on that evaluation, Mr. Oldham and Mr. Foster have concluded that
our disclosure controls and procedures were effective as of December 31, 2008 to provide reasonable
assurance that information required to be disclosed in our reports filed or submitted under the
Securities Exchange Act of 1934, as
(79)
amended, is accumulated and communicated to management and
recorded, processed, summarized and reported within the time periods specified in the SECs rules
and forms.
Managements Annual Report on Internal Control Over Financial Reporting
Management of Parallel is responsible for establishing and maintaining adequate internal
control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of
1934, as amended.
Our internal control over financial reporting is a process designed by, or under the
supervision of, our principal executive and financial officers, and effected by our Board of
Directors, management and other personnel, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with accounting principles generally accepted in the United States of
America. Our internal control over financial reporting includes those policies and procedures
that:
|
|
|
pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of our assets; |
|
|
|
|
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with accounting
principles generally accepted in the United States of America, and that our
receipts and expenditures are being made only in accordance with authorizations
of management and our Board of Directors; and |
|
|
|
provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of our assets that could have a
material effect on our financial statements. |
Because of its inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Therefore, even those systems determined to be effective can provide only
reasonable assurance with respect to financial statement preparation and presentation. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance
with the policies and procedures may deteriorate.
Management assessed the effectiveness of Parallels internal control over financial reporting
as of December 31, 2008. In making this assessment, management used the criteria set forth in
Internal Control Integrated Framework, issued by the Committee of Sponsoring Organizations (COSO)
of the Treadway Commission. As a result of this assessment, management determined that Parallels
internal control over financial reporting, as of December 31, 2008, was effective based on those
criteria.
BDO Seidman, LLP, the independent registered public accounting firm who also audited our
Consolidated Financial Statements included in this Annual Report on Form 10-K, has issued an
attestation report on our internal control over financial reporting as of December 31, 2008, which
is set forth below under Attestation Report.
Changes in Internal Controls
During the fourth quarter of fiscal year 2008, there were no changes in our internal control
over financial reporting that materially affected, or are reasonably likely to materially affect,
our internal control over financial reporting.
(80)
Attestation Report
Report of Independent Registered Public Accounting Firm
on Internal Control over Financial Reporting
Board of Directors and Stockholders
Parallel Petroleum
Midland, Texas
We have audited Parallel Petroleum Corporations internal control over financial reporting as of
December 31, 2008, based on criteria established in Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria).
Parallel Petroleum Corporations management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of internal control
over financial reporting, included in the accompanying
Item 9A. Managements Annual Report on
Internal Control Over Financial Reporting. Our responsibility is to express an opinion on Parallel
Petroleum Corporations internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of internal control based on the assessed
risk. Our audit also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
companys internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Parallel Petroleum Corporation maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of Parallel Petroleum Corporation as of
December 31, 2008 and 2007, and the related consolidated statements of operations, comprehensive
income (loss), stockholders equity, and cash flows for each of the three years in the period ended
December 31, 2008 and our report dated February 23, 2009 expressed an unqualified opinion thereon.
(81)
BDO Seidman, LLP
Houston, Texas
February 23, 2009
ITEM 9B. OTHER INFORMATION
There is no other information to disclose as of December 31, 2008 and 2007.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Our Directors and executive officers at February 1, 2009 are as follows:
|
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|
|
Director |
|
|
Name |
|
Age |
|
Since |
|
Position with Company |
Jeffrey G. Shrader(1)
|
|
|
58 |
|
|
|
2001 |
|
|
Director and Chairman of the Board of Directors |
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Larry C. Oldham(2)
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55 |
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1979 |
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Director, President and Chief Executive Officer |
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Donald E. Tiffin
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51 |
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Chief Operating Officer |
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Steven D. Foster
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53 |
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Chief Financial Officer |
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Eric A. Bayley
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60 |
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Vice President of Corporate Engineering |
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John S. Rutherford
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48 |
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Vice President of Land and Administration |
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Edward A. Nash(1)
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60 |
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2007 |
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Director |
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Martin B. Oring(1)
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63 |
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2001 |
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Director |
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Ray M. Poage(1)
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61 |
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2003 |
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Director |
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(1) |
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Member of Hedging and Acquisitions Committee, Compensation Committee, Audit
Committee
and the Corporate Governance and Nominating Committee. |
|
(2) |
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Member of Hedging and Acquisitions Committee. |
Mr. Shrader has been a shareholder in the law firm of Sprouse Shrader Smith, Amarillo, Texas,
since January 1993. He has also served as a director of Hastings Entertainment, Inc. since 1992.
Mr. Shrader has served as Chairman of the Board of Directors since August 2007. At February 1,
2009, Mr. Shrader was Chairman of the Corporate Governance and Nominating Committee of the Board of
Directors.
Mr. Oldham is a founder of Parallel and has served as an officer and Director since its
formation in 1979. Mr. Oldham became President of Parallel in October 1994, and served as Executive
Vice President before becoming President. Effective January 1, 2004, Mr. Oldham became Chief
Executive Officer. Mr. Oldham received a Bachelor of Business Administration degree from West Texas
State University in 1975.
Mr. Tiffin served as Vice President of Business Development from June 2002 until January 1,
2004 when he became Chief Operating Officer. From August 1999 until May 2002, Mr. Tiffin served as
General Manager of First Permian, L.P. and from July 1993 to
July 1999, Mr. Tiffin was the Drilling and
(82)
Production Manager in the Midland, Texas office of Fina Oil and Chemical Company. Mr. Tiffin
graduated from the University of Oklahoma in 1979 with a Bachelor of Science degree in Petroleum
Engineering.
Mr. Foster has been the Chief Financial Officer of Parallel since June 2002. From November
2000 to May 2002, Mr. Foster was the Controller and Assistant Secretary of First Permian, L.P. and
from September 1997 to November 2000, he was employed by Pioneer Natural Resources, USA in the
capacities of Director of Revenue Accounting and Manager of Joint Interest Accounting. Mr. Foster
graduated from Texas Tech University in 1977 with a Bachelor of Business Administration degree in
Accounting. He is a certified public accountant.
Mr. Bayley has been Vice President of Corporate Engineering since July 2001. From October 1993
until July 2001, Mr. Bayley was employed by Parallel as Manager of Engineering. From December 1990
to October 1993, Mr. Bayley was an independent consulting engineer and devoted substantially all of
his time to Parallel. Mr. Bayley graduated from Texas A&M University in 1978 with a Bachelor of
Science degree in Petroleum Engineering. He graduated from the University of Texas of the Permian
Basin in 1984 with a Masters of Business Administration degree.
Mr. Rutherford has been Vice President of Land and Administration of Parallel since July 2001.
From October 1993 until July 2001, Mr. Rutherford was employed as Manager of Land/Administration.
From May 1991 to October 1993, Mr. Rutherford served as a consultant to Parallel, devoting
substantially all of his time to Parallels business. Mr. Rutherford graduated from Oral Roberts
University in 1982 with a degree in Education, and in 1986 he graduated from Baylor University with
a Masters degree in Business Administration.
Mr. Nash served as a consultant to TOTAL Petrochemicals, Inc. from February 2004 until
December 2006, providing advisory services primarily in the areas of corporate relocation,
construction, safety and communications. He also served as a consultant to Clayton Williams
Energy, Inc. from September 2003 to September 2004, primarily in the area of acquisitions. From
2000 to March 2003, Mr. Nash was employed by TOTAL as a Senior Vice President of Special Projects
and as Senior Vice President of its U.S. onshore division. From 1974 to 2000, Mr. Nash was
employed by Fina, Inc. in various capacities, including serving as Vice President of Human
Resources, Vice President Exploration and Production from April 1998 to 2000 and as President of
Fina Natural Gas Company from 1999 to 2000. Mr. Nash graduated from Texas A&M University in 1970
with a Bachelors of Science degree in Mechanical Engineering. He is a registered professional
engineer in petroleum and mechanical engineering. At February 1, 2009, Mr. Nash was Chairman of the
Compensation Committee.
Mr. Oring is an owner and managing member of Wealth Preservation, LLC, a financial counseling
firm founded by Mr. Oring in January 2001. From 1998 to December 2000, Mr. Oring was Managing
Director Executive Services of Prudential Securities Incorporated, and from 1996 to 1998, Mr. Oring
was Managing Director Capital Markets of Prudential Securities Incorporated. From 1989 to 1996,
Mr. Oring was Manager of Capital Planning for The Chase Manhattan Corporation. Mr. Oring is also a
director and member of the audit committees of PetroHunter Energy Corporation and Searchlight
Minerals Corp. At February 1, 2009, Mr. Oring was Chairman of the Hedging and Acquisitions
Committee of the Board of Directors.
Mr. Poage was a partner in KPMG LLP from 1980 to June 2002 when he retired. Mr. Poages
responsibilities included supervising and managing both audit and tax professionals and providing
services, primarily in the area of taxation, to private and publicly held companies engaged in the
oil and natural gas industry. He is also a Director and Chairman of the Audit Committee of the
Board of Directors of Concho Resources, Inc. At February 1, 2009, Mr. Poage was Chairman of the
Audit Committee of the Board of Directors.
(83)
Directors hold office until the annual meeting of stockholders following their election or
appointment and until their respective successors have been duly elected or appointed.
Officers are appointed annually by the Board of Directors to serve at the Boards discretion
and until their respective successors in office are duly appointed.
There are no family relationships between any of Parallels Directors or officers.
Consulting Arrangements
As part of our overall business strategy, we continually monitor our general and
administrative expenses. Decisions regarding our general and administrative expenses are made
within parameters we believe to be compatible with our size, the level of our activities and
projected future activities. Our goal
is to keep general and administrative expenses at acceptable
levels, without impairing the quality of services and organizational structure necessary for
conducting our business. In this regard, we retain outside advisors and consultants from time to
time to provide technical and administrative support services in the operation of our business.
Corporate Governance
Under the Delaware General Corporation Law and Parallels bylaws, our business, property and
affairs are managed by or under the direction of the Board of Directors. Members of the Board are
kept informed of Parallels business through discussions with the Chairman of the Board, the Chief
Executive Officer and other officers, by reviewing materials provided to them and by participating
in meetings of the Board and its committees. We currently have five members of the Board, including
Edward A. Nash, Larry C. Oldham, Martin B. Oring, Ray M. Poage and Jeffrey G. Shrader. The Board
has determined that all of our Directors, other than Mr. Oldham, are independent for purposes of
NASD Rule 4200(a)(15), the independent standards applicable to us. The Board based these
determinations primarily on responses of the Directors and executive officers to questions
regarding employment and compensation history, affiliations and family and other relationships,
comparisons of the independence criteria under NASD Rule 4200(a)(15) to the particular
circumstances of each Director and on discussions among the Directors.
Committees of the Board of Directors
The Board has four separately-designated standing committees, which include:
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the Audit Committee; |
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the Corporate Governance and Nominating Committee; |
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the Compensation Committee; and |
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the Hedging and Acquisitions Committee. |
Audit Committee
The Audit Committee of the Board of Directors oversees our accounting and financial reporting
processes and reviews the results of the annual audit of our Consolidated Financial Statements and
recommendations of the independent auditors with respect to our accounting practices, policies and
procedures. As prescribed by our Audit Committee Charter, the Audit Committee also assists the
Board of Directors in fulfilling its oversight responsibilities, reviewing our systems of internal
accounting and financial controls, and the independent audit of our Consolidated Financial
Statements. The Audit Committee is directly responsible for the appointment, compensation,
retention and oversight of the work of the auditors.
(84)
The Audit Committee of the Board of Directors consists of four Directors, all of whom have no
financial or personal ties to Parallel (other than director compensation and equity ownership as
described or incorporated in this Annual Report on Form 10-K) and meet the Nasdaq standards for
independence. The Board of Directors has determined that at least one member of the Audit
Committee, Ray M. Poage, meets the criteria of an audit committee financial expert as that term
is defined in Item 407(d)(5) of Regulation S-K, and is independent for purposes of Nasdaq listing
standards and Rule 10A-3(b)(1) under
the Securities Exchange Act of 1934, as amended. Mr. Poages background and experience
includes service as a partner of KPMG LLP where Mr. Poage participated extensively in accounting,
auditing and tax matters related to the oil and natural gas business. The Audit Committee operates
under a charter which can be viewed in our website on www.plll.com.
The current members of the Audit Committee are Edward A. Nash, Martin B. Oring, Ray M. Poage
(Chairman) and Jeffrey G. Shrader.
Corporate Governance and Nominating Committee
The Boards Corporate Governance and Nominating Committee operates under a charter outlining
the functions and responsibilities of the committee, including recommending to the full Board of
Directors nominees for election as directors of Parallel, and making recommendations to the Board
of Directors from time to time as to matters of corporate governance. The current members of this
committee are Edward A. Nash, Martin B. Oring, Ray M. Poage and Jeffrey G. Shrader (Chairman). A
copy of the charter can be viewed in our website at www.plll.com.
The committee will consider candidates for Director suggested by stockholders. Stockholders
wishing to suggest a candidate for Director should write to any one of the members of the committee
at his address shown under Item 12 of this Annual Report on Form 10-K. Suggestions should include:
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a statement that the writer is a stockholder and is proposing a candidate
for consideration by the committee; |
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the name of and contact information for the candidate; |
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a statement of the candidates age, business and educational experience; |
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information sufficient to enable the committee to evaluate the candidate; |
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a statement detailing any relationship between the candidate and any joint
interest owners, customer, supplier or competitor of Parallel; |
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detailed information about any relationship or understanding between the
proposing stockholder and the candidate; and |
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a statement that the candidate is willing to be considered and willing to
serve as a Director if nominated and elected. |
Compensation Committee
The current members of the Compensation Committee are Edward A. Nash (Chairman), Martin B.
Oring, Ray M. Poage and Jeffrey G. Shrader. The Compensation Committee of the Board of Directors
administers and approves all elements of compensation and awards for our executive officers. The
Committee has the responsibility to review and approve the corporate goals and objectives relevant
to each executive officers compensation, evaluates individual performance of each executive in
light of those goals and objectives, and determines and approves each executives compensation
based on this evaluation.
(85)
Members of the Committee are non-management directors who, in the opinion of the Board,
satisfy the independence standards of the Nasdaq Global Market. The Committee has the sole
authority to retain consultants and advisors as it may deem appropriate in its discretion, and sole
authority to approve related fees and retention terms for these advisors.
Generally, on its own initiative the Compensation Committee reviews the performance and
compensation of all of our executives and then reviews and discusses its conclusions and
recommendations with management. A copy of the Compensation Committee charter can be viewed
on our website at www.plll.com.
Hedging and Acquisitions Committee
The Hedging and Acquisitions Committee presently consists of all five of our Directors,
including Messrs. Nash, Oldham, Oring, Poage and Shrader. Mr. Oring presently serves as Chairman of
this committee. With respect to derivative contracts, the committee reviews, assists, and advises
management on overall risk management strategies and techniques with a view to implementing prudent
commodity and interest rate derivative arrangements. The Hedging and Acquisitions Committee also
reviews with management plans and strategies for pursuing acquisitions.
Code of Ethics
The Board has adopted a code of ethics which applies to all of our Directors, officers and
employees, including our Chief Executive Officer, Chief Financial Officer and all other financial
officers and executives. You may review the code of ethics on our website at www.plll.com.
A copy of our code of ethics has also been filed with the Securities and Exchange Commission and is
incorporated by reference as an exhibit to this Annual Report on Form 10-K. We will provide without
charge to each person, upon written or oral request, a copy of our code of ethics. Requests should
be directed to:
Manager of Investor Relations
Parallel Petroleum Corporation
1004 N. Big Spring, Suite 400
Midland, Texas 79701
Telephone: (432) 684-3727
Stockholder Communications with Directors
Parallel stockholders who want to communicate with any individual Director can write to that
Director at his address shown under Item 12 of this Annual Report on Form 10-K.
Your letter should indicate that you are a Parallel stockholder. Depending on the subject
matter, the Director will:
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if you request, forward the communication to the other Directors; |
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request that management handle the inquiry directly, for example where it is
a request for information about the company or it is a stock-related matter; or |
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not forward the communication to the other Directors or management if it is
primarily commercial in nature or if it relates to an improper or irrelevant
topic. |
Director Attendance at Annual Meetings
We typically schedule a Board meeting in conjunction with our annual meeting of stockholders.
Although we do not have a formal policy on the matter, we expect our Directors to attend each
annual meeting, absent a valid reason, such as illness or a schedule conflict. Last year, all of
the individuals then serving as Directors attended our annual meeting of stockholders.
(86)
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our Directors and officers to
file periodic reports with the Securities and Exchange Commission. These reports show the
Directors and officers ownership, and the changes in ownership, of our common stock and other
equity securities. To our knowledge, all Section 16(a) filing requirements were complied with
during 2008, except that Mr.
Bayley filed one Form 4 report twelve days late. The transaction reported was the exercise by
Mr. Bayley on April 23, 2008 of a warrant to purchase 200 shares of common stock.
ITEM 11. EXECUTIVE COMPENSATION
The information required in response to this item will be set forth in Parallels definitive
proxy statement for the annual meeting of stockholders to be held during May 2009 and is
incorporated herein by reference.
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ITEM 12. |
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SECURITY OWNERSHIP OF CERTAIN BENEFICAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS |
The table below shows information as of February 17, 2009 about the beneficial ownership of
common stock by (1) each person known by us to own beneficially more than five percent of our
outstanding common stock; (2) our executive officers (3) each Director of Parallel; and
(4) all of our executive officers and
Directors as a group.
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Name and Address |
|
Amount and Nature |
|
Percent |
of Beneficial Owner |
|
of Beneficial Ownership(1) |
|
of Class(2) |
Larry C. Oldham |
|
|
631,090 |
(3) |
|
|
1.52 |
% |
1004 N. Big Spring, Suite 400
Midland, Texas 79701
|
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Donald E. Tiffin |
|
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67,400 |
(4) |
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* |
|
1004 N. Big Spring, Suite 400
Midland, Texas 79701
|
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Eric A. Bayley |
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153,690 |
(5) |
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* |
|
1004 N. Big Spring, Suite 400
Midland, Texas 79701
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Steven D. Foster |
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11,000 |
(6) |
|
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* |
|
1004 N. Big Spring, Suite 400
Midland, Texas 79701
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John S. Rutherford |
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44,000 |
(7) |
|
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* |
|
1004 N. Big Spring, Suite 400
Midland, Texas 79701
|
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Edward A. Nash |
|
|
33,615 |
(8) |
|
|
* |
|
16214 Lafone
Spring, Texas 77379
|
|
|
|
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|
Martin B. Oring |
|
|
158,774 |
(9) |
|
|
* |
|
10817 Grande Blvd.
West Palm Beach, Florida 33417
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(87)
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Name and Address |
|
Amount and Nature |
|
Percent |
of Beneficial Owner |
|
of Beneficial Ownership(1) |
|
of Class(2) |
Ray M. Poage |
|
|
131,028 |
(10) |
|
|
* |
|
4711 Meandering Way
Colleyville, Texas 76034
|
|
|
|
|
|
|
|
|
|
Jeffrey G. Shrader |
|
|
68,460 |
(11) |
|
|
* |
|
801 S. Filmore, Suite 600
Amarillo, Texas 79105
|
|
|
|
|
|
|
|
|
|
Neuberger Berman, Inc. |
|
|
3,080,089 |
(12) |
|
|
7.40 |
% |
605 Third Avenue
New York, New York 10158
|
|
|
|
|
|
|
|
|
|
Noah Malone Mitchell, 3rd |
|
|
3,400,572 |
(13) |
|
|
8.18 |
% |
4801 Gaillardia Parkway, Suite 225
Oklahoma City, Oklahoma 73142
|
|
|
|
|
|
|
|
|
|
Reid S. Walker |
|
|
3,325,745 |
(14) |
|
|
8.00 |
% |
300 Crescent Court, Suite 1111
Dallas, Texas 75201
|
|
|
|
|
|
|
|
|
|
G. Stacy Smith |
|
|
3,325,745 |
(14) |
|
|
8.00 |
% |
300 Crescent Court, Suite 1111
Dallas, Texas 75201
|
|
|
|
|
|
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|
Barrow,
Hanley, Mewhinney & Strauss, Inc. |
|
|
2,169,780 |
(15) |
|
|
5.22 |
% |
200 Ross
Avenue, 31st Floor
Dallas, Texas 75201-2761
|
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|
Barclays
Global Investors, NA |
|
|
2,498,253 |
(16) |
|
|
6.01 |
% |
400 Howard
Street
San Francisco, California 94105
|
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|
All Executive Officers and Directors |
|
|
1,299,057 |
(17) |
|
|
3.10 |
% |
as a Group (9 persons) |
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* |
|
Less than one percent. |
|
(1) |
|
Unless otherwise indicated, all shares of common stock
are held directly with sole voting and investment powers. |
|
(2) |
|
Securities not outstanding, but included in the
beneficial ownership of each such person, are deemed to be outstanding for
the purpose of computing the percentage of outstanding securities of the
class owned by such person, but are not deemed to be outstanding for the
purpose of computing the percentage of the class owned by any other person.
Shares of common stock that may be acquired within sixty days of February
17, 2009, upon exercise of outstanding stock options are deemed to be
outstanding. |
|
(3) |
|
Includes 375,000 shares of common stock held indirectly
through Oldham Properties, Ltd., a limited partnership, and as to which Mr.
Oldham disclaims beneficial ownership. Also included are 22,500 shares of
common stock underlying a presently exercisable stock option held by Mr.
Oldham. At February 17, 2009, a total of 150,000 shares of common stock
were pledged as collateral to secure repayment of loans. |
(88)
(4) |
|
Of the total number of shares shown, 57,400 shares are
held indirectly through Mr. Tiffins individual retirement account. |
|
(5) |
|
Includes 50,000 shares of common stock underlying a
presently exercisable stock option. A total of 6,790 shares of common
stock are held indirectly by Mr. Bayley through an individual retirement
account and 408(k) Plan. |
|
(6) |
|
Includes 400 shares of common stock held by Mr.
Fosters spouse and 9,000 shares held in his 408(k) Plan. |
|
(7) |
|
All of such shares may be acquired upon exercise of a
presently exercisable stock option. |
|
(8) |
|
Includes 19,450 shares of common stock held indirectly
by Mr. Nash through an individual retirement account. Also included are
7,500 shares underlying a restricted stock award which vests in increments
of 2,500 shares on each of June 12, 2009, June 12, 2010 and June 12, 2011,
but as to which Mr. Nash has sole voting power. |
|
(9) |
|
Of the total number of shares shown, 82,019 shares are
held by Wealth Preservation, LLC, a limited liability company owned and
controlled by Mr. Oring and his wife, and 30,000 shares may be acquired by
Mr. Oring upon exercise of stock options that are presently exercisable. |
|
(10) |
|
Includes 20,068 shares of common stock held indirectly
by Mr. Poage through his individual retirement account. Also included are
97,500 shares that may be acquired upon exercise of presently exercisable
stock options. |
|
(11) |
|
Includes 30,000 shares of common stock that may be
acquired upon exercise of a presently exercisable stock option. |
|
(12) |
|
Based on Amendment No. 3 to Schedule 13G filed by
Neuberger Berman, Inc., Neuberger Berman, LLC, Neuberger Berman Management,
LLC, and Neuberger Berman Equity Funds with the Securities and Exchange
Commission on February 12, 2009, Neuberger Berman, Inc., or NBI, reported
beneficial ownership of 3,080,089 shares
of common stock. Of these shares, NBI and Neuberger Berman, LLC each
reported sole voting power with respect to 740 shares; shared voting
power with respect to 2,610,170 shares; and shared dispositive power with
respect to 3,080,089 shares. Neuberger Berman Management, LLC reported
shared voting and dispositive powers with respect to 2,610,170 shares and
Neuberger Berman Equity Funds reported shared voting and dispositive powers
with respect to 2,598,470 shares. NBI is the parent company of Neuberger
Berman, LLC, an investment advisor and broker-dealer, and Neuberger Berman
Management LLC, an investment advisor to a series of public mutual funds.
Neuberger Berman, LLC is deemed to be a beneficial owner of such shares
since it has shared dispositive power, and in some cases the sole power to
vote such shares. Neuberger Berman Management LLC is deemed to be a
beneficial owner of such shares since it has shared dispositive and voting
power. The holdings of Lehman Brothers Asset Management LLC, and
Lehman Brothers Asset Management Inc., affiliates
of Neuberger Berman LLC, are also included in the total number of shares
shown. |
|
(13) |
|
Based on Schedule 13G filed with the Securities and
Exchange Commission on January 9, 2009, Mr. Mitchell and his wife, Amy
Mitchell, reported shared voting and dispositive powers with respect to
such shares. |
|
(14) |
|
Based on Amendment No. 1 to Schedule 13G filed with the Securities and
Exchange Commission on February 17, 2009, Reid S. Walker and G. Stacy Smith
each reported shared voting powers and shared dispositive powers with
respect to such shares. |
|
(15) |
|
Based on Amendment No. 1 to Schedule 13G filed by Barrow,
Hanley, Mewhinney & Strauss, Inc. with the Securities and
Exchange Commission on February 12, 2009,
|
(89)
|
|
Barrow, Hanley, Mewhinney
& Strauss, Inc. or BHMSI, reported beneficial
ownership of 2,169,780 shares of common stock. Of these shares BHMSI
reported sole voting power of 953,880 shares; shared voting power with
respect to 1,215,900 shares; and sole dispositive powers with respect
to 2,169,780 shares. |
|
(16) |
|
Based on Schedule 13G filed by Barclays Global Investors,
NA, Barclays Global Funds Advisors, Barclays Global Investors, Ltd.
Barclays Global Investors Japan Limited, Barclays Global Investors
Canada Limited, Barclays Global Investor Australia Limited and Barclays Global
Investors (Deutschland) AG with the Securities and Exchange
Commission on February 5, 2009, Barclays Global Investors, NA
reported beneficial ownership of 2,498,253 shares of common stock. Of
these shares Barclays Global Investors, NA reported sole voting power
of 1,418,350 shares and sole dispositive power of 1,575,562 shares,
Barclays Global Fund Advisors reported sole voting and dispositive
powers with respect to 922,691 shares.
|
|
(17) |
|
Includes 274,000 shares of common stock underlying
stock options that are presently exercisable. The unexercisable portion of
stock options held by our officers and directors do not become exercisable
within the next sixty days. |
Equity Compensation Plans
At December 31, 2008, a total of 2,436,160 shares of common stock were authorized for issuance
under our equity compensation plans. In the table below, we describe certain information about
these shares and the equity compensation plans which provide for their authorization and issuance.
You can find additional information about our stock grant and stock option plans beginning on page
F-35.
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(c) |
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|
Number of securities |
|
|
|
|
|
|
|
|
|
|
remaining available for |
|
|
|
|
|
|
|
|
|
|
future issuance under |
|
|
(a) |
|
(b) |
|
equity compensation |
|
|
Number of securities to |
|
Weighted-average |
|
plans (excluding |
|
|
be issued upon exercise |
|
exercise price of |
|
securities reflected in |
Plan category |
|
of outstanding options |
|
outstanding options |
|
column (a)) |
Equity compensation plans
approved by security holders |
|
|
615,000 |
(1) |
|
$ |
16.31 |
|
|
|
1,697,160 |
(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation plans not
approved by security holders |
|
|
124,000 |
(3) |
|
$ |
4.97 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
739,000 |
|
|
$ |
14.41 |
|
|
|
1,697,160 |
|
|
|
|
(1) |
|
Includes shares of common stock issuable upon exercise of stock options granted under our
1997 Nonemployee Directors Stock Option Plan, 1998 Stock Option Plan, 2001 Nonemployee
Directors Stock Option Plan and 2008 Long-Term Incentive Plan. |
|
(2) |
|
Of these shares, 69,808 shares of common stock are available for future issuance under our
2004 Non-Employee Director Stock Grant Plan and 1,627,352 shares of common stock are available
for future awards under our 2008 Long-Term Incentive Plan. |
|
(3) |
|
These shares represent shares of common stock underlying stock options granted on June 20,
2001 to non-officer employees under our 2001 Employee Stock Option Plan. The 2001 Employee
Stock Option Plan is the only equity compensation plan in effect that we have adopted without
approval of our stockholders. Our directors and officers are not eligible to participate in
this plan. A description of the material features of this plan can be found under the caption
2001 Employee Stock Option Plan on page F-36. |
(90)
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Certain Transactions
In December 2001, and prior to his employment with us in June 2002, Donald E. Tiffin, our
Chief Operating Officer, received from an unaffiliated third party a 3% working interest in our
Diamond M project in Scurry County, Texas for services rendered in connection with assembling the
project. In August 2002, shortly after his employment with us, and due to the personal financial
exposure associated with the ownership of the working interest and to prevent the interest from
being acquired by a third party, Mr. Tiffin assigned two-thirds of his ownership interest in the
project to us at no cost, leaving him with a 1% working interest. We acquired our initial interest
in the Diamond M Project from the same third party in December 2001, but did not become operator of
the project until March 1, 2003. As with other nonaffiliated interest owners, we invoice Mr. Tiffin
on a monthly basis, without interest, for his share of drilling, development and lease operating
expenses. During 2008, we billed Mr. Tiffin a total of approximately $95,000 for his proportionate
share of capital expenditures and lease operating expenses, and Mr. Tiffin paid us approximately
$89,000 for these drilling and development expenses, which included approximately $5,000
attributable to expenses billed to Mr. Tiffin in 2007. During 2008, we disbursed to Mr. Tiffin
approximately $116,000 in oil and natural gas revenues related to his interest in this project. The
largest aggregate amount outstanding and owed to us by Mr. Tiffin at any one time during 2008 was
approximately $22,000. At December 31, 2008, Mr. Tiffin owed us approximately $12,000.
We believe the transactions described above were made on terms no less favorable than if we
had entered into the transactions with an unrelated party.
Procedures for Reviewing Certain Transactions
We have adopted a written policy for the review, approval or ratification of related party
transactions. All of our officers, directors and employees are subject to this policy. Under this
policy, the Audit Committee reviews all related party transactions for potential conflicts of
interest situations. Generally, our policy defines a related party transaction as a transaction
in which we are a participant
and the amount involved exceeds $10,000, and in which a related party has an interest. A
related party is:
|
|
|
a director or officer of Parallel or a nominee to become a director; |
|
|
|
|
an owner of more than 5% of our outstanding common stock; |
|
|
|
|
certain family members of any of the above persons; and |
|
|
|
|
any entity in which any of the above persons is employed or is a partner or
principal or in which such person has a 5% or greater ownership interest. |
Approval Procedures
Before entering into a related party transaction, the related party or the department within
Parallel responsible for the potential transaction must notify the Audit Committee of the facts and
circumstances of the proposed transaction, including:
|
|
|
the related partys relationship to Parallel and interest in the
transaction; |
|
|
|
|
the material terms of the proposed transaction; |
|
|
|
|
the benefits to Parallel of the proposed transaction; |
(91)
|
|
|
the availability of other sources of comparable properties or services; and |
|
|
|
|
whether the proposed transaction is on terms comparable to terms available
to an unrelated third party or to employees generally. |
The Audit Committee will then consider all of the relevant facts and circumstances available
to it, including the matters described above and, if applicable, the impact on a Directors
independence. No member of the Audit Committee is permitted to participate in any review,
consideration or approval of any related party transaction if such member or any of his or her
immediate family members is the related party. After review, the Audit Committee may approve,
modify or disapprove the proposed transaction.
The Audit Committee will approve only those related
party transactions that are in, or are not inconsistent with, the best interests of Parallel and
its stockholders.
Ratification Procedures
If an officer or Director of Parallel becomes aware of a related party transaction that has
not been previously approved or ratified by the Audit Committee then, if the transaction is pending
or ongoing, the transaction must be submitted to the Audit Committee and the Audit Committee will
consider the matters described above. Based on the conclusions reached, the Audit Committee will
evaluate all options, including ratification, amendment or termination of the related party
transaction. If the transaction is completed, the Audit Committee will evaluate the transaction,
taking into account the same factors as described above, to determine if rescission of the
transaction or any disciplinary action is appropriate, and will request that we evaluate our
controls and procedures to determine the reason the transaction was not submitted to the Audit
Committee for prior approval and whether any changes to the procedures are recommended.
Director Independence
Under the Delaware General Corporation Law and our bylaws, our business, property and affairs
are managed by or under the direction of the Board of Directors. Members of the Board are kept
informed of our business through discussions with the Chairman of the Board, the Chief Executive
Officer and other officers, by reviewing materials provided to them and by participating in
meetings of the Board and its committees. In 2008, five individuals served as a Director of
Parallel throughout the
entire year. These individuals were Edward A. Nash, Larry C. Oldham, Martin B. Oring, Ray M.
Poage and Jeffrey G. Shrader.
The Board has determined that Messrs. Nash, Oring, Poage and Shrader meet the definition of an
independent director for purposes of NASD Rule 4200(a)(15), the independence standards applicable
to us. The Board based these determinations primarily on responses of the Directors to questions
regarding employment and compensation history, affiliations and family and other relationships,
comparisons of the independence criteria under NASD Rule 4200(a)(15) to the particular
circumstances of each Director and on discussions among the Directors.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The Audit Committee had not, as of the time of filing this Annual Report on Form 10-K with the
Securities and Exchange Commission, adopted policies and procedures for pre-approving audit or
permissible non-audit services performed by our independent auditors. Instead, the Audit Committee
as a whole pre-approves all such services. In the future, our Audit Committee may approve the
services of our independent auditors pursuant to pre-approval policies and procedures adopted by
the Audit Committee, provided the policies and procedures are detailed as to the particular
service, the Audit Committee is informed of each service, and such policies and procedures do not
include delegation of the Audit Committees responsibilities to our management.
(92)
The aggregate fees we paid or accrued for professional services rendered by our principal
accountants, BDO Seidman, LLP, for 2008 and 2007 were:
|
|
|
|
|
|
|
|
|
Types
of Fees |
|
2008 |
|
|
2007 |
|
|
|
($ in thousands) |
|
Audit fees |
|
$ |
571 |
|
|
$ |
736 |
|
Audit-related fees |
|
|
|
|
|
|
13 |
|
Tax fees |
|
|
|
|
|
|
|
|
All other fees |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
571 |
|
|
$ |
749 |
|
|
|
|
|
|
|
|
We retained an independent third party to assist us in our Sarbanes-Oxley 404 readiness and
assessment of internal control over financial reporting. The aggregate fees for services provided
in connection with the internal control over financial reporting for 2008 and 2007 were
approximately $92,000 and $75,000, respectively, including associated expenses.
In the above table, Audit fees are fees we paid for professional services for the audit of
our Consolidated Financial Statements included in our Annual Report on Form 10-K and for the review
of our Consolidated Financial Statements included in our Quarterly Reports on Form 10-Q, or for
services that are normally provided by our principal accountants in connection with statutory and
regulatory filings or engagements and fees for Sarbanes-Oxley 404 audit work. Audit-related fees
are fees billed for assurance and related regulatory filings.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as part of this report:
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
For a list of Consolidated Financial Statements and Schedules, see Index to the
Consolidated Financial Statements on page F-1, and incorporated herein by reference.
(a)(3) Exhibits
See Item 15(b) below.
(b) Exhibits
|
|
The exhibits to this Annual Report on Form 10-K required to be filed pursuant to Item 15(b)
are listed below and in the Index to Exhibits attached hereto. |
|
(c) |
|
No financial statement schedules are required to be filed as part of this Annual Report on
Form 10-K or they are inapplicable. |
|
|
|
No. |
|
Description of Exhibit |
|
3.1
|
|
Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form
10-Q of the Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
3.2
|
|
Bylaws of Registrant (Incorporated by reference to Exhibit 10.1 of the Registrants Current
Report on Form 8-K filed on November 30, 2007) |
|
|
|
(93)
|
|
|
No. |
|
Description of Exhibit |
|
|
|
3.3
|
|
Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of
the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.4
|
|
Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit
No. 3.4 of the Registrants Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.5
|
|
Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit
No. 3.5 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on
October 13, 2004) |
|
|
|
3.6
|
|
Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No.
3.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
4.1
|
|
Certificate of Designations, Preferences and Rights of Serial Preferred Stock 6%
Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the
Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
4.2
|
|
Certificate of Designations, Preferences and Rights of Series A Preferred Stock (Incorporated
by reference to Exhibit 4.2 of Form 10-K of the Registrant for the fiscal year ended December
31, 2000) |
|
|
|
4.3
|
|
Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust
Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the
Registrant filed with the Securities and Exchange Commission on October 10, 2000) |
|
|
|
4.4
|
|
Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No.
4.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.5
|
|
Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
4.6
|
|
Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
4.7
|
|
Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American
Stock Transfer, Inc. (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant
for the fiscal year ended December 31, 2006) |
|
|
|
4.8
|
|
First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant,
Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A. (Incorporated
by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December
31, 2006) |
|
|
|
4.9
|
|
Form of Rule 144A 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.2 to the
Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.10
|
|
Form of IAI 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.3 to the
Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.11
|
|
Form of Regulation S 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.4 to
the Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
(94)
|
|
|
No. |
|
Description of Exhibit |
|
|
|
4.12
|
|
Indenture, dated as of July 31, 2007, among the Registrant as Issuer and Wells Fargo Bank,
National Association as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrants
Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.13
|
|
Registration Rights Agreement, dated as of July 31, 2007, by and among the Registrant,
Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP
Paribas Securities Corp. (Incorporated by reference to Exhibit 10.2 to the Registrants
Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.14
|
|
Purchase Agreement, dated as of July 26, 2007, by and among the Registrant, Jefferies &
Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities
Corp. (Incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K
filed on August 1, 2007) |
|
4.15
|
|
Form of 101/4% Unrestricted Senior Note due 2014 (Incorporated by reference to Exhibit 4.13 of
Form S-4 of the Registrant, Registration No. 333-148465) |
|
|
|
|
|
Executive Compensation Plans and Arrangements (Exhibit No.s 10.1 through 10.11): |
|
|
|
10.1
|
|
1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2004) |
|
|
|
10.2
|
|
Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005) |
|
|
|
10.3
|
|
1998 Stock Option Plan (Incorporated by reference to Exhibit 10.4 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.4
|
|
2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of
the Registrants Form 10-Q Report for the fiscal quarter ended March 31, 2004) |
|
|
|
10.5
|
|
2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the
Registrants Form 8-K Report dated September 22, 2004) |
|
|
|
10.6
|
|
Incentive and Retention Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.7
|
|
2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrants
Form 8-K Report dated March 27, 2008) |
|
|
|
10.8
|
|
Form of Nonqualified Stock Option Agreement for nonqualified stock options granted under the
Registrants 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.2 of the
Registrants Current Report on Form 8-K filed on June 18, 2008) |
|
|
|
10.9
|
|
Form of Outside Director Stock Award Agreement for stock awards granted under the
Registrants 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Current Report on Form 8-K filed on June 18, 2008) |
|
|
|
10.10
|
|
Form of Outside Director Restricted Stock Agreement for restricted stock grants under the
Registrants 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.4 of the
Registrants Current Report on Form 8-K filed on June 18, 2008) |
|
|
|
10.11
|
|
Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference
to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004) |
|
|
|
(95)
|
|
|
No. |
|
Description of Exhibit |
|
|
|
10.12
|
|
ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank,
N.A. (Incorporated by reference to Exhibit 10.5 of the Registrants Form 8-K Report dated
October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005) |
|
|
|
10.13
|
|
Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas,
CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and
Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrants Form
8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on
December 30, 2005) |
|
|
|
10.14
|
|
Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum
Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference
to Exhibit No. 10.4 of the Registrants Form 8-K Report, dated November 15, 2005, as filed
with the Securities and Exchange Commission on November 21, 2005) |
|
10.15
|
|
Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas,
N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C.
(Incorporated by reference to Exhibit No. 10.5 of the Registrants Form 8-K Report, dated
November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005) |
|
|
|
10.16
|
|
Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of
Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.23 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.17
|
|
Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between
Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.24 of Form
10-K of the Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.18
|
|
Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by
Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated
by
reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended December
31, 2006) |
|
|
|
10.19
|
|
Third Amendment to Third Amended and Restated Credit Agreement, dated as of July 31, 2007,
among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank,
Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to
Exhibit 10.3 of the Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
10.20
|
|
Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of November 30,
2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank,
Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to
Exhibit 10.27 of Form S-4 of the Registrant, Registration No. 333-148465) |
|
|
|
10.21
|
|
Hagerman Gas Gathering System Joint Venture Agreement, dated as of January 16, 2007, among
the Registrant, Feagan Gathering Company and Capstone Oil and Gas Company, L.P. (Incorporated
by reference to Exhibit 10.28 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2007) |
|
|
|
10.22
|
|
Fourth Amended and Restated Credit Agreement, dated as of May 16, 2008, among the
Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank,
Bank of Scotland plc, and Texas Capital Bank, N.A. (Incorporated by reference to Exhibit 10.1
of the Registrants Current Report on Form 8-K filed on May 22, 2008) |
|
|
|
(96)
|
|
|
No. |
|
Description of Exhibit |
|
10.23
|
|
First Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 31,
2008, by and among Parallel Petroleum Corporation, Citibank, N.A., BNP Paribas, Western
National Bank, Compass Bank, Bank of Scotland plc, Texas Capital Bank, N.A., Bank of America,
N.A. and West Texas National Bank (Incorporated by reference to Exhibit 10.34 of the
Registrants Form 10-Q Report for the third fiscal quarter ended September 30, 2008) |
|
|
|
*10.24
|
|
Second Amendment to Fourth Amended
and Restated Credit Agreement, executed as of February 19,
2009, by and among Parallel Petroleum Corporation, Citibank, N.A., BNP Paribas, Western
National Bank, Compass Bank, Bank of Scotland plc, Texas Capital Bank, N.A., Bank of America,
N.A. and West Texas National Bank |
|
|
|
14
|
|
Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
|
|
|
*23.1
|
|
Consent of BDO Seidman, LLP |
|
|
|
*23.2
|
|
Consent of Cawley, Gillespie & Associates Inc. Independent Petroleum Engineers |
|
|
|
*31.1
|
|
Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of
the Sarbanes Oxley Act of 2002. |
|
|
|
*31.2
|
|
Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of
the Sarbanes Oxley Act of 2002. |
|
|
|
**32.1
|
|
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes Oxley Act of 2002. |
|
|
|
**32.2
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes Oxley Act of 2002. |
|
|
|
* |
|
Filed herewith. |
|
** |
|
Furnished herewith. |
(97)
PARALLEL PETROLEUM CORPORATION
Index to the Consolidated Financial Statements
|
|
|
|
|
|
|
Page |
|
|
|
|
F-2 |
|
|
Financial Statements: |
|
|
|
|
|
|
|
|
F-3 |
|
|
|
|
F-5 |
|
|
|
|
F-6 |
|
|
|
|
F-7 |
|
|
|
|
F-9 |
|
|
|
|
F-10 |
|
All schedules are omitted, as the required information is inapplicable or the information is
presented in the Consolidated Financial Statements or related notes.
F-1
Report of Independent Registered Public Accounting Firm
Board of Directors
Parallel Petroleum Corporation
Midland, Texas
We have audited the accompanying consolidated balance sheets of Parallel Petroleum Corporation as
of December 31, 2008 and 2007 and the related consolidated statements of operations, comprehensive
income (loss), stockholders equity, and cash flows for each of the three years in the period ended
December 31, 2008. These financial statements are the responsibility of the Companys management.
Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards 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, as well as evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of Parallel Petroleum Corporation at December 31, 2008
and 2007, and the results of its operations and its cash flows for each of the three years in the
period ended December 31, 2008 in conformity with accounting principles generally accepted in the
United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), Parallel Petroleum Corporations internal control over financial reporting
as of December 31, 2008, based on criteria established in Internal Control Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our
report dated February 23, 2009 expressed an unqualified opinion thereon.
BDO Seidman, LLP
Houston, Texas
February
23, 2009
F-2
PARALLEL PETROLEUM CORPORATION
Consolidated Balance Sheets
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
Assets |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
36,303 |
|
|
$ |
7,816 |
|
Short-term investments |
|
|
5,002 |
|
|
|
|
|
|
Accounts receivable: |
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
|
13,399 |
|
|
|
20,499 |
|
Joint interest owners and other, net of allowance for doubtful accounts of $50 |
|
|
2,805 |
|
|
|
2,460 |
|
Affiliates and joint ventures |
|
|
12 |
|
|
|
3,970 |
|
|
|
|
|
|
|
|
|
|
|
16,216 |
|
|
|
26,929 |
|
Other current assets |
|
|
430 |
|
|
|
449 |
|
Derivatives |
|
|
22,665 |
|
|
|
151 |
|
Deferred tax asset |
|
|
|
|
|
|
10,293 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
80,616 |
|
|
|
45,638 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, at cost: |
|
|
|
|
|
|
|
|
Oil and
natural gas properties, full cost method (including $137,202 and
$86,402 not subject to depletion) |
|
|
878,722 |
|
|
|
648,576 |
|
Other |
|
|
3,172 |
|
|
|
2,877 |
|
|
|
|
|
|
|
|
|
|
|
881,894 |
|
|
|
651,453 |
|
Less accumulated depreciation, depletion and amortization |
|
|
(490,566 |
) |
|
|
(145,482 |
) |
|
|
|
|
|
|
|
Net property and equipment |
|
|
391,328 |
|
|
|
505,971 |
|
|
|
|
|
|
|
|
|
|
Restricted cash |
|
|
81 |
|
|
|
78 |
|
Investment in pipelines and gathering system ventures |
|
|
337 |
|
|
|
8,638 |
|
Other assets, net of accumulated amortization of $1,443 and $1,193 |
|
|
3,566 |
|
|
|
2,768 |
|
Deferred tax asset |
|
|
60,567 |
|
|
|
|
|
Derivatives |
|
|
14,081 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
550,576 |
|
|
$ |
563,093 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these Consolidated Financial Statements.
F-3
PARALLEL PETROLEUM CORPORATION
Consolidated Balance Sheets (continued)
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
Liabilities and Stockholders Equity |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable trade |
|
$ |
13,560 |
|
|
$ |
12,264 |
|
Accrued liabilities |
|
|
21,742 |
|
|
|
29,135 |
|
Accrued interest on senior notes |
|
|
6,407 |
|
|
|
6,449 |
|
Asset retirement obligations |
|
|
158 |
|
|
|
598 |
|
Derivative obligations |
|
|
3,004 |
|
|
|
30,424 |
|
Put premium obligations |
|
|
628 |
|
|
|
|
|
Deferred tax liability |
|
|
6,597 |
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
52,096 |
|
|
|
78,870 |
|
|
|
|
|
|
|
|
|
Revolving credit facility |
|
|
225,000 |
|
|
|
60,000 |
|
Senior notes (principal amount $150,000) |
|
|
145,890 |
|
|
|
145,383 |
|
Asset retirement obligations |
|
|
11,221 |
|
|
|
4,339 |
|
Derivative obligations |
|
|
5,136 |
|
|
|
13,194 |
|
Put premium obligations |
|
|
3,655 |
|
|
|
|
|
Deferred tax liability |
|
|
|
|
|
|
26,045 |
|
Termination obligation |
|
|
532 |
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term liabilities |
|
|
391,434 |
|
|
|
248,961 |
|
|
|
|
|
|
|
|
Commitments and contingencies |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Series A preferred stock par value $0.10 per share, authorized 50,000 shares |
|
|
|
|
|
|
|
|
Common stock par value $0.01 per share, authorized 60,000,000 shares,
issued and outstanding 41,597,161 and 41,252,644 |
|
|
415 |
|
|
|
412 |
|
Additional paid-in capital |
|
|
200,132 |
|
|
|
196,457 |
|
Retained earnings (deficit) |
|
|
(93,501 |
) |
|
|
38,393 |
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
107,046 |
|
|
|
235,262 |
|
|
|
|
|
|
|
|
|
|
$ |
550,576 |
|
|
$ |
563,093 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these Consolidated Financial Statements.
F-4
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Operations
($ in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
Oil and natural gas revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
$ |
182,515 |
|
|
$ |
116,031 |
|
|
$ |
97,025 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense |
|
|
28,454 |
|
|
|
22,200 |
|
|
|
16,819 |
|
Production taxes |
|
|
9,135 |
|
|
|
5,545 |
|
|
|
5,577 |
|
Production tax refund |
|
|
(1,958 |
) |
|
|
(1,209 |
) |
|
|
|
|
General and administrative |
|
|
11,907 |
|
|
|
10,415 |
|
|
|
9,523 |
|
Depreciation, depletion and amortization |
|
|
44,691 |
|
|
|
30,115 |
|
|
|
24,687 |
|
Impairment of oil and natural gas properties |
|
|
300,532 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
392,761 |
|
|
|
67,066 |
|
|
|
56,606 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(210,246 |
) |
|
|
48,965 |
|
|
|
40,419 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense), net: |
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges |
|
|
32,018 |
|
|
|
(36,776 |
) |
|
|
2,802 |
|
Gain on ineffective portion of hedges |
|
|
|
|
|
|
|
|
|
|
626 |
|
Interest and other income |
|
|
278 |
|
|
|
197 |
|
|
|
158 |
|
Interest expense, net of capitalized interest |
|
|
(23,750 |
) |
|
|
(19,177 |
) |
|
|
(12,360 |
) |
Cost of debt retirement |
|
|
(286 |
) |
|
|
(760 |
) |
|
|
|
|
Other expense |
|
|
(12 |
) |
|
|
(118 |
) |
|
|
(189 |
) |
Equity in gain (loss) of pipelines and gathering system ventures |
|
|
380 |
|
|
|
(311 |
) |
|
|
8,593 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense), net |
|
|
8,628 |
|
|
|
(56,945 |
) |
|
|
(370 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
(201,618 |
) |
|
|
(7,980 |
) |
|
|
40,049 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax benefit (expense) |
|
|
69,724 |
|
|
|
3,319 |
|
|
|
(13,894 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(131,894 |
) |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(3.18 |
) |
|
$ |
(0.12 |
) |
|
$ |
0.73 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(3.18 |
) |
|
$ |
(0.12 |
) |
|
$ |
0.71 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these Consolidated Financial Statements.
F-5
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Stockholders Equity
Years ended December 31, 2008, 2007 and 2006
(amounts in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
Common stock |
|
|
Additional |
|
|
Retained |
|
|
Other |
|
|
Total |
|
|
|
Number of |
|
|
|
|
|
|
paid-in |
|
|
earnings |
|
|
Comprehensive |
|
|
stockholders |
|
|
|
shares |
|
|
Amount |
|
|
capital |
|
|
(deficit) |
|
|
Loss |
|
|
equity |
|
Balance,
January 1, 2006 |
|
|
34,749 |
|
|
$ |
347 |
|
|
$ |
78,699 |
|
|
$ |
16,899 |
|
|
$ |
(6,443 |
) |
|
$ |
89,502 |
|
Common stock issued, net of transaction costs |
|
|
2,500 |
|
|
|
25 |
|
|
|
60,242 |
|
|
|
|
|
|
|
|
|
|
|
60,267 |
|
Common stock issued for services |
|
|
5 |
|
|
|
|
|
|
|
118 |
|
|
|
|
|
|
|
|
|
|
|
118 |
|
Cashless exercise of warrants |
|
|
117 |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Options exercised |
|
|
176 |
|
|
|
2 |
|
|
|
764 |
|
|
|
|
|
|
|
|
|
|
|
766 |
|
Stock option expense |
|
|
|
|
|
|
|
|
|
|
531 |
|
|
|
|
|
|
|
|
|
|
|
531 |
|
Changes in fair value of cash flow hedges, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,443 |
|
|
|
6,443 |
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,155 |
|
|
|
|
|
|
|
26,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
January 1, 2007 |
|
|
37,547 |
|
|
|
375 |
|
|
|
140,353 |
|
|
|
43,054 |
|
|
|
|
|
|
|
183,782 |
|
Common stock issued, net of transaction costs |
|
|
3,000 |
|
|
|
30 |
|
|
|
52,492 |
|
|
|
|
|
|
|
|
|
|
|
52,522 |
|
Common stock issued for services |
|
|
4 |
|
|
|
|
|
|
|
96 |
|
|
|
|
|
|
|
|
|
|
|
96 |
|
Cashless exercise of warrants |
|
|
83 |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Options exercised |
|
|
619 |
|
|
|
6 |
|
|
|
2,454 |
|
|
|
|
|
|
|
|
|
|
|
2,460 |
|
Stock option expense |
|
|
|
|
|
|
|
|
|
|
247 |
|
|
|
|
|
|
|
|
|
|
|
247 |
|
Tax benefit of stock option exercise
in excess of compensation |
|
|
|
|
|
|
|
|
|
|
816 |
|
|
|
|
|
|
|
|
|
|
|
816 |
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,661 |
) |
|
|
|
|
|
|
(4,661 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
January 1, 2008 |
|
|
41,253 |
|
|
|
412 |
|
|
|
196,457 |
|
|
|
38,393 |
|
|
|
|
|
|
|
235,262 |
|
Common stock issued for services |
|
|
22 |
|
|
|
|
|
|
|
358 |
|
|
|
|
|
|
|
|
|
|
|
358 |
|
Options exercised |
|
|
174 |
|
|
|
2 |
|
|
|
733 |
|
|
|
|
|
|
|
|
|
|
|
735 |
|
Warrants exercised, net of transaction costs |
|
|
148 |
|
|
|
1 |
|
|
|
795 |
|
|
|
|
|
|
|
|
|
|
|
796 |
|
Reduction in estimated stock offering costs |
|
|
|
|
|
|
|
|
|
|
468 |
|
|
|
|
|
|
|
|
|
|
|
468 |
|
Stock option expense |
|
|
|
|
|
|
|
|
|
|
1,321 |
|
|
|
|
|
|
|
|
|
|
|
1,321 |
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(131,894 |
) |
|
|
|
|
|
|
(131,894 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance,
December 31, 2008 |
|
|
41,597 |
|
|
$ |
415 |
|
|
$ |
200,132 |
|
|
$ |
(93,501 |
) |
|
$ |
|
|
|
$ |
107,046 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these Consolidated Financial Statements.
F-6
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Cash Flows
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(131,894 |
) |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
Adjustments to reconcile net income (loss) to net cash
provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
44,691 |
|
|
|
30,115 |
|
|
|
24,687 |
|
Impairment of oil and natural gas properties |
|
|
300,532 |
|
|
|
|
|
|
|
|
|
Gain on sale of automobiles |
|
|
|
|
|
|
(30 |
) |
|
|
|
|
Accretion of asset retirement obligation |
|
|
401 |
|
|
|
324 |
|
|
|
248 |
|
Accretion of senior notes discount |
|
|
507 |
|
|
|
197 |
|
|
|
|
|
Deferred income tax (benefit) expense |
|
|
(69,724 |
) |
|
|
(3,319 |
) |
|
|
13,894 |
|
(Gain) loss on derivatives not classified as hedges |
|
|
(32,018 |
) |
|
|
36,776 |
|
|
|
(2,802 |
) |
(Gain) loss on ineffective portion of hedges |
|
|
|
|
|
|
|
|
|
|
(626 |
) |
Amortization of deferred financing costs |
|
|
567 |
|
|
|
493 |
|
|
|
492 |
|
Cost of debt retirement |
|
|
286 |
|
|
|
760 |
|
|
|
|
|
Accretion of interest on put obligations |
|
|
97 |
|
|
|
|
|
|
|
|
|
Common stock issued in lieu of cash for directors fees |
|
|
358 |
|
|
|
96 |
|
|
|
118 |
|
Stock option expense |
|
|
1,321 |
|
|
|
247 |
|
|
|
531 |
|
Equity in (gain) loss in pipelines and gathering system ventures |
|
|
(380 |
) |
|
|
311 |
|
|
|
(8,593 |
) |
Return on investment in pipelines and gathering system ventures |
|
|
|
|
|
|
287 |
|
|
|
9,000 |
|
Bad debt expense |
|
|
|
|
|
|
(30 |
) |
|
|
71 |
|
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Other assets, net |
|
|
(861 |
) |
|
|
(114 |
) |
|
|
1,075 |
|
Restricted cash |
|
|
(3 |
) |
|
|
247 |
|
|
|
(50 |
) |
Accounts receivable |
|
|
10,713 |
|
|
|
2,253 |
|
|
|
(15,151 |
) |
Other current assets |
|
|
19 |
|
|
|
1,070 |
|
|
|
(153 |
) |
Accounts payable and accrued liabilities |
|
|
(3,571 |
) |
|
|
9,097 |
|
|
|
19,290 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
121,041 |
|
|
|
74,119 |
|
|
|
68,186 |
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties |
|
|
(217,393 |
) |
|
|
(146,798 |
) |
|
|
(189,396 |
) |
Use of restricted cash for acquisition of oil and natural gas properties |
|
|
|
|
|
|
|
|
|
|
2,366 |
|
Proceeds
from disposition of oil and natural gas properties and other property and equipment |
|
|
427 |
|
|
|
1,677 |
|
|
|
130 |
|
Additions to other property and equipment |
|
|
(434 |
) |
|
|
(379 |
) |
|
|
(210 |
) |
Settlements of derivative instruments |
|
|
(35,869 |
) |
|
|
(16,615 |
) |
|
|
(3,902 |
) |
Short-term investments |
|
|
(5,002 |
) |
|
|
|
|
|
|
|
|
Net investment in pipelines and gathering system ventures |
|
|
(26 |
) |
|
|
(2,782 |
) |
|
|
(11,260 |
) |
Return of investment in pipelines and gathering system ventures |
|
|
|
|
|
|
|
|
|
|
7,724 |
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(258,297 |
) |
|
|
(164,897 |
) |
|
|
(194,548 |
) |
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these Consolidated Financial Statements.
F-7
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Cash Flows (Continued)
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings from bank line of credit |
|
|
165,000 |
|
|
|
92,000 |
|
|
|
117,000 |
|
Payments on bank line of credit |
|
|
|
|
|
|
(147,000 |
) |
|
|
(52,000 |
) |
Payment on term loan |
|
|
|
|
|
|
(50,000 |
) |
|
|
|
|
Senior notes (principal amount $150,000 in 2008 and 2007) |
|
|
|
|
|
|
145,186 |
|
|
|
|
|
Deferred financing costs |
|
|
(788 |
) |
|
|
(813 |
) |
|
|
(179 |
) |
Deferred debt offering |
|
|
|
|
|
|
(1,671 |
) |
|
|
|
|
Proceeds from exercise of stock options and warrants |
|
|
1,531 |
|
|
|
2,460 |
|
|
|
766 |
|
Proceeds (net) from common stock issued |
|
|
|
|
|
|
52,522 |
|
|
|
60,267 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
165,743 |
|
|
|
92,684 |
|
|
|
125,854 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
28,487 |
|
|
|
1,906 |
|
|
|
(508 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
|
7,816 |
|
|
|
5,910 |
|
|
|
6,418 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year |
|
$ |
36,303 |
|
|
$ |
7,816 |
|
|
$ |
5,910 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash financing and investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred purchase of derivative puts |
|
$ |
4,186 |
|
|
$ |
|
|
|
$ |
|
|
Oil and natural gas properties asset retirement obligation |
|
$ |
6,041 |
|
|
$ |
(450 |
) |
|
$ |
2,320 |
|
Additions to oil and natural gas properties accrued |
|
$ |
(2,100 |
) |
|
$ |
2,500 |
|
|
$ |
6,000 |
|
Termination obligation capitalized to oil and natural gas
properties |
|
$ |
532 |
|
|
$ |
|
|
|
$ |
|
|
Transfer to oil and natural gas properties |
|
$ |
8,707 |
|
|
$ |
|
|
|
$ |
|
|
Transfer from equity investment |
|
$ |
(8,707 |
) |
|
$ |
|
|
|
$ |
|
|
Non-cash exchange of oil and natural gas properties: |
|
|
|
|
|
|
|
|
|
|
|
|
Properties received in exchange |
|
$ |
|
|
|
$ |
6,463 |
|
|
$ |
|
|
Properties delivered in exchange |
|
$ |
|
|
|
$ |
(5,495 |
) |
|
$ |
|
|
Other transactions: |
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid |
|
$ |
22,609 |
|
|
$ |
13,096 |
|
|
$ |
12,255 |
|
Taxes paid |
|
$ |
40 |
|
|
$ |
|
|
|
$ |
40 |
|
The accompanying notes are an integral part of these Consolidated Financial Statements.
F-8
PARALLEL PETROLEUM CORPORATION
Consolidated Statements of Comprehensive Income (Loss)
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
Net income (loss) |
|
$ |
(131,894 |
) |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized losses on derivatives |
|
|
|
|
|
|
|
|
|
|
(1,648 |
) |
Reclassification adjustment for losses
on derivatives included in net income (loss) |
|
|
|
|
|
|
|
|
|
|
11,409 |
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of derivatives |
|
|
|
|
|
|
|
|
|
|
9,761 |
|
Income tax expense, deferred |
|
|
|
|
|
|
|
|
|
|
(3,318 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income |
|
|
|
|
|
|
|
|
|
|
6,443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income (loss) |
|
$ |
(131,894 |
) |
|
$ |
(4,661 |
) |
|
$ |
32,598 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these Consolidated Financial Statements.
F-9
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization, Business and Summary of Significant Accounting Policies
Organization and Business
|
(a) |
|
Nature of Operations |
|
|
|
|
The Companys focus is on the acquisition, development and exploitation of long-lived
oil and natural gas reserves and, to a lesser extent, exploration for new oil and
natural gas reserves. The Companys business activities are currently carried out
primarily in Texas and New Mexico. The Companys activities are focused in the Permian
Basin of west Texas and New Mexico, the Fort Worth Basin of north Texas and the onshore
Gulf Coast area of south Texas. |
|
|
(b) |
|
Concentration of Credit Risk |
|
|
|
|
The Companys cash and short term investments are subject to credit risk through our
exposure with the financial institutions which hold these assets. The Company had
approximately $36.3 million in cash and cash equivalents as of December 31, 2008. The
Company maintains its cash in bank deposit and brokerage accounts which, at times, may
exceed federally insured limits. As of December 31, 2008, the Company had deposits in
excess of the FDIC and SIPC limits in the amount of $26.7 million. In addition, the
Company had short-term investments in United States Treasury bills of $5.0 million. |
|
|
|
|
The Company is also exposed to credit risk from its unsecured accounts receivable from
working interest owners and crude oil and natural gas purchasers. The activities and
payment patterns of these owners and purchasers are monitored by the Company. |
|
|
|
|
The Company has entered into various derivative contracts with financial institutions.
These contracts are intended to reduce the Companys exposure to commodity price and
interest rate fluctuations. The risk of nonperformance by the Companys counterparties
is mitigated by the fact that such counterparties (or their affiliates) are also bank
lenders under the Companys Revolving Credit Agreement and the derivative instruments
with these counterparties allow the Company to setoff amounts owed by the counterparty
against any obligation of the Company owed to the counterparty under the Companys
Revolving Credit Agreement. |
|
|
|
|
The Company manages the credit risk associated with its largest customers by using a
credit risk monitoring tool to actively monitor credit ratings, including S&P and
Moodys, financial statement filings, financial position, bankruptcy filings and current
news. Additionally, the Company actively monitors the information discussed above for
some competitors, oil service companies, banks and other financial institutions that the
Company does business with to help minimize its exposure to overall business risk and,
in some cases, counterparty risk. |
Significant Accounting Policies
|
(c) |
|
Basis of Consolidation |
|
|
|
|
The accompanying financial statements present the consolidated accounts of Parallel
Petroleum Corporation, a Delaware Corporation, and its wholly owned subsidiaries,
Parallel L.P. and Parallel, L.L.C. (collectively the Company or Parallel) prior to
their dissolution
and merger into Parallel on July 2, 2007. All significant inter-company account balances
and transactions have been eliminated. |
F-10
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
The Company accounts for its interests in oil and natural gas joint ventures and working
interests using the proportionate consolidation method. Under this method, the Company
records its proportionate share of assets, liabilities, revenues and expenses. |
|
|
(d) |
|
Property and Equipment |
|
|
|
|
Oil and natural gas properties: |
|
|
|
|
The Company uses the full cost method of accounting for its oil and natural gas
producing activities. Accordingly, all costs associated with acquisition, exploration,
and development of oil and natural gas reserves, including directly related overhead
costs, are capitalized. |
|
|
|
|
Under full cost accounting rules, capitalized costs, less accumulated amortization and
related deferred income taxes, shall not exceed an amount (the ceiling) equal to the sum
of: (i) the after tax present value of estimated future net revenues computed by
applying current prices of oil and gas reserves to estimated future production of proved
oil and gas reserves as of the date of the latest balance sheet presented, less
estimated future expenditures (based on current costs) to be incurred in developing and
producing the proved reserves computed using a discount factor of ten percent and
assuming continuation of existing economic conditions; (ii) the cost of properties not
being amortized; and (iii) the lower of cost or estimated fair value of unproven
properties included in the costs being amortized. If unamortized costs capitalized
within a cost center, less related deferred income taxes, exceed the ceiling, the excess
shall be charged to expense and separately disclosed during the period in which the
excess occurs. Amounts thus required to be written off shall not be reinstated for any
subsequent increase in the cost center ceiling. Under rules and regulations of the
Securities and Exchange Commission, the excess above the ceiling may be limited or
eliminated if, subsequent to the end of the quarter or year but prior to the release of
the financial results, prices have increased sufficiently that such excess above the
ceiling would not have existed if the increased prices were used in the calculations. |
|
|
|
|
Management and service fees received under contractual arrangements, if any, are treated
as reimbursement of costs, offsetting the costs incurred to provide those services.
Specifically, the Company serves as operator of certain oil and natural gas properties
in which it owns an interest. Under operating agreements naming the Company as operator,
the Company is reimbursed for certain specified direct charges and overhead charges.
Amounts received in reimbursement for drilling activities are applied as a reduction to
Parallels capital costs, and amounts received in reimbursement for producing activities
are applied to reduce the Companys general and administrative expenses. |
|
|
|
|
Depletion is provided using the unit-of-production method based upon estimates of proved
oil and natural gas reserves with oil and natural gas production being converted to a
common unit of measure based upon their relative energy content. Investments in unproved
properties and major development projects are not amortized until proved reserves
associated with the projects can be determined or until impairment occurs. If the
results of an assessment indicate that the properties are impaired, the amount of the
impairment is added to the capitalized costs to be amortized. Once the assessment of
unproved properties is complete and when major development projects are evaluated, the
costs previously excluded from amortization are transferred to the full cost pool and
amortization begins. The amortizable base includes estimated future development costs
and where significant, dismantlement, restoration and abandonment costs, net of
estimated salvage value. |
|
|
|
|
In arriving at rates under the unit-of-production method, the quantities of recoverable
oil and natural gas reserves are established based on estimates made by the Companys
geologists |
F-11
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
and engineers which require significant judgment as does the projection of
future production volumes and levels of future costs, including future development
costs. In addition, considerable judgment is necessary in determining when unproved
properties become impaired and in determining the existence of proved reserves once a
well has been drilled. All of these judgments may have significant impact on the
calculation of depletion expense. There have been no material changes in the methodology
used by the Company in calculating depletion of oil and gas properties under the full
cost method during the three years ended December 31, 2008. |
|
|
|
|
Sales of proved and unproved properties are accounted for as adjustments of capitalized
costs with no gain or loss recognized, unless such adjustments would significantly alter
the relationship between capitalized costs and proved oil and natural gas reserves, in
which case the gain or loss would be recognized in the statement of operations. |
|
|
|
|
Other Property and Equipment: |
|
|
|
|
Maintenance and repairs are charged to operations. Renewals and betterments are
capitalized to the appropriate property and equipment accounts. |
|
|
|
|
Upon retirement or disposition of assets other than oil and natural gas properties, the
cost and related accumulated depreciation are removed from the accounts with the
resulting gains or losses, if any, recognized in the statement of operations.
Depreciation of other property and equipment is computed using the straight-line method
based on the estimated useful lives of the property and equipment. |
|
|
(e) |
|
Asset Retirement Obligations |
|
|
|
|
On January 1, 2003, the Company adopted Statement of Financial Accounting Standards SFAS
No. 143, Accounting for Asset Retirement Obligations (SFAS 143). SFAS 143 required
companies to recognize a liability for the present value of all legal obligations
associated with the retirement of tangible long-lived assets and to capitalize an equal
amount as part of the cost of the related oil and natural gas properties. The Company
recognizes the legal obligation of the dismantlement, restoration and abandonment costs
associated with its oil and natural gas properties with its asset retirement obligation.
These costs are impacted by our estimate of remaining lives as well as current market
conditions associated with these costs. Accretion expense is recognized as a component
of lease operating expense. |
|
|
(f) |
|
Income Taxes |
|
|
|
|
The Company accounts for income taxes based upon Statement of Financial Accounting
Standards No. 109, Accounting for Income Taxes (SFAS 109). |
|
|
|
|
Under SFAS 109, the Company accounts for income taxes using the liability method. Under
the liability method, deferred tax assets and liabilities are recognized for the future
tax consequences attributable to differences between financial statement carrying
amounts of existing assets and liabilities and their respective tax bases. Deferred tax
assets and liabilities are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected to be recovered or
settled. Under the liability method, the effect on previously recorded deferred tax
assets and liabilities resulting from a change in tax rates is recognized in earnings in
the period in which the change is enacted. |
|
|
|
|
The Company adopted the provisions of Financial Accounting Standards Board (FASB)
Interpretation No. 48, Accounting for Uncertainty in Income Taxes-an interpretation of
FASB Statement No. 109 (FIN 48), on January 1, 2007. FIN 48 clarifies the accounting
for |
F-12
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
uncertainty in income taxes recognized in an enterprises financial statements in
accordance with SFAS 109 and prescribes a recognition threshold and measurement process
for financial statement recognition and measurement of a tax position taken or expected
to be taken in a tax return. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods, disclosure and
transition. |
|
|
|
|
Interest recorded, if any, will be charged to interest expense, and penalties recorded
will be charged to other expense in the Companys statement of operations. |
|
|
(g) |
|
Equity Investments |
|
|
|
|
Investments in affiliated companies with a 20% to 50% ownership interest were accounted
for under the equity method and, accordingly, net income included the Companys
proportionate share of its income or loss. In addition, the Company had an investment
in a joint venture which was accounted for by the equity method because the Company did
not have effective control or voting interest although the Company had owned
approximately 76 1/2% of the joint venture economic interest. See
Note 10 - Investment in
Gas Gathering Systems. |
|
|
(h) |
|
Deferred financing costs |
|
|
|
|
Costs associated with obtaining financing under long-term debt under revolving credit
facilities and senior notes are deferred and expensed over the term of the applicable
long-term debt facility or the term of the notes. |
|
|
(i) |
|
Stock-Based Compensation |
|
|
|
|
Parallel accounts for stock based compensation in accordance with the SFAS No. 123
(revised 2004), Share-Based Payment,( SFAS 123(R)). Parallel adopted SFAS 123(R)
effective January 1, 2006, applying the modified prospective method, whereby
compensation cost associated with the unvested portion of awards granted during the
period of June 2001 to December 2002 was recognized over the remaining vesting period.
Under this method, prior periods were not revised for comparative purposes. |
|
|
(j) |
|
Environmental Expenditures |
|
|
|
|
The Company is subject to extensive federal, state and local environmental laws and
regulations. These laws regulate the discharge of materials into the environment and may
require the Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites. Environmental expenditures
are expensed or capitalized depending on their future economic benefit. Expenditures
that relate to an existing condition caused by past operations and that have no future
economic benefits are expensed. |
|
|
|
|
Liabilities for expenditures of a noncapital nature are recorded when environmental
assessment and or remediation is probable, and the costs can be reasonably estimated.
Such liabilities are generally undiscounted unless the timing of cash payments for the
liability or component is fixed or reliably determinable. |
|
|
(k) |
|
Earnings Per Share |
|
|
|
|
Basic earnings per share excludes any dilutive effects of options, warrants and
convertible securities and is computed by dividing income available to common
stockholders by the weighted average number of common shares outstanding for the period.
Diluted earnings per |
F-13
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
share is computed similar to basic earnings per share; however,
diluted earnings per share reflects the assumed conversion of all potentially dilutive
securities. |
|
|
|
|
The Company uses the treasury stock method described in SFAS
No. 128, Earnings per
Share, (SFAS 128) to calculate the dilutive effect of stock options, stock warrants,
convertible debentures and non-vested restricted stock. This method requires that the
Company compute the presumed proceeds from the exercise of options and other dilutive
instruments, including the expected tax benefit to us and assumes that we used the net
proceeds to purchase shares of our common stock at the average price during the period.
These assumed net shares issued are then included in the calculation of the diluted
weighted average shares outstanding for the period, if the effect is dilutive. |
|
|
(l) |
|
Use of Estimates in the Preparation of Consolidated Financial Statements |
|
|
|
|
The preparation of the accompanying Consolidated Financial Statements in conformity with
accounting principles generally accepted in the United States of America requires
management to make estimates and assumptions. These estimates and assumptions affect
the reported amounts of assets and liabilities, disclosure of contingent assets and
liabilities at the date of the balance sheet and the amounts of revenues and expenses
recognized during the reporting period. The Company analyzes its estimates based on
historical experience and various other assumptions that we believe to be reasonable
under the circumstances. However, actual results could differ from such estimates. |
|
|
|
|
Significant estimates include volumes of oil and natural gas reserves, abandonment
obligations, impairment of oil and natural gas properties, income taxes, bad debts,
derivatives, contingencies and litigation. |
|
|
|
|
Oil and natural gas reserve estimates, which are the basis for unit-of-production
depletion and the ceiling test, have number our inherent uncertainties. The accuracy of
any reserve estimate is a function of the quality of available data and of engineering
and geological interpretation and judgment. Results of drilling, testing, and
production subsequent to the date of the estimate may justify revision of such estimate.
Accordingly, reserve estimates are often different from the quantities of oil and
natural gas that are ultimately recovered. In addition, reserve estimates are
vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have
been volatile in the past and can be expected to be volatile in the future. |
|
|
(m) |
|
Cash Equivalents |
|
|
|
|
For purposes of the statements of cash flows, the Company considers all demand deposits,
money market accounts and certificates of deposit purchased with an original maturity of
three months or less to be cash equivalents. |
|
|
(n) |
|
Restricted Cash |
|
|
|
|
Cash that is restricted as to withdrawal, such as certificates of deposit, would not be
included with cash because of the time restrictions. Also, cash must be available for
current use in order to be classified as a current asset. Cash that is restricted in
use would not be included in current assets unless its restrictions will expire with the
operating cycle. Cash restricted for a noncurrent use, such as cash designated for the
purchase of property or equipment would be recorded as a noncurrent asset. |
F-14
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
(o) |
|
Short-Term Investments |
|
|
|
|
Short-term investments represent certificates of deposit and U.S. government securities
with maturities of less than twelve months. Each of the investments are carried at
amortized cost as management has the intention and ability to hold these to maturity. |
|
|
(p) |
|
Allowance for Doubtful Accounts |
|
|
|
|
The Company maintains an allowance for doubtful accounts for estimated losses resulting
from the inability of some of its customers to make required payments. These estimated
allowances are periodically reviewed, on a case by case basis, analyzing the customers
payment history and information regarding customers creditworthiness known to the
Company. In addition, the Company records a reserve based on the size and age of all
receivable balances against which the Company does not have specific reserves. If the
financial condition of its customers was to deteriorate, resulting in their inability to
make payments, additional allowances may be required. |
|
|
(q) |
|
Reclassifications |
|
|
|
|
Certain reclassifications have been made to prior years amounts to conform with current
year presentation. |
|
|
(r) |
|
Derivative Financial Instruments |
|
|
|
|
Derivative financial instruments, utilized to manage or reduce commodity price risk
related to the Companys production and interest rate risk related to the Companys
long-term debt are accounted for under the provisions of SFAS No. 133, Accounting for
Derivative Instruments and for Hedging Activities", and related interpretations and
amendments. Under this Statement, derivatives are carried on the balance sheet at fair
value. If the derivative is designated as a fair value hedge, the changes in the fair
value of the derivative and of the hedged item attributable to the hedged risk are
recognized in earnings. If the derivative is designated as a cash flow hedge, the
effective portions of changes in the fair value of the derivative are recorded in other
comprehensive income (OCI) and are recognized in oil and natural gas sales for
commodity trades and in interest expense for interest rate swaps when the hedged item
affects earnings. Ineffective portions of changes in the fair value of cash flow hedges
are also recognized in other expense. If the derivative is not designated as a hedge,
changes in the fair value are recognized in other income (expense). |
|
|
(s) |
|
Revenue Recognition |
|
|
|
|
Oil and natural gas revenues are recorded using the sales method, whereby the Company
recognizes oil and natural gas revenue based on the amount of oil and natural gas sold
to purchasers. For the period ended December 31, 2008, 2007 and 2006, the Company did
not have any significant oil or natural gas imbalances. The Company does not recognize
revenues until they are realized or realizable and earned. Revenues are considered
realized or realizable and earned when: (i) persuasive evidence of an arrangement
exists; (ii) delivery has occurred or services have been rendered; (iii) the sellers
price to the buyer is fixed or determinable; and, (iv) collectibility is reasonably
assured. |
F-15
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
The following summarizes revenue for each of the three years ended December 31 by
product sold. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
Oil revenue |
|
$ |
97,799 |
|
|
$ |
69,315 |
|
|
$ |
68,076 |
|
Effects of oil hedges |
|
|
|
|
|
|
|
|
|
|
(11,512 |
) |
Natural gas revenue |
|
|
84,716 |
|
|
|
46,716 |
|
|
|
40,461 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
182,515 |
|
|
$ |
116,031 |
|
|
$ |
97,025 |
|
|
|
|
|
|
|
|
|
|
|
|
(t) |
|
Recent Accounting Pronouncements |
|
|
|
|
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (SFAS 157).
SFAS 157 defines fair value as used in numerous accounting pronouncements, establishes a
framework for measuring fair value in accordance with generally accepted accounting
principles and expands disclosure requirements related to the use of fair value measures
in financial statements. The Company adopted SFAS 157 effective January 1, 2008 and the
adoption did not have a significant effect on its financial position or operating
results. |
|
|
|
|
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities, Including an Amendment of FASB Statement No. 115,
(SFAS 159) which became effective on January 1, 2008. SFAS 159 permits entities to
measure eligible financial assets, financial liabilities and firm commitments at fair
value, on an instrument-by-instrument basis, that are otherwise not permitted to be
accounted for at fair value under other generally accepted accounting principles. The
fair value measurement election is irrevocable and subsequent changes in fair value must
be recorded in earnings. This statement did not have any effect on the Companys
financial position or operating results as the Company did not elect to apply the fair
value method. |
|
|
|
|
In April 2007, the FASB issued FASB Staff Position FIN 39-1, Amendment of FASB
Interpretation No. 39 (FSP FIN 39-1). FSP FIN 39-1 clarifies that a reporting entity
that is party to a master netting arrangement can offset fair value amounts recognized
for the right to reclaim cash collateral (a receivable) or the obligation to return cash
collateral (a payable) against fair value amounts recognized for derivative instruments
that have been offset under the same master netting arrangement. FSP FIN 39-1 was
effective for financial statements issued for fiscal years beginning after November 15,
2007. Adoption of FSP FIN 39-1 did not have a material impact on the Companys
consolidated financial statements. |
|
|
|
|
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations
(SFAS 141(R)), which replaces FASB Statement No. 141. SFAS 141(R) establishes
principles and requirements for how an acquirer recognizes and measures in its financial
statements the identifiable assets acquired, the liabilities assumed, any non-
controlling interest in the acquiree and the goodwill acquired. The Statement also
establishes disclosure requirements that will enable users to evaluate the nature and
financial effects of the business combination. SFAS 141(R) is effective for acquisitions
that occur in an entitys fiscal year that begins after December 15, 2008, which will be
the Companys fiscal year
2009. The impact, if any, will depend on the nature and size of business combinations
the Company consummates after the effective date. |
F-16
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statementsan amendment of ARB No. 51 (SFAS 160). SFAS 160
requires that accounting and reporting for minority interests will be recharacterized as
noncontrolling interests and classified as a component of equity. SFAS 160 also
establishes reporting requirements that provide sufficient disclosures that clearly
identify and distinguish between the interests of the parent and the interests of the
noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated
financial statements, except not-for-profit organizations, but will affect only those
entities that have an outstanding noncontrolling interest in one or more subsidiaries or
that deconsolidate a subsidiary. This statement is effective as of the beginning of an
entitys first fiscal year beginning after December 15, 2008, which will be the
Companys fiscal year 2009. Based upon the Companys balance sheet, the statement would
have no impact. |
|
|
|
|
In February 2008, the FASB issue Financial Staff Positions (FSP) FAS 157-2, Effective
Date of FASB Statement No. 157 (FSP FAS 157-2), which delays the effective date of
SFAS 157, for all nonfinancial assets and nonfinancial liabilities, except those that
are recognized or disclosed at fair value in the financial statements on a recurring
basis (at least annually), SFAS 157 establishes a framework for measuring fair value and
expands disclosures about fair value measurements. FSP FAS 157-2 is effective for the
Company beginning January 1, 2009. The Company does not anticipate that this
pronouncement will have a material impact on its results of operations or consolidated
financial position. |
|
|
|
|
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments
and Hedging Activities, an amendment of FASB Statement No. 133 (SFAS 161). This
statement is intended to improve transparency in financial reporting by requiring
enhanced disclosures of an entitys derivative instruments and hedging activities and
their effects on the entitys financial position, financial performance, and cash flows.
SFAS 161 applies to all derivative instruments within the scope of SFAS 133, Accounting
for Derivative Instruments and Hedging Activities (SFAS 133), as well as related
hedged items, bifurcated derivatives, and nonderivative instruments that are designated
and qualify as hedging instruments. Entities with instruments subject to SFAS 161 must
provide expanded disclosures. SFAS 161 is effective prospectively for financial
statements issued for fiscal years and interim periods beginning after November 15,
2008, with early application permitted. This statement will have no impact to the
Companys financial results of operations. The Company will apply SFAS 161 beginning
January 1, 2009. |
|
|
|
|
In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles (SFAS 162), which becomes effective for the Company 60 days
following the SECs approval of the Public Company Accounting Oversight Board amendments
to AU Section 411, The Meaning of Present Fairly in Conformity With General Accepted
Accounting Principles". This standard identifies the sources of accounting principles
and the framework for selecting the principles used in the preparation of financial
statements that are presented in conformity with generally accepted accounting
principles. The Company does not anticipate that this pronouncement will have a material
impact on its results of operations or consolidated financial position. |
|
|
|
|
In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1
Determining Whether Instruments Granted in Share-Based Payment Transactions are
Participating Securities (FSP EITF 03-6-1), which addresses whether instruments
granted
in share-based payment transactions are participating securities prior to vesting and,
therefore, need to be included in the net income allocation in computing basic net
income per share under the two class method prescribed under SFAS 128
Earnings per
Share. FSP 03-6-1 is effective for
|
F-17
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
financial statements issued for fiscal years
beginning after December 15, 2008 and, to the extent applicable, must be applied
retrospectively by adjusting all prior-period net income per share data to conform to
the provisions of the standard. The adoption of FSP EITF 03-6-1 is not expected to have
a material effect on the Companys earnings per share calculations. |
|
|
|
|
In December 2008, the Securities and Exchange Commission published a Final Rule,
Modernization of Oil and Gas Reporting. The new
rule permits the use of new technologies to determine proved reserves if those
technologies have been demonstrated to lead to reliable conclusions about reserves
volumes. The new requirements also will allow companies to disclose their probable and
possible reserves to investors. In addition, the new disclosure requirements require
companies to: (a) report the independence and qualifications of its reserves preparer or
auditor; (b) file reports when a third party is relied upon to prepare reserves
estimates or conducts a reserves audit; and (c) report oil and gas reserves using an
average price based upon the prior 12-month period rather than year-end prices. The use of average prices will affect
future impairment and depletion calculations. |
|
|
|
|
The new disclosure requirements are effective for annual reports on Forms 10-K for
fiscal years ending on or after December 31, 2009. A company may not apply the
new rules to disclosures in quarterly reports prior to the first annual report in which
the revised disclosures are required. The Company has not yet determined the impact of
this Final Rule, which will vary depending on changes in commodity prices on its
disclosures financial position or results of operations. |
(2) |
|
Earnings Per Share |
|
|
|
The following table provides the computation of basic and diluted earnings per share for the
years ended December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
(in thousands, except per share data) |
|
Basic EPS Computation: |
|
|
|
|
|
|
|
|
|
|
|
|
Numerator- |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(131,894 |
) |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator- |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
41,471 |
|
|
|
38,120 |
|
|
|
35,888 |
|
|
|
|
|
|
|
|
|
|
|
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share |
|
$ |
(3.18 |
) |
|
$ |
(0.12 |
) |
|
$ |
0.73 |
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS Computation: |
|
|
|
|
|
|
|
|
|
|
|
|
Numerator- |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(131,894 |
) |
|
$ |
(4,661 |
) |
|
$ |
26,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator - |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding |
|
|
41,471 |
|
|
|
38,120 |
|
|
|
35,888 |
|
Employee stock options |
|
|
|
|
|
|
|
|
|
|
599 |
|
Warrants |
|
|
|
|
|
|
|
|
|
|
269 |
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares for diluted
earnings per share assuming conversion |
|
|
41,471 |
|
|
|
38,120 |
|
|
|
36,756 |
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share |
|
$ |
(3.18 |
) |
|
$ |
(0.12 |
) |
|
$ |
0.71 |
|
|
|
|
|
|
|
|
|
|
|
F-18
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
For the years ended December 31, 2008 and 2007, the effects of all potentially dilutive
securities (including options and warrants) were excluded from the computation of diluted
earnings per share because the Company had a net loss and, therefore, the effect would have
been anti-dilutive. Approximately 286,000 and 878,000 options and warrants were excluded from
the computation of diluted earnings per share in 2008 and 2007, respectively. |
|
(3) |
|
Fair Value of Financial Instruments |
|
|
|
The fair values and methods and assumptions used to estimate the fair values for each class of
financial instruments are as follows. The fair value of a financial instrument is the amount
at which the instrument could be exchanged in a current transaction between two willing
parties. |
|
|
|
The carrying amount of cash, short-term investments, accounts receivable, accounts payable,
and accrued liabilities approximates fair value because of the short maturity of these
instruments. |
|
|
|
The carrying amount of long-term debt outstanding under the Companys revolving credit
facility in 2008 and 2007 approximated fair value because the Companys borrowing rate on this
financial instrument is based on a variable market rate of interest. |
|
|
|
The carrying value of the Companys 101/4% senior notes at December 31, 2008 is approximately
$145.9 million and their estimated fair value is approximately $99.0 million. Fair value is
estimated based on market trades at or near December 31, 2008. |
|
|
|
The Company also has derivative instruments which are
described in Note 9 - Derivative Instruments.
|
|
(4) |
|
Property Exchange and Acquisitions |
|
|
|
In January, 2006, Parallel acquired additional interest in the Harris San Andres Field
properties located in Andrews and Gaines counties, Texas for a net purchase price of
approximately $23.4 million, including adjustments. The 2006 purchase was made utilizing
Parallels restricted cash and revolving credit facility. In March 2006, Parallel purchased
additional interests in the Barnett Shale Gas Project located in Tarrant County, Texas. The
additional interests were acquired from five unaffiliated parties for a total cash purchase
price of approximately $5.5 million. In April 2006, Parallel acquired an additional interest
in the Barnett Shale Gas Project located in Tarrant County, Texas from one other unaffiliated
third party for approximately $570,000. |
|
|
|
On February 23, 2007, we entered into a property exchange agreement with an unrelated third
party. As a result of the exchange, we acquired an additional 9,233 net undeveloped acres in
our New Mexico Wolfcamp project area with an estimated fair value of approximately $6.5
million. We are the operator of wells drilled on this undeveloped acreage. Under the terms
of the exchange agreement, we assigned to the third party interests in 37 non-operated wells
and 3,250 net undeveloped non-operated acres in the New Mexico Wolfcamp project area, along
with cash of approximately $969,000. In accordance with the full cost method of accounting, no
gain or loss was recorded on the transaction. |
|
|
|
On June 26, 2008 we exercised a preferential right and purchased additional the interests
owned by an unrelated third party in our operated Diamond M properties in Scurry County,
Texas, effective May 1, 2008. The purchase price, approximately $35.5 million, was financed
with borrowings under our revolving credit facility. The additional interest acquired
represented proved reserves of approximately 2.0 million BOE. |
|
|
|
The acquired interest consisted of two components, including an 89% working interest in the
Base production and reserves and a 22.3% working interest in the production and reserves above
the |
F-19
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
Base. As used in our original trade agreement with the unrelated third party, the Base
production and reserves generally referred to and meant future production and reserves defined by an
established base production decline curve as of December 19, 2001. Prior to this acquisition,
we did not own an interest in the Base production and reserves but owned a 65.7% working
interest in the production and reserves above the Base. This acquisition resulted in an
increase in our current ownership in the Base production and reserves from zero to an
approximate 89% working interest (77% net revenue interest), and an increase in the production
and reserves above the Base from a 65.7% working interest to an 88% working interest (76% net
revenue interest). |
|
|
As described in Note 10 - Investment in Gas Gathering Systems, in June 2008 we acquired all of
the assets of the Hagerman Gas Gathering System Joint Venture. |
|
(5) |
|
Oil and Natural Gas Properties |
|
|
|
The following table reflects capitalized costs related to the oil and natural gas properties
as of December 31: |
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
|
|
($ in thousands) |
|
Proved properties |
|
$ |
741,520 |
|
|
$ |
562,174 |
|
Unproved properties, not subject to depletion |
|
|
137,202 |
|
|
|
86,402 |
|
|
|
|
|
|
|
|
|
|
|
878,722 |
|
|
|
648,576 |
|
Accumulated depletion (1) |
|
|
(488,168 |
) |
|
|
(143,264 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
390,554 |
|
|
$ |
505,312 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes $300.5 million impairment of oil and natural gas properties in 2008. |
At December 31, 2008, the net book value of the Companys oil and natural gas properties, less
related deferred income taxes, was above the calculated ceiling. As a result, the Company was
required to record an impairment of its oil and natural gas properties under the full cost
method of accounting in the amount of $300.5 million for the year ended December 31, 2008.
The following table reflects, by category of cost, amounts excluded from the depletion base as
of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and |
|
|
|
|
|
|
|
|
Leasehold |
|
|
Geological and |
|
|
Work-in- |
|
|
|
|
Year Incurred |
|
|
|
Costs |
|
|
Geophysical |
|
|
Progress |
|
|
Total |
|
|
|
|
|
($ in thousands) |
|
2008 |
|
|
|
$ |
35,866 |
|
|
$ |
5,334 |
|
|
$ |
39,103 |
|
|
$ |
80,303 |
|
2007 |
|
|
|
|
34,195 |
|
|
|
2,088 |
|
|
|
3,665 |
|
|
|
39,948 |
|
2006 |
|
|
|
|
15,415 |
|
|
|
989 |
|
|
|
|
|
|
|
16,404 |
|
Prior |
|
|
|
|
496 |
|
|
|
51 |
|
|
|
|
|
|
|
547 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
85,972 |
|
|
$ |
8,462 |
|
|
$ |
42,768 |
|
|
$ |
137,202 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2008 and 2007, unevaluated costs of approximately $137.2 million and $86.4
million, respectively, were excluded from the depletion base. These costs consist primarily of
acreage acquisition, related geological and geophysical costs, prepaid drilling costs and
work-in-progress. The majority of these costs relate to the Companys New Mexico and Barnett
Shale
F-20
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
leasehold positions. The Company transfers these costs to the full cost pool as wells
are drilled or as proven well locations are identified. The timing of these transfers is
highly dependent on the Companys future drilling program.
Certain directly identifiable internal costs of property acquisition, exploration, and
development activities are capitalized. Such costs capitalized in 2008, 2007 and 2006 totaled
approximately $1.9 million, $1.9 million and $2.3 million, respectively, including $55,000,
$394,000 and $620,000 of capitalized interest for the years ended December 31, 2008, 2007 and
2006, respectively.
Depletion per equivalent unit of production (BOE) was $15.56, $13.02 and $10.88 for 2008, 2007
and 2006, respectively. Accordingly, depletion expense, excluding the impact of the
impairment write-down, was approximately $44.4 million, $29.8 million and $24.3 million in
2008, 2007 and 2006, respectively.
The following table reflects costs incurred in oil and natural gas property acquisition,
exploration, and development activities for each of the years in the three year period ended
December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
Proved property acquisition costs |
|
$ |
41,481 |
|
|
$ |
|
|
|
$ |
27,370 |
|
Unproved property acquisition costs |
|
|
41,568 |
|
|
|
36,750 |
|
|
|
30,058 |
|
Exploration costs |
|
|
59,290 |
|
|
|
55,827 |
|
|
|
71,003 |
|
Development costs |
|
|
88,235 |
|
|
|
61,766 |
|
|
|
69,285 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
230,574 |
|
|
$ |
154,343 |
|
|
$ |
197,716 |
|
|
|
|
|
|
|
|
|
|
|
(6) |
|
Other Assets |
|
|
|
Below are the components of other assets as of December 31, 2008 and 2007: |
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
($ in thousands) |
|
Revolving credit facility deferred financing costs, net |
|
$ |
1,306 |
|
|
$ |
1,185 |
|
Senior notes deferred financing costs, net |
|
|
1,432 |
|
|
|
1,575 |
|
Other |
|
|
828 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
$ |
3,566 |
|
|
$ |
2,768 |
|
|
|
|
|
|
|
|
|
|
Amortization expense was approximately $567,000, $493,000, and $492,000 in 2008, 2007 and
2006, respectively. |
|
(7) |
|
Other Accrued Liabilities |
|
|
|
Below are the components of other accrued liabilities as of December 31, 2008 and 2007: |
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
($ in thousands) |
|
Revenue payable to joint interest owners |
|
$ |
8,004 |
|
|
$ |
9,062 |
|
Accrued capital expenditures |
|
|
9,275 |
|
|
|
11,907 |
|
Accrued lease operating expense |
|
|
2,223 |
|
|
|
1,581 |
|
Other |
|
|
2,240 |
|
|
|
6,585 |
|
|
|
|
|
|
|
|
|
|
$ |
21,742 |
|
|
$ |
29,135 |
|
|
|
|
|
|
|
|
F-21
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(8) |
|
Asset Retirement Obligations |
|
|
|
The Companys asset retirement obligations consist of costs related to the plugging of
wells, the removal of facilities and equipment and site restoration on oil and natural gas
properties. |
|
|
|
The following table summarizes the Companys asset retirement obligation transactions for
the years ended December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
Beginning asset retirement obligation |
|
$ |
4,937 |
|
|
$ |
5,063 |
|
|
$ |
2,495 |
|
Additions related to new properties |
|
|
1,152 |
|
|
|
257 |
|
|
|
406 |
|
Revisions in estimated cash flows |
|
|
4,949 |
|
|
|
(342 |
) |
|
|
1,979 |
|
Deletions related to property disposals |
|
|
(60 |
) |
|
|
(365 |
) |
|
|
(65 |
) |
Accretion expense |
|
|
401 |
|
|
|
324 |
|
|
|
248 |
|
|
|
|
|
|
|
|
|
|
|
Ending asset retirement obligation |
|
$ |
11,379 |
|
|
$ |
4,937 |
|
|
$ |
5,063 |
|
|
|
|
|
|
|
|
|
|
|
(9) |
|
Derivative Instruments |
|
|
|
The Company enters into derivative contracts to provide a measure of stability in the cash
flows associated with the Companys oil and natural gas production and interest rate payments
and to manage exposure to commodity price and interest rate risk. The Companys objective is
to lock in a range of oil and natural gas prices and to limit variability in its cash interest
payments. In addition, the Companys revolving credit facility requires the Company to
maintain derivative financial instruments which limit the Companys exposure to fluctuating
commodity prices covering at least 50% of the Companys estimated monthly production of oil
and natural gas extending 24 months into the future. |
|
|
|
Derivative contracts not designed as cash flow hedges are marked to market at each period
end and the increases or decreases in fair values are recorded to earnings. No derivative
contracts entered into subsequent to June 30, 2004, have been designated as cash flow hedges. |
|
|
|
Adoption of SFAS No. 157 |
|
|
|
The Company adopted SFAS No. 157, Fair Value Measurements (SFAS 157), effective January 1,
2008 for all financial assets and liabilities. As defined in SFAS 157, fair value is the
price that would be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date (exit price). In determining
the fair value of its derivative contracts the Company evaluates its counterparty and
third party service provider valuations and adjusts for credit risk when appropriate SFAS 157
requires disclosure that establishes a framework for measuring fair value and expands
disclosure about fair value measurements. The statement requires fair value measurements be
classified and disclosed in one of the following categories: |
|
|
|
Level 1: |
|
Unadjusted quoted prices in active markets that are accessible at the
measurement date for identical, unrestricted assets or liabilities. The Company
considers active markets as those in which transactions for the assets or
liabilities occur in sufficient frequency and volume to provide pricing
information on an ongoing basis. |
F-22
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
Level 2: |
|
Quoted prices in markets that are not active, or inputs which are observable,
either directly or indirectly, for substantially the full term of the asset or
liability. This category includes those derivative instruments that are valued
using observable market data. Substantially all of these inputs are observable in
the marketplace throughout the full term of the derivative instrument, can be
derived from observable data, or supported by observable levels at which
transactions are executed in the marketplace. Instruments in this category include
non-exchange traded derivatives such as over-the-counter commodity price swaps and
interest rate swaps. |
|
|
|
Level 3: |
|
Measured based on prices or valuation models that require inputs that are
both significant to the fair value measurement and less observable from objective
sources (i.e., supported by little or no market activity). The Companys valuation
models are primarily industry-standard models that consider various inputs
including: (a) quoted forward prices for commodities, (b) time value,
(c) volatility factors and (d) current market and contractual prices for the
underlying instruments, as well as other relevant economic measures. Level 3
instruments primarily include derivative instruments, such as commodity price
collars and puts. These instruments are considered Level 3 because the Company
does not have sufficient corroborating market evidence for volatility to support
classifying these assets and liabilities as Level 2. |
As required by SFAS 157, financial assets and liabilities are classified based on the lowest
level of input that is significant to the fair value measurement. The Companys assessment of
the significance of a particular input to the fair value measurement requires judgment, and
may affect the valuation of the fair value of assets and liabilities and their placement
within the fair value hierarchy levels.
The following table summarizes the fair market valuation of the Companys derivative financial
assets (liabilities) by SFAS 157 valuation levels as of December 31, 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices in |
|
|
|
|
|
|
|
|
|
|
|
|
Active Markets |
|
|
|
|
|
|
|
|
|
|
|
|
for Identical |
|
|
Other Observable |
|
|
Unobservable |
|
|
Fair Value at |
|
|
|
Assets (Level 1) |
|
|
Inputs (Level 2) |
|
|
Inputs (Level 3) |
|
|
December 31, 2008 |
|
Interest Swaps |
|
$ |
|
|
|
$ |
(8,052 |
) |
|
$ |
|
|
|
$ |
(8,052 |
) |
Oil Puts |
|
|
|
|
|
|
|
|
|
|
16,656 |
|
|
|
16,656 |
|
Oil & Gas Collars |
|
|
|
|
|
|
|
|
|
|
20,002 |
|
|
|
20,002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
|
|
|
$ |
(8,052 |
) |
|
$ |
36,658 |
|
|
$ |
28,606 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The determination of the fair values above incorporates various factors required under SFAS
157. These factors include the impact of our nonperformance risk and the credit standing of
the counterparties involved in the Companys derivative contracts. The risk of nonperformance
by the Companys counterparties is mitigated by the fact that such counterparties (or their
affiliates) are also bank lenders under the Companys Revolving Credit Agreement and the
derivative instruments with these counterparties allow the Company to setoff amounts owed by
the counterparty to it against any obligation of the Company owed to the counterparty under
the Companys Revolving Credit Agreement.
F-23
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth a reconciliation of changes in the fair value of financial
assets and liabilities classified as Level 3 in the fair value hierarchy (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended |
|
|
|
December 31, 2008 |
|
|
|
Derivative |
|
|
Derivative |
|
|
|
Collars |
|
|
Puts |
|
Beginning balance |
|
$ |
(15,852 |
) |
|
$ |
|
|
Total gains |
|
|
30,453 |
|
|
|
12,470 |
|
Settlements |
|
|
5,401 |
|
|
|
|
|
Purchases |
|
|
|
|
|
|
4,186 |
|
|
|
|
|
|
|
|
Ending balance |
|
$ |
20,002 |
|
|
$ |
16,656 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in unrealized gains (losses) included in earnings relating
to derivatives still held as of December 31, 2008(1) |
|
$ |
35,854 |
|
|
$ |
12,470 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gains and losses (realized and unrealized) included in earnings for
the year ended December 31, 2008 are reported in other income on the
Consolidated
Statement of Operations. |
During periods of market disruption, including periods of volatile oil and natural gas prices,
rapid credit contraction or illiquidity, it may be difficult to value certain of the Companys
derivative instruments if trading becomes less frequent and/or market data becomes less
observable. There may be certain asset classes that were in active markets with observable
data that become illiquid due to the current financial environment. In such cases, more
derivative instruments may fall to Level 3 and thus require more subjectivity and management
judgment. As such, valuations may include inputs and assumptions that are less observable or
require greater estimation as well as valuation methods which are more sophisticated or
require greater estimation thereby resulting in valuations with less certainty. Further,
rapidly changing commodity and unprecedented credit and equity market conditions could
materially impact the valuation of derivative instruments as reported within our consolidated
financial statements and the period-to-period changes in value could vary significantly.
Decreases in value may have a material adverse effect on our results of operations or
financial condition.
Interest Rates
Under the Companys revolving credit facility, the Company may elect an interest rate based
upon the agent banks base lending rate, plus a margin ranging from 0% to 0.25%, or the LIBOR
rate, plus a margin ranging from 2.25% to 2.75% per annum, depending on the Companys
borrowing base usage. The interest rate the Company is required to pay, including the
applicable margin, may never be less than 4.75%. Under the Companys second lien term loan
facility, the Company had the option to elect an interest rate based upon an alternate base
rate, or the LIBOR rate, plus a margin of 4.50%. The second lien term loan facility was paid
in its entirety and terminated on July 31, 2007 with the Companys payment to the lenders of
$50.2 million, including interest.
Interest Rate Swaps. The Company has entered into interest rate swaps with BNP
Paribas and Citibank, N.A. (the counterparties) which are intended to have the effect of
converting the variable rate interest payments to be made on the Companys revolving credit
agreement to fixed interest rates for the periods covered by the swaps. Under terms of these
swap contracts, in periods during which the fixed interest rate stated in the swap contract
exceeds the variable rate (which is based on the 90 day LIBOR rate), the Company pays to the
counterparties an amount determined by applying this excess fixed rate to the notional amount
of the contract. In periods when the variable
F-24
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
rate exceeds the fixed rate stated in the swap
contracts, the counterparties pay an amount to the
Company determined by applying the excess of the variable rate over the stated fixed rate to
the notional amount of the contract. These contracts are accounted for by mark to market
accounting as prescribed in SFAS 133. The Company has historically viewed these contracts as
additional protection against future interest rate volatility.
The table below recaps the nature of these interest rate swaps and the fair market value of
these contracts as of December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional |
|
|
Weighted Average |
|
Estimated |
|
Period of Time |
|
Amounts |
|
|
Fixed Interest Rates |
|
Fair Market Value |
|
|
|
($ in millions) |
|
|
|
|
|
|
($ in thousands) |
|
January 1, 2009 through December 31, 2009 |
|
$ |
100 |
|
|
|
4.22 |
% |
|
$ |
(3,004 |
) |
January 1, 2010 through October 31, 2010 |
|
$ |
100 |
|
|
|
4.71 |
% |
|
|
(2,517 |
) |
November 1, 2010 through December 31, 2010 |
|
$ |
50 |
|
|
|
4.26 |
% |
|
|
(216 |
) |
January 1, 2011 through December 31, 2011 |
|
$ |
100 |
|
|
|
4.67 |
% |
|
|
(2,315 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
(8,052 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Prices
All of the Companys commodity derivatives are accounted for using mark-to-market accounting
as prescribed in SFAS 133.
Put Options. Puts are options to sell assets. For any put transaction, the
counterparty is required to make a payment to the Company if the reference floating price for
any settlement period is less than the put or floor price for such contract.
In June 2008, the Company entered into multiple put contracts with BNP Paribas and in October
2008 the Company entered into a put contract with Citibank, N.A. In lieu of making premium
payments for the puts at the time of entering into its put contracts, the Company deferred
payment until the settlement dates of the contracts. Future premium payments will be netted
against any payments that the counterparty may owe to the Company based on the floating price.
Due to the deferral of the premium payments, the Company will pay a total amount of premiums
of $4.68 million which is $491,000 greater than if the premiums had been paid at the time of
entering into the contracts. The $491,000 difference is recorded as a discount to the put
premium obligations and recognized as interest expense over the terms of the contracts using
the effective interest method. Through December 31, 2008, the Company has accrued $97,000 of
interest expense. Accordingly, the recorded balance of the put premium obligations at December
31, 2008 is $4.28 million.
A summary of the Companys put positions at December 31, 2008 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels of |
|
|
|
|
|
|
Estimated |
|
Period of Time |
|
Oil |
|
|
Floor |
|
|
Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
January 1, 2009 through December 31, 2009 |
|
|
109,500 |
|
|
$ |
100.00 |
|
|
$ |
5,112 |
|
January 1, 2010 through December 31, 2010 |
|
|
280,100 |
|
|
$ |
84.36 |
|
|
|
6,405 |
|
January 1, 2011 through December 31, 2011 |
|
|
146,000 |
|
|
$ |
100.00 |
|
|
|
5,139 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
$ |
16,656 |
|
|
|
|
|
|
|
|
|
|
|
|
|
F-25
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Collars. Collars are contracts which combine both a put option or floor and a call
option or ceiling. These contracts may or may not involve payment or receipt of cash at
inception, depending on ceiling and floor pricing. Citibank, N.A. and BNP Paribas are the
counterparties to the Companys oil and natural gas collar contracts.
A summary of the Companys collar positions at December 31, 2008 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels of |
|
|
NYMEX Oil Prices |
|
Estimated |
|
Period of Time |
|
|
|
|
|
Oil |
|
|
Floor |
|
|
Ceiling |
|
Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ in thousands) |
|
January 1, 2009 through December 31, 2009 |
|
|
|
|
|
|
766,500 |
|
|
$ |
65.71 |
|
|
$ |
82.93 |
|
$ |
10,942 |
January 1, 2010 through October 31, 2010 |
|
| | | |
|
486,400 |
|
|
$ |
63.44 |
|
|
$ |
78.26 |
|
|
2,449 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
M M Btu of |
|
|
WAHA Gas Prices |
|
|
|
|
|
|
|
Natural Gas |
|
|
Floor |
|
|
Ceiling |
|
|
|
|
|
January 1,
2009 through December 31, 2009 |
|
|
3,285,000 |
|
|
$ |
7.06 |
|
|
$ |
9.93 |
|
|
|
6,611 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Fair Market Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
20,002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10) |
|
Investment in Gas Gathering Systems |
|
|
|
Prior to 2006, the Company had three separate partnership investments to construct pipeline
systems which gather natural gas, primarily on its leaseholds in the Barnett Shale area. The
partnership investments included West Fork Pipeline Company I, L.P., West Fork Pipeline
Company II, L.P. and West Fork Pipeline Company V, L.P. These investments were recorded as
equity method investments. |
|
|
|
In the fourth quarter of 2006, substantially all of the assets of West Fork Pipeline I and
West Fork Pipeline V were sold. The Company received distributions of $16.0 million and
$683,000, respectively, as a result of these asset sales. The total of these distributions,
approximately $16.7 million, is reported in the accompanying statement of cash flows for 2006
in Cash flows from operating activities as Return on investment in pipelines and gathering
systems ventures in the amount of $9.0 million, which represents the excess of distributions
received over the Companys cash investments in these ventures, and in Cash flows from
investing activities as Return of investment in pipelines and gathering systems ventures in
the amount of $7.7 million, representing the return through distribution of the Companys
previous cash investments in the two joint ventures. |
|
|
|
The Company had a total equity investment of $337,000 in West Fork Pipeline II at December 31,
2008. The Companys investment percentage in the West Fork Pipeline II is 23.25848%. |
|
|
|
The Company had a net investment of $8.7 million in the Hagerman Gas Gathering System Joint
Venture (Hagerman) to construct pipelines on certain of its leaseholds in New Mexico. The
Companys investment percentage in Hagerman was 76.50%. In June 2008, the Company acquired
all of the assets of the Hagerman Gas Gathering System Joint Venture, or the Joint Venture,
for the purchase price of $3.2 million, in connection with winding up and terminating the
Joint Venture. The winding up of the Joint Venture commenced on June 19, 2008. At the time
of the winding up of the Joint Venture, the investment was transferred into oil and natural
gas properties and subsequent results have been included in the Companys operating income and
not as an equity gain (loss) item in the Companys Consolidated Statement of Operations. |
F-26
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Until June 2008, the Companys investment in Hagerman was accounted for by the equity method
because the Company did not have voting control. All significant actions taken by Hagerman
had to be approved by the Company plus one of the two other equity owners. Consequently, the
remaining equity owners prevented voting control by the Company.
The Companys equity investments for the periods indicated consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
($ in thousands) |
|
West Fork Pipeline Company II, L.P. |
|
$ |
337 |
|
|
$ |
312 |
|
Hagerman Gas Gathering System |
|
|
|
|
|
|
8,326 |
|
|
|
|
|
|
|
|
|
|
$ |
337 |
|
|
$ |
8,638 |
|
|
|
|
|
|
|
|
The Companys earnings from equity investments for the periods indicated were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
West Fork Pipeline Company I, L.P.(1) |
|
$ |
|
|
|
$ |
161 |
|
|
$ |
9,286 |
|
West Fork Pipeline Company II, L.P. |
|
|
(1 |
) |
|
|
3 |
|
|
|
(50 |
) |
West Fork Pipeline Company V, L.P.(2) |
|
|
|
|
|
|
126 |
|
|
|
(147 |
) |
Hagerman Gas Gathering System(3) |
|
|
381 |
|
|
|
(601 |
) |
|
|
(496 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
380 |
|
|
$ |
(311 |
) |
|
$ |
8,593 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Included in the Companys earnings for 2007
is its proportionate share of a final cash distribution of
$161,000 received in the fourth quarter of 2007. Included in
the Companys earnings for 2006 is its proportionate gain in
the sale of the partnership assets of approximately $9.1
million. |
|
(2) |
|
Included in the Companys earnings for 2007
was its proportionate share of a final cash distribution of
$126,000 received in the fourth quarter of 2007. Included in
the Companys earnings for 2006 is its proportionate loss in
the sale of the partnership assets of approximately $90,000. |
|
(3) |
|
Includes the Companys proportionate share
of earnings before the acquisition of the remaining assets in
June 2008. |
F-27
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summarized combined financial information for the Companys equity investments (listed above)
is reported below. Amounts represent 100% of the investees financial information:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
($ in thousands) |
|
Balance Sheet |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
78 |
|
|
$ |
62 |
|
Account receivables affiliates |
|
|
|
|
|
|
696 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
78 |
|
|
|
758 |
|
Plan and pipeline costs |
|
|
707 |
|
|
|
10,917 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
785 |
|
|
$ |
11,675 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
|
|
|
$ |
50 |
|
Accounts payable affiliates |
|
|
|
|
|
|
523 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
|
|
|
|
573 |
|
Partner capital |
|
|
785 |
|
|
|
11,102 |
|
|
|
|
|
|
|
|
Total
liabilities and partner capital |
|
$ |
785 |
|
|
$ |
11,675 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
Income Statement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
1,188 |
|
|
$ |
847 |
|
|
$ |
2,402 |
|
Costs and expenses |
|
|
(699 |
) |
|
|
(1,654 |
) |
|
|
(2,597 |
) |
Gain/loss on sale of assets |
|
|
|
|
|
|
782 |
|
|
|
23,780 |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
489 |
|
|
$ |
(25 |
) |
|
$ |
23,585 |
|
|
|
|
|
|
|
|
|
|
|
(11) |
|
Credit Arrangements |
|
|
|
In the past, the Company has maintained two separate credit facilities. One of these credit
facilities is the Fourth Amended and Restated Credit Agreement, dated May 16, 2008, as
amended on October 31, 2008 described below, or the Revolving Credit Agreement. This
Revolving Credit Agreement provides the Company with a revolving line of credit having a
borrowing base limitation of $230.0 million. |
|
|
|
The Companys second credit facility was a five year term loan facility provided to it under
a Second Lien Term Loan Agreement, or the Second Lien Agreement, with a group of banks and
other lenders. The Second Lien Agreement was paid in its entirety and terminated on July 31,
2007 with the Companys payment to the lenders of $50.2 million, including interest. |
|
|
|
On July 31, 2007, the Company completed a private offering of unsecured senior notes in the
principal amount of $150.0 million. |
F-28
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The senior notes have a fixed rate of 101/4% throughout the life of the notes.
The revolving credit
facility has varying interest rates and consisted of the following banks base
rate and LIBOR tranches at December 31:
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
|
|
($ in thousands) |
|
Revolving Credit Facility note payable to banks,
| | | | | | | | |
Agent banks base lending rate of 4.75% |
|
$ |
225,000 |
|
|
$ |
|
|
Libor Tranche at 6.84% |
|
|
|
|
|
|
60,000 |
|
Senior notes (principal amount $150,000)
rate of 101/4% |
|
|
145,890 |
|
|
|
145,383 |
|
|
|
|
|
|
|
|
Total notes payable to banks |
|
$ |
370,890 |
|
|
$ |
205,383 |
|
|
|
|
|
|
|
|
Revolving Credit Facility
The Revolving Credit Agreement, with a group of bank lenders provides the Company with a
revolving line of credit having a borrowing base limitation of $230.0 million at December
31, 2008. The total amount that the Company can borrow and have outstanding at any one time
is limited to the lesser of $600.0 million or the borrowing base established by the lenders.
At December 31, 2008, the principal amount outstanding under its revolving credit facility
was $225.0 million, excluding $445,000 reserved for our letters of credit. The Company has
pledged substantially all of its producing oil and natural gas properties to secure the
repayment of its indebtedness under the Revolving Credit Agreement.
The Revolving Credit Agreement allows the Company to borrow, repay and reborrow amounts
available under the revolving credit facility. The amount of the borrowing base is based
primarily upon the estimated value of the Companys oil and natural gas reserves. The
borrowing base amount is redetermined by the lenders semi-annually on or about April 1 and
October 1 of each year or at other times required by the lenders or at the Companys request.
If, as a result of the lenders redetermination of the borrowing base, the outstanding
principal amount of the Companys loans exceeds the borrowing base, the Company must either
provide additional collateral to the lenders or repay the outstanding principal of its loans
in an amount equal to the excess. Except for the principal payments that may be required
because of the Companys outstanding loans being in excess of the borrowing base, interest
only is payable monthly.
As of December 31, 2008, the Companys group of bank lenders included Citibank, N.A., BNP
Paribas, Compass Bank, Bank of Scotland plc, Bank of America, N.A., Texas Capital Bank, N.A.,
Western National Bank and West Texas National Bank. None of the bank lenders hold more than
21% of the facility at December 31, 2008.
Loans made to the Company under this revolving credit facility bear interest based on the
base rate of Citibank, N.A. or the LIBOR rate, at the Companys election.
The base rate is generally equal to the sum of (a) Citibanks prime rate as announced by it
from time to time and (b) a specified margin, the amount of which depends upon the
outstanding principal amount of the Companys loan. If the principal amount outstanding is
equal to or greater than 75% of the borrowing base, the margin is 0.25%. If the borrowing
base usage is less than 75%, the margin is zero percent.
The LIBOR rate is generally equal to the sum of (a) the rate designated as British Bankers
Association Interest Settlement Rates and offered in one, two, three, six or twelve month
interest periods for deposits of $1.0 million, and (b) a margin ranging from 2.25% to 2.75%,
depending upon the outstanding principal amount of the Companys loans. If the principal
amount outstanding
F-29
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
is equal to or greater than 75% of the borrowing base, the margin is 2.75%. If the principal
amount outstanding is equal to or greater than 50%, but less than 75% of the borrowing base,
the margin is 2.50%. If the principal amount outstanding is less than 50% of the borrowing
base, the margin is 2.25%.
The interest rate the Company is required to pay on its borrowings, including the applicable
margin, may never be less than 4.75%. At December 31, 2008, the Companys base rate, plus the
applicable margin, was 4.75% on $225.0 million, the outstanding principal amount of its
revolving loan on that date.
In the case of base rate loans, interest is payable on the last day of each month. In the
case of LIBOR loans, interest is payable on the last day of each applicable interest period.
If the total outstanding borrowings under the revolving credit facility are less than the
borrowing base, the Company is required to pay an unused commitment fee to the lenders in an
amount equal to 0.25% of the daily average of the unadvanced portion of the borrowing base.
The fee is payable quarterly.
If the borrowing base is increased, the Company is also required to pay a fee of 0.375% on
the amount of any such increase.
All outstanding principal and accrued and unpaid interest under the revolving credit facility
is due and payable on December 31, 2013. The maturity date of the Companys outstanding loans
may be accelerated by the lenders upon the occurrence of an event of default under the
Revolving Credit Agreement.
The Revolving Credit Agreement contains various restrictive covenants, including (i)
maintenance of a minimum current ratio, (ii) maintenance of a maximum ratio of funded
indebtedness to earnings before interest, income taxes, depreciation, depletion and
amortization, (iii) maintenance of a minimum net worth, (iv) prohibition of payment of
dividends and (v) restrictions on incurrence of additional debt. The Company has pledged
substantially all of its producing oil and natural gas properties to secure the repayment of
its indebtedness under the revolving credit facility.
As of December 31, 2008, the Company was in compliance with its Revolving Credit Agreement.
On
February 19, 2009, but effective as of December 31, 2008 the Company entered into a Second Amendment to its Revolving Credit
Agreement. See Note 19 Subsequent Events.
Second Lien Term Loan Facility
Until July 31, 2007, the Second Lien Agreement provided a $50.0 million term loan to the
Company. Loans made to the Company under this credit facility bore interest at an alternate
base rate or the LIBO rate, at the Companys election. The alternate base rate was the
greater of (a) the prime rate in effect on such day and (b) the Federal Funds Effective
Rate in effect on such day plus 1/2 of 1%, plus a margin of 3.50% per annum.
The LIBO rate was generally equal to the sum of (a) a designated rate appearing in the Dow
Jones Market Service for the applicable interest periods offered in one, two, three or six
month periods and (b) an applicable margin rate per annum equal to 4.50%.
Upon completion of the Companys senior notes offering, the Company paid off and terminated
this facility with $50.2 million of the net proceeds from the offering. As a result the
Company charged to earnings $760,000 of previously capitalized deferred financing costs.
F-30
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Senior Notes
On July 31, 2007, the Company completed a private offering of unsecured senior notes, or the
senior notes, in the principal amount of $150.0 million. At December 31, 2008, the carrying
value of the Companys senior notes, net of remaining
unamortized discount, was $145.9 million. The
senior notes mature on August 1, 2014 and bear interest at 101/4%, per annum, which is payable
semi-annually beginning on February 1, 2008. Prior to August 1, 2010, the Company may redeem
up to 35% of the senior notes for a price equal to 110.250% of the original principal amount
of the senior notes with the proceeds of certain equity offerings. On or after August 1, 2011
the Company may redeem all or some of the senior notes at a redemption price that will
decrease from 105.125% of the principal amount of the senior notes to 100% of the principal
amount on August 1, 2013. In addition, prior to August 1, 2011, the Company may redeem some
or all of the senior notes at a redemption price equal to 100% of the principal amount of the
senior notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest.
Generally, the make-whole premium is an amount equal to the greater of (a) 1% of the
principal amount of the senior notes being redeemed or (b) the excess of the present value of
the redemption price of such notes as of August 1, 2011 plus all required interest payments
due through August 1, 2011 (computed at a discount rate equal to a specified U.S. Treasury
Rate plus 50 basis points), over the principal amount of the senior notes being redeemed.
If the Company experiences a change of control, it will be required to make an offer to
repurchase the senior notes at a price equal to 101% of the principal amount thereof, plus
accrued and unpaid interest to the date of repurchase.
The indenture governing the senior notes restricts our ability to: (i) borrow money; (ii)
issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make
investments; (v) create liens without securing the senior notes; (vi) enter into agreements
that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into
other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness;
and (x) enter into new lines of business.
As of December 31, 2008 the Company was in compliance with the covenants in the indenture.
The Company agreed, pursuant to a Registration Rights Agreement with the initial purchasers
of the senior notes, to use its commercially reasonable efforts to prepare and file with the
Securities and Exchange Commission, within 180 days after July 31, 2007, a registration
statement with respect to a registered offer to exchange freely tradable notes having
substantially identical terms as the senior notes and to use its reasonable best efforts to
cause the registration statement to be declared effective within 210 days after July 31,
2007. The registration statement became effective on January 29, 2008. All of the Companys
obligations under the Registration Rights Agreement were satisfied on March 4, 2008 when the
Company completed the exchange of freely tradable senior notes for the restricted senior
notes initially issued under the indenture.
Interest
Incurred
For the year ended December 31, 2008, the aggregate interest incurred under the Companys
revolving credit facility and its senior notes was approximately $22.5 million. Deferred
financing costs and note discount amortization was approximately $1.1 million, $690,000 and
$492,000 and interest capitalized was approximately $81,000, $423,000 and $637,000 for the
years ended December 31, 2008, 2007 and 2006, respectively.
F-31
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(12) |
|
Income Taxes |
|
|
|
The Companys income tax benefit (expense) consists of the following: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands) |
|
Federal
income tax benefit of net operating loss carryforward |
|
$ |
7,974 |
|
|
$ |
8,428 |
|
|
$ |
13,252 |
|
State
income tax benefit (expense) of net operating loss carryforward |
|
|
2 |
|
|
|
(80 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
tax benefit of current net operating loss carryforward |
|
$ |
7,976 |
|
|
$ |
8,348 |
|
|
$ |
13,252 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred Federal tax benefit (expense) |
|
$ |
60,005 |
|
|
$ |
(6,006 |
) |
|
$ |
(26,993 |
) |
Deferred State tax benefit (expense) |
|
|
1,743 |
|
|
|
977 |
|
|
|
(153 |
) |
|
|
|
|
|
|
|
|
|
|
Total deferred tax benefit (expense) |
|
$ |
61,748 |
|
|
$ |
(5,029 |
) |
|
$ |
(27,146 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax benefit (expense) |
|
$ |
69,724 |
|
|
$ |
3,319 |
|
|
$ |
(13,894 |
) |
|
|
|
|
|
|
|
|
|
|
Income tax benefit (expense) differs from the amount computed at the federal statutory rate as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
|
($ in thousands, except tax rate) |
|
Income tax
benefit (expense) at statutory rate |
|
$ |
68,525 |
|
|
$ |
2,713 |
|
|
$ |
(13,606 |
) |
Permanent differences |
|
|
(20 |
) |
|
|
(103 |
) |
|
|
(203 |
) |
State tax, net of Federal benefit (expense) |
|
|
1,152 |
|
|
|
592 |
|
|
|
(101 |
) |
Other |
|
|
67 |
|
|
|
117 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
Actual income tax benefit (expense) |
|
$ |
69,724 |
|
|
$ |
3,319 |
|
|
$ |
(13,894 |
) |
|
|
|
|
|
|
|
|
|
|
Effective tax rate |
|
|
34.60 |
% |
|
|
41.60 |
% |
|
|
34.72 |
% |
|
|
|
|
|
|
|
|
|
|
Prior to 2007, the Company had not recognized the tax benefits of state net operating loss
carryovers due to uncertainty about their ultimate realization. The Texas Margin Tax, a revision of
Texas state tax laws, applied to earnings for the first time in 2007. In June 2007, the state of
Texas enacted changes to the Texas Margin Tax legislation originally enacted in 2006, and issued
final rules related to that legislation in December 2007. The utilization of a credit for prior
taxable losses contained in this legislation is dependent on an election to be made by the
taxpayer. Based on the Companys tax planning strategies and the determination (made in December
2007) that the election to utilize the credit would be beneficial to the Companys state and
federal tax positions, the Company decided to make the appropriate election by May 2008, as
required.
F-32
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The tax
effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liability at
December 31 are as follows:
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
|
|
($ in thousands) |
|
Current: |
|
|
|
|
|
|
|
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Fair market value losses on derivatives expected
to be settled within one year |
|
$ |
|
|
|
$ |
10,293 |
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Fair market value gains on derivatives expected
to be settled within one year |
|
|
(6,597 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net current deferred tax assets (liabilities) |
|
$ |
(6,597 |
) |
|
$ |
10,293 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent: |
|
|
|
|
|
|
|
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Property and equipment, principally due to differences in
basis, expensing of intangible drilling costs for tax
purposes, depletion and impairment of oil and natural gas properties |
|
$ |
34,217 |
|
|
$ |
|
|
Federal operating loss carryforwards |
|
|
22,611 |
|
|
|
15,081 |
|
State operating loss credit carryforwards |
|
|
1,764 |
|
|
|
1,805 |
|
Statutory depletion carryforwards |
|
|
2,639 |
|
|
|
2,609 |
|
Alternative minimum tax credit carryforwards |
|
|
157 |
|
|
|
157 |
|
Fair market value losses on derivatives not expected
to be settled within one year |
|
|
|
|
|
|
5,275 |
|
Asset retirement obligations |
|
|
489 |
|
|
|
350 |
|
Other |
|
|
946 |
|
|
|
73 |
|
|
|
|
|
|
|
|
Total noncurrent deferred tax assets |
|
|
62,823 |
|
|
|
25,350 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Property and equipment, principally due to differences in
basis, expensing of intangible drilling costs for tax
purposes and depletion |
|
|
|
|
|
|
(50,368 |
) |
Fair market value gain on derivatives not expected
to be settled within one year |
|
|
(1,645 |
) |
|
|
|
|
Federal impact of state operating loss credit carryforwards |
|
|
(600 |
) |
|
|
(614 |
) |
Partnership investments |
|
|
(11 |
) |
|
|
(413 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent deferred tax liabilities |
|
|
(2,256 |
) |
|
|
(51,395 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net noncurrent deferred income tax assets (liabilities) |
|
$ |
60,567 |
|
|
$ |
(26,045 |
) |
|
|
|
|
|
|
|
F-33
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2008, the Company had net operating loss (NOL) carry forwards for regular
tax and alternative minimum taxable income (AMT) purposes available to reduce future taxable
income.
These carry forwards expire as follows:
|
|
|
|
|
|
|
|
|
|
|
Net operating |
|
|
AMT |
|
|
|
loss |
|
|
operating loss |
|
|
|
($ in thousands) |
|
2019 |
|
$ |
2,566 |
|
|
$ |
2,918 |
|
2021 |
|
|
4,576 |
|
|
|
4,498 |
|
2022 |
|
|
44 |
|
|
|
44 |
|
2023 |
|
|
8 |
|
|
|
332 |
|
2024 |
|
|
3,718 |
|
|
|
3,806 |
|
2025 |
|
|
6,258 |
|
|
|
5,008 |
|
2026 |
|
|
27,849 |
|
|
|
26,003 |
|
2027 |
|
|
23,452 |
|
|
|
21,921 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
68,471 |
|
|
$ |
64,530 |
|
|
|
|
|
|
|
|
Included in the Federal NOL is $2.0 million of NOLs associated with stock based compensation
deductions pursuant to SFAS 109 and SFAS 123(R). The tax benefit associated with this NOL
will be recorded to Additional Paid-In Capital when utilized.
The Company continually assesses its ability to use all of its federal net operating loss
carryforwards and state operating loss credit carryforwards that result from substantial
income tax deductions and prior year losses. The Company considers future federal and state
taxable income in making such assessments. If the Company concludes that it is more likely
than not that some portion or all of the deferred tax assets will not be realized under
accounting standards, they will be reduced by a valuation allowance. The Company believes that it is more likely than not that it will
utilize all of these federal net operating loss carryforwards and state operating loss credit
carryforwards in connection with federal and state income tax
generated in the future. The Company based this
conclusion on an evaluation of its future cash flows, from its year-end reserve report,
estimates related to general and administrative costs and the interest expenses it
anticipates to incur.
As of December 31, 2008, the Company had approximately $157,000 of AMT credit carryforwards
that have no expiration date.
Based on its evaluation, the Company has concluded that there are no significant uncertain
tax positions requiring recognition in its financial statements. The Companys evaluation was
performed for the tax years ended December 31, 2004, 2005, 2006 and 2007, the tax years which
remain subject to examination by major tax jurisdictions as of December 31, 2008.
The Company may from time to time be assessed interest or penalties by major tax
jurisdictions, although any such assessments historically have been minimal and immaterial to
its financial results. In addition, should the Company determine that any of its tax
positions are uncertain it may record related interest and penalties that may be assessed.
F-34
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(13) |
|
Stockholders Equity |
|
|
|
Sale of Equity Securities |
|
|
|
On December 6, 2007, the Company sold 3,000,000 shares of its common stock in an underwritten
public offering at a price of $18.50. The Company used the net proceeds for general
corporate purposes and for conducting exploitation, development and acquisition activities in
certain core areas such as the Companys Permian Basin properties and its Barnett Shale gas
project. |
|
|
|
Stock Compensation, Warrants and Rights |
|
|
|
Parallel accounts for stock based compensation in accordance with the SFAS 123(R). |
|
|
|
The Company awards incentive stock options, nonqualified stock options, restricted stock and
stock awards to selected key employees, officers, and directors. The options are awarded at
an exercise price equal to the closing price of the Companys common stock on the date of
grant. These options vest over a period of two to ten years with a ten-year exercise period.
As of December 31, 2008, options expire beginning in 2011 and extending through 2018. The
stock options, restricted stock and stock awards fair values are described below for each
grant. Stock based compensation expense is classified as general and administrative expenses
in the Consolidated Statements of Operations. |
|
(a) |
|
Plans |
|
|
|
|
1997 Nonemployee Directors Stock Option Plan. The 1997 Nonemployee
Directors Stock Option Plan was approved by the Companys stockholders at the annual
meeting of stockholders held in May 1997. This plan provides for granting to Directors
who are not employees of Parallel options to purchase up to an aggregate of 500,000
shares of common stock. Options granted under this plan are not incentive stock
options within the meaning of the Internal Revenue Code. |
|
|
|
|
Under provisions of the plan, the option exercise price must be the fair market value
of the stock subject to the option on the grant date. Options are not transferable
other than by will or the laws of descent and distribution. |
|
|
|
|
At December 31, 2007, there were no shares of common stock available for future option
grants under the 1997 Stock Option Plan. |
|
|
|
|
At December 31, 2008, options to purchase a total of 92,500 shares of common stock were
outstanding under this plan. |
|
|
|
|
1998 Stock Option Plan. In June 1998, the Companys stockholders adopted
the 1998 Stock Option Plan. The 1998 Plan provides for the granting of options to
purchase up to 850,000 shares of common stock. Stock options granted under the 1998
Plan may be either incentive stock options or stock options which do not constitute
incentive stock options. |
|
|
|
|
Under provisions of the plan, the option exercise price must be the fair market value
of the stock subject to the option on the grant date. Options are not transferable
other than by will or the laws of descent and distribution. |
|
|
|
|
Options may not be granted under the 1998 Plan after March 11, 2008. However, at May
29, 2003, there were no shares of common stock available for future option grants under
the 1998 Stock Option Plan. |
F-35
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
At December 31, 2008, options to purchase a total of 42,500 shares of common stock were
outstanding under this plan. |
|
|
|
|
2001 Nonemployee Directors Stock Option Plan. The 2001 Nonemployee
Directors Stock Option Plan was approved by the Companys stockholders at the annual
meeting of stockholders held in June 2001. This plan provides for granting to
Directors who are not employees of Parallel options to purchase up to an aggregate of
500,000 shares of common stock. Options granted under the plan will not be incentive
stock options within the meaning of the Internal Revenue Code. |
|
|
|
|
Under provisions of the plan, the option exercise price must be the fair market value
of the stock subject to the option on the grant date. Options are not transferable
other than by will or the laws of descent and distribution. |
|
|
|
|
Options may not be granted under this plan after May 2, 2011. However, as of August
23, 2005, no shares of common stock were available for future option grants under this
plan. |
|
|
|
|
At December 31, 2008, options to purchase 125,000 shares of common stock were
outstanding under this plan. |
|
|
|
|
2001 Employee Stock Option Plan. In June 2001, our Board of Directors
adopted the 2001 Employee Stock Option Plan. This plan authorized the grant of options
to purchase up to 200,000 shares of common stock, or less than 1.00% of our
outstanding shares of common stock. Directors and officers are not eligible to receive
options under this plan. Only employees are eligible to receive options. Stock options
granted under this plan are not incentive stock options. |
|
|
|
|
This plan was implemented without stockholder approval. |
|
|
|
|
Under provisions of the plan, the purchase price of common stock issued under each
option must not be less than the fair market value of the common stock at the time of
grant. Options granted under this plan are not transferable other than by will or the
laws of descent and distribution. |
|
|
|
|
The Employee Stock Option Plan will expire on June 20, 2011. However, as of June 20,
2001, no shares of common stock were available for future option grants under this
plan. |
|
|
|
|
At December 31, 2008, options to purchase 124,000 shares of common stock were
outstanding under this plan. |
|
|
|
|
2004 Non-Employee Director Stock Grant Plan. The 2004 Non-Employee
Directors Stock Grant Plan was approved by the Companys stockholders at the annual
meeting of stockholders held in June 2004. Under this plan, each non-employee Director
is entitled to receive an annual retainer fee consisting of shares of common stock
that will be automatically granted on the first day of July in each year. The total
number of shares of common stock initially available for grant under the plan was
116,000 shares, subject to adjustment as described in the plan. The plan will remain
in effect until terminated by the Board, although no additional share of common stock
may be issued after the 116,000 shares subject to the plan have been issued. |
|
|
|
|
Under provisions of the plan, the purchase price of common
stock issued under each option must not be less than the fair market
value of the common stock at the time of grant. Options granted under
this plan are not transferable other than by will or the laws of
descent and distribution. |
F-36
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
|
As of December 31, 2008, the Company had 69,808 remaining shares of common stock
available to issue to directors under this plan. |
|
|
|
2008 Long-Term Incentive Plan. The Companys 2008 Long-Term Incentive Plan
was approved by the Companys stockholders at the annual meeting of stockholders held
on May 28, 2008. This plan provides for granting of nonqualified and incentive stock
options, restricted stock awards, performance awards and other awards to selected
officers, employees, consultants and outside directors. The maximum number of
shares of common stock that may be delivered pursuant to awards granted under the plan
is 2,000,000 shares. |
|
|
|
|
The option price for shares of common stock that may be purchased under a nonqualified
or incentive stock option must be at least equal to the fair market value of the shares
on the date of grant. The exercise price of an option may be paid in cash, in shares of
Parallels common stock or a combination of both. Unless terminated earlier, stock
options granted under the plan expire no more than ten years from the date of the
grant. |
|
|
|
|
The plan will remain in effect until May 28, 2018, unless sooner terminated by the
Board of Directors of the Company. No award may be made under the plan after its
expiration date. No awards under the plan may be repriced or exchanged for awards with
lower exercise prices because of a drop in market prices since grant, unless such
repricings or exchanges are approved by the stockholders of the Company. |
|
|
|
|
At December 31, 2008, options to purchase 355,000 shares of common stock were
outstanding under this plan and 1,627,352 shares were available for future awards. |
|
|
(b) |
|
Stock Options |
|
|
|
|
For the twelve months ended December 31, 2008, 2007 and 2006, the Company recognized
compensation expense of approximately $1.3 million, $247,000 and $531,000 with tax
benefits of approximately $449,000, $84,000 and $181,000, respectively, associated with
its stock option grants. |
|
|
|
|
During June 2007, the Company revised its estimate of expected forfeitures of stock
options granted to directors due to the resignation of a director and the subsequent
forfeiture of 40,000 stock options held by the director. As a result, the Company revised
its estimate of the grant date fair value of shares expected to ultimately vest under its
stock option plan by approximately $283,000. As a consequence, general and administrative
expenses during the three months ended June 30, 2007 were reduced by approximately
$154,000 which included a cumulative adjustment for amounts previously expensed and
associated with options estimated to be forfeited or surrendered. |
F-37
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A summary of the Companys employee stock options as of December 31, 2008, 2007 and 2006,
and changes during the years ended on those dates is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended |
|
|
Year ended |
|
|
Year ended |
|
|
|
December 31, 2008 |
|
|
December 31, 2007 |
|
|
December 31, 2006 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
average |
|
|
|
|
|
|
average |
|
|
|
|
|
|
average |
|
|
|
|
|
|
|
exercise |
|
|
|
|
|
|
exercise |
|
|
|
|
|
|
exercise |
|
|
|
Options |
|
|
price |
|
|
Options |
|
|
price |
|
|
Options |
|
|
price |
|
|
|
(in thousands) |
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Stocks options: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at
beginning of year |
|
|
558 |
|
|
$ |
7.03 |
|
|
|
1,199 |
|
|
$ |
5.40 |
|
|
|
1,405 |
|
|
$ |
5.22 |
|
Granted |
|
|
355 |
|
|
|
21.02 |
|
|
|
18 |
|
|
|
22.89 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(174 |
) |
|
|
4.23 |
|
|
|
(619 |
) |
|
|
3.98 |
|
|
|
(176 |
) |
|
|
4.35 |
|
Surrendered |
|
|
|
|
|
|
|
|
|
|
(40 |
) |
|
|
12.27 |
|
|
|
(30 |
) |
|
|
3.09 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at
end of year |
|
|
739 |
|
|
$ |
14.41 |
|
|
|
558 |
|
|
$ |
7.03 |
|
|
|
1,199 |
|
|
$ |
5.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at
end of year |
|
|
293 |
|
|
$ |
7.30 |
|
|
|
420 |
|
|
$ |
5.39 |
|
|
|
1,001 |
|
|
$ |
4.32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average
fair value of options
granted during the year |
|
|
|
|
|
$ |
10.63 |
|
|
|
|
|
|
$ |
12.45 |
|
|
|
|
|
|
$ |
|
|
The following table summarizes information about the Companys employee stock options
outstanding and exercisable at December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
Intrinsic |
|
|
|
Remaining Life |
|
|
Value |
|
|
|
|
|
|
|
(in thousands) |
|
Stock options outstanding
as of December 31, 2008 |
|
|
8.8 |
|
|
$ |
|
|
|
|
|
|
|
|
|
Currently exercisable
as of December 31, 2008 |
|
|
4.6 |
|
|
$ |
|
|
|
|
|
|
|
|
|
The following table presents the future stock-based compensation expense for the
Companys outstanding stock options which it expects to recognize during the indicated
vesting periods:
|
|
|
|
|
|
|
|
|
($ in thousands) |
2009 |
|
$ |
1,534 |
2010 |
|
|
789 |
2011 |
|
|
375 |
2012 |
|
|
105 |
|
|
|
Total |
|
$ |
2,803 |
|
|
|
The
fair value of each option award is estimated on the date of grant. The fair values of
stock options were determined using the Black-Scholes option valuation method and the
assumptions noted in the following table. Expected volatilities are based on implied
volatilities from traded options and historical volatility of our stock. The expected
term of the options granted used in
F-38
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the Black-Scholes model represent the period of time
that options granted are expected to be outstanding. The Company utilizes the simplified
method for calculating the expected life of its options as the Company does not have
sufficient historical data to provide a basis upon which to estimate term. As illustrated
in Staff Accounting Bulletin 107, the simplified method for calculating the expected life is ((vesting term + original contractual term)/2). Risk
free rates are based on the U.S. Treasury, Daily Treasury Yield Curve Rate.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2005 |
|
2001 |
Expected volatility |
|
|
46.50 |
% |
|
|
52.52 |
% |
|
|
54.20 |
% |
|
|
57.95 |
% |
|
Expected dividends |
|
|
0.00 |
|
|
|
0.00 |
|
|
|
0.00 |
|
|
|
0.00 |
|
|
Expected term (in years) |
|
|
6.25 |
|
|
|
5.75 |
|
|
|
6.5 |
|
|
|
7.5 |
|
|
Risk free rate |
|
|
3.81%-3.86 |
% |
|
|
4.89 |
% |
|
|
4.20 |
% |
|
|
5.05 |
% |
|
|
|
|
|
|
|
($ in thousands) |
Intrinsic Value of Options Exercised Year Ended December 31, 2008 |
|
$ |
2,336 |
|
Intrinsic Value of Options Exercised Year Ended December 31, 2007 |
|
$ |
10,071 |
|
Intrinsic Value of Options Exercised Year Ended December 31, 2006 |
|
$ |
2,855 |
|
|
|
|
|
|
Fair Market Value of Options Granted Year Ended December 31, 2008 |
|
$ |
3,774 |
|
Fair Market Value of Options Granted Year Ended December 31, 2007 |
|
$ |
218 |
|
Fair Market Value of Options Granted Year Ended December 31, 2006 |
|
$ |
|
|
|
|
|
|
|
Average Weighted Grant Date Fair Value of Options
Issued and Unvested, December 31, 2008 |
|
$ |
4,383 |
|
Average Weighted Grant Date Fair Value of Options
Issued and Outstanding, December 31, 2008 |
|
$ |
5,618 |
|
|
(c) |
|
Restricted Stock |
|
|
|
|
On June 12, 2008, 10,000 shares of restricted stock were awarded to a non-employee
director under the Companys 2008 Long-Term Incentive Plan. The fair value of the
restricted stock award was approximately $209,000 and based on the last sales price of
the Companys common stock on the Nasdaq Global Market on the date of grant. For the
twelve months ended December 31, 2008 the Company recognized compensation expense of
approximately $106,000 for restricted stock. These shares vest in four equal increments
on June 12th of each year, commencing on June 12, 2008. |
|
|
|
|
The following table presents future stock-based compensation expense for the restricted stock
award, which we expect to recognize during the indicated vesting periods: |
|
|
|
|
|
|
|
($ in thousands) |
|
2009 |
|
$ |
67 |
|
2010 |
|
|
29 |
|
2011 |
|
|
7 |
|
|
|
|
|
Total |
|
$ |
103 |
|
|
|
|
|
F-39
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A summary of restricted stock activity as of December 31, 2008 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
|
|
|
|
Remaining |
|
|
|
|
|
|
|
Award Date |
|
|
Contractual |
|
|
|
Restricted Stock |
|
|
Fair Value |
|
|
Term |
|
|
|
|
|
|
|
|
|
|
|
(years) |
|
Outstanding December 31, 2007 |
|
|
|
|
|
$ |
|
|
|
|
|
|
Granted |
|
|
10,000 |
|
|
$ |
20.91 |
|
|
|
|
|
Vested |
|
|
(2,500 |
) |
|
$ |
20.91 |
|
|
|
|
|
Surrendered |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested shares at December 31, 2008 |
|
|
7,500 |
|
|
$ |
20.91 |
|
|
|
1.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(d) |
|
Stock Awards |
|
|
|
|
For the twelve months ended December 31, 2008, 2007 and 2006, the Company recognized
compensation expense of approximately $253,000, $96,000 and $118,000 associated with
restricted stock awards. |
|
|
|
|
Effective July 1, 2004, the Company began paying an annual retainer fee to each
non-employee Director in the form of shares of the Companys common stock. Under the 2004
Non-Employee Director Stock Grant Plan, each non-employee Director is entitled to receive
an annual retainer fee in the form of shares of common stock having a value of $25,000.
The shares of stock are automatically granted on the first day of July in each year. The
Company has 69,808 remaining shares of common stock available to issue to directors under
this arrangement. |
|
|
|
|
On July 1, 2008, each of our four non-employee directors were awarded 1,153 shares of
common stock under our 2004 Non-Employee Director Stock Grant Plan. The fair value of
common stock awarded of $20.25 per share was based on the average of the high and low
sales price of our common stock on the Nasdaq Global Market on the date of grant. The
shares vested 100% on the date of the grant. |
|
|
|
|
On July 1, 2007, each of our four non-employee directors were awarded 1,100 shares of
common stock under our 2004 Non-Employee Director Stock Grant Plan. The fair value of
common stock awarded of $21.79 per share was based on the average of the high and low
sales price of our common stock on the Nasdaq Global Market on the date of grant. The
shares vested 100% on the date of the grant. |
|
|
|
|
On July 1, 2006, each of our four non-employee directors were awarded 1,174 shares of
common stock under our 2004 Non-Employee Director Stock Grant Plan. The fair value of
common stock awarded of $25.23 per share was based on the average of the high and low
sales price of our common stock on the Nasdaq Global Market on the date of grant. The
shares vested 100% on the date of the grant. |
|
|
|
|
From time to time the Board of Directors authorizes stock awards to the non-employee
directors for compensation other than the annual retainer. On June 12, 2008, each of our
four non-employee directors was awarded 1,912 shares of common stock under our 2008
Long-Term Incentive Plan. The fair value of the common stock awarded of $20.91 per share
was based on the last sales price of our common stock on the Nasdaq Global Market on the
date of grant. The shares vested 100% on the date of the grant. |
F-40
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
(e) |
|
Stock Warrants |
|
|
|
|
The Company had 300,030 warrants outstanding at December 31, 2007, which were issued as
part of the Companys initial public offering in 1980. Each warrant allowed the holder to
buy one share of common stock for $6.00. The warrants were exercisable for a 30 day
period commencing on the date a registration statement covering exercise was declared
effective. The warrants contained antidilution provisions. On April 15, 2008, the
Companys registration statement relating to 300,030 shares of common stock issuable upon
the exercised of outstanding warrants was declared effective by the Securities and
Exchange Commission. The warrants were exercisable at $6.00 per share at any time on or
before 5:00 p.m., Mountain Time, on May 15, 2008, at which time the warrants expired.
Between April 15, 2008 and May 15, 2008 a total of 148,757 warrants were exercised for
net proceeds of approximately $796,000. Warrants to purchase 151,273 shares were not
exercised and expired by their terms on May 15, 2008. |
|
|
|
|
The Company had 100,000 warrants outstanding at July 11, 2007 and December 31, 2006 which
were issued as partial payment for services rendered for financial and investment advice
for the Companys private placement offering in December, 2003. The warrants had a term
of five years from date of issuance and vesting period of one year. The warrants had an
exercise price of $3.98 per share and contained a provision for cashless exercise. The
fair value related to these warrants in the amount of $157,000 was recorded in other
expenses in 2003 based on the estimated fair value on the date of grant using the
Black-Scholes option pricing model. The holders of these warrants elected to exercise
during 2007 through cashless exercise as allowed under the terms of the warrants. As a
result, 82,734 common shares were issued to the warrant holders. |
|
|
(f) |
|
Stock Rights |
|
|
|
|
On October 5, 2000, the board of directors adopted a Stockholder Rights Plan (the Plan)
and declared a dividend of one Stock Right for each outstanding share of the Companys
common stock. Generally, the Plan is designed to protect the Company from unfair or
coercive takeover attempts, prevent a potential acquiror from gaining control of the
Company without fairly compensating all of the Companys stockholders, and encourage
third parties that may have an interest in acquiring the Company to negotiate with the
Companys board of directors. In particular, the Plan is intended to (i) reduce the risk
of coercive or partial tender offers that may not offer fair value to all stockholders;
(ii) deter purchasers who through open market or private purchase may attempt to achieve
a position of substantial influence or control over the Company without paying a fair
control premium to selling or remaining stockholders; and (iii) preserve the board of
directors bargaining power and flexibility to deal with acquirors and otherwise to seek
to maximize value for all stockholders. The Plan is intended to achieve these goals by
confronting a potential acquiror of the Companys common stock with the possibility that
the Company or its stock-holders will be able to substantially dilute the acquirors
equity interest by using the Stock Rights to acquire additional Company common stock, or
in certain cases stock of the acquiror, at a 50% discount. |
|
|
|
|
If a person acquires 15% or more of the Companys common stock or a tender offer or
exchange offer is made for 15% or more of the common stock, each Stock Right will entitle
the holder to purchase from the Company one one-thousandth of a share of Series A
Preferred Stock, par value $0.10 per share, at an exercise price of $26.00 per one
one-thousandth of a share, subject to adjustment. |
F-41
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Initially, the Stock Rights attach to all common stock certificates representing shares
then outstanding, and no separate Stock Rights certificates will be distributed. The
Stock Rights separate from the common stock upon the earlier of (1) ten business days
following a public announcement that a person or group of affiliated or associated
persons has acquired or obtained the right to acquire, beneficial ownership of 15% or
more of the outstanding shares of common stock or (2) ten business days (or such later
date as the board of directors shall determine) following the commencement of a tender or
exchange offer that would result in a person or group beneficially owning 15% or more of
such outstanding shares of common stock. The date the Stock Rights separate is referred
to as the distribution date.
Under certain circumstances the Stock Rights entitle the holders to buy shares of the
acquirers common stock at a 50% discount. In the event that, at any time after a person
has acquired 15% or more of the Companys common stock, (1) the Company enters into a
merger or other business combination transaction in which the Company is not the
surviving corporation; (2) the Company is the surviving corporation in a transaction in
which all or part of the common stock is exchanged for cash, property or securities of
any other person; or, (3) more than 50% of the assets, cash flow or earning power of the
Company is sold, each right holder will have the option to buy for the purchase price
stock of the acquiring company having a value equal to two times the purchase price of
the Stock Right.
The Stock Rights are not exercisable until the distribution date and will expire at the
close of business on October 5, 2010, unless earlier redeemed by the Company for $0.001
per Stock Right.
At issuance, the Stock Rights had no determinable value and, therefore, no accounting
entry was required. The Stock Rights have not had, nor does the Company anticipate that
the Stock Rights will have, a material effect on its results of operations.
(14) |
|
Related Party Transactions |
|
|
|
In December, 2001, and prior to his employment with Parallel, Donald E. Tiffin, Parallels
Chief Operating Officer, received a 3% working interest from an unaffiliated third party in
the Diamond M Project in Scurry County, Texas for services rendered in connection with
assembling the project. In August, 2002, shortly after his employment with Parallel, and due
to the personal financial exposure in the Diamond M Project and to prevent the interest from
being acquired by a third party, Mr. Tiffin assigned two-thirds of his ownership interest in
the project to Parallel at no cost, leaving him with a 1% working interest. Parallel acquired
its initial interest in the Diamond M Project in December, 2001. In 2008, 2007 and 2006, the
Company charged approximately $95,000, $45,000 and $111,000, respectively, for capital
expenditures and lease operating expenses and paid approximately $116,000, $65,000 and
$100,000, respectively, in oil and natural gas revenues related to this project. In
addition, $5,000 of this balance was for outstanding joint interest billings to an executive
officer as of December 31, 2007. This receivable was collected within one month of billing. |
|
|
|
As of December 31, 2008 and 2007, the Company had accounts receivable of $12,000 and $4.0
million, respectively, from affiliates. Joint interest receivables from a joint interest
owner (who was also a joint venture partner in Hagerman) represented $0 and $3.4 million of
these balances at December 31, 2008 and 2007, respectively. |
F-42
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(15) |
|
Major Customers and Concentrations |
|
|
|
The following purchasers and operators accounted for 10% or more of the Companys oil and natural
gas sales for the years ended December 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
2007 |
|
2006 |
Chesapeake Operating, Inc. |
|
|
22 |
% |
|
|
12 |
% |
|
|
(1) |
|
Conoco, Inc. |
|
|
18 |
% |
|
|
21 |
% |
|
|
20 |
% |
Dale Operating Company |
|
|
(1) |
|
|
|
(1) |
|
|
|
10 |
% |
Occidental Energy Marketing |
|
|
10 |
% |
|
|
(1) |
|
|
|
(1) |
|
Texland Petroleum, Inc. |
|
|
29 |
% |
|
|
30 |
% |
|
|
30 |
% |
Tri-C Resources, Inc. |
|
|
(1) |
|
|
|
(1) |
|
|
|
12 |
% |
|
|
A substantial portion of Parallels oil and natural gas reserves and production are located
in the Permian Basin and the Fort Worth Basin. The Company may be disproportionally exposed
to the impact of delays of interruptions of production from these wells due to mechanical
problems, damages to the current producing reservoirs and significant governmental
regulations, including any curtailment of production or interruption of transportation of oil
or natural gas produced from these wells. |
|
|
|
The Company manages the credit risk associated with its largest customers by using a credit
risk monitoring tool to actively monitor credit ratings, including S&P and Moodys, financial
statement filings, financial position, bankruptcy filings and current news. |
|
(16) |
|
Commitments and Contingencies |
|
|
|
On April 14, 2008, the Company was added as a defendant to a lawsuit filed in 2007, styled
Brady Briscoe vs. Capstar Drilling, L.P. (Capstar), Cause No. 21,287, in the 259th
District Court of Jones County, Texas. The plaintiff alleged that he was injured as the
result of an accident while he was working, as an employee of an unrelated third party, on a
drilling rig operated by Capstar. Capstar was conducting drilling operations for the
Company. The plaintiff asserted general allegations of negligence as to Capstar and,
specifically, a failure to properly equip its drilling rig, further alleging the Company was
in charge of the drilling rig and the operational details of the plaintiffs work. The
plaintiff sued for an amount of actual damages of up to $15.0 million, together with
pre-judgment interest, post-judgment interest and exemplary damages. Capstar recently
settled with the plaintiff and Capstar was dismissed from the lawsuit. If judgment is
entered against the Company, it would be entitled to a credit for the amount that the
plaintiff has already received from Capstar. On November 13, 2008, the plaintiff, filed
notice of non-suit, without prejudice, of all claims and causes of action asserted against
the Company. |
|
|
|
On March 24, 2008, a lawsuit was filed in the 24th District Court of Jackson
County, Texas, against the Company and twenty-two other defendants in Cause No. 07-6-13069,
styled Tony Kubenka, Carolyn Kubenka, Dennis J. Kallus, David J. Kallus, Mary L. Kallus,
Patricia Kallus, Nova Deleon, Janie Figuerova, and Larkin Thedford, Plaintiffs v. Tri-C
Resources, Inc., Marie S. Adian, Laura E. Adian, Glenn A. Fiew, Lynn Kramer, Debra Boysen,
Carol J. Gleason, Alana Sue Curlee, Connie W. Marthiljohni, Claire E. Adian, Zachary D.
Adian, Donald R. Starkweather, Inc., D.A. Webernick, Danette Bundick, Johnny A. Webernick,
Donna Gail Glover, Sherry Shulze, William H. Webernick, Jr., TAC Resources, Inc., New Century
Exploration, Inc., Allegro Investments, Inc., |
F-43
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Parallel Petroleum Corporation and Welper
Interests, LP. The nine plaintiffs in this lawsuit have named the Company and the other
working interest owners, including Tri-C Resources, Inc., the operator, as defendants. The
plaintiffs in this lawsuit allege that they are royalty owners under oil and gas leases which
are part of a pooled gas unit (the unit) located in Jackson County, Texas, and that the
defendants, including the Company, are owners of the leasehold estate under the plaintiffs
leases and others forming the unit. Plaintiffs also assert that one of the leases (other
than plaintiffs leases) forming part of the unit has been terminated and, as a result, the
defendants have not properly computed the royalties due to plaintiffs from unit production
and have failed to properly pay royalties due to them. Plaintiffs have sued for an
unspecified amount of damages, including exemplary damages, under theories of breach of
contract (including breach of express and implied covenants of their leases) and conversion,
and seek an accounting, a declaratory judgment to declare the rights of the parties under the
leases, and attorneys fees, interest and court costs. If a judgment adverse to the
defendants were entered, as a working interest owner in the leases comprising the unit, we
believe our liability would be proportionate to the ownership of the other working interest
owners in the leases. The Company has filed an answer denying any liability. Although an
initial exchange of discovery has occurred, the Company cannot predict the ultimate outcome
of this matter, but believe we have it has meritorious defenses and intend to vigorously
contest this lawsuit. The Company has not established a reserve with respect to plaintiffs
claims.
The Company received a Notice of Proposed Adjustment from the Internal Revenue Service, or
the Service in May 2007 advising it of proposed adjustments to federal income tax of
approximately $2.0 million for the years 2004 and 2005. Subsequent discussions with the
Service placed the issues contested in a development status. In November 2007, the Service
issued a letter on the matter giving the company 30 days to agree or disagree with a final
examination report. The final examination report reflected revisions of the previous
proposed adjustments resulting in a reduced $1.1 million of additional income tax and
interest charges. The decrease in proposed tax was the result of information supplied by the
Company to the examiner as well as discussions of the applicable tax statutes and
regulations. In December 2007, the Company filed a protest documenting its complete
disagreement with the adjustments proposed on the final examination report and requested a
conference with the appeals office of the Service. The examination office of the Service
filed a response to the Companys protest in February 2008 with the appeals office. In the
response the additional tax was further reduced by the examination office to $720,000. In
June and November of 2008, the Companys representatives met with the Services Appeals
Officer to review specific issues related to the alternative minimum tax items in dispute.
During these meetings the Company submitted supplements to its initial protest in further
support of the Companys position. Currently the IRS appeals office is considering the
Companys information as well as data supplied at the request of the appeals officer. The
Company intends to vigorously contest the adjustment proposed by the Service and believe that
it will ultimately prevail in its position. The Company has not recorded a liability for
tax, interest, or penalties related to this matter based on its analysis. If a liability for
additional income tax should later be determined to be more likely than not, the Company
anticipates the adjustment to increase the federal income tax liability would be offset by
an increase to a deferred tax asset and would not result in a charge to earnings. Any
interest or penalties resulting from a subsequent determination of increased tax liability
would require a charge to earnings. The Company believes that the effects of this matter
would not have a material effect on its results of operations for the fiscal quarter in which
the Company actually incurs or establishes a reserve account for interest or penalties.
The Company is also presently a named defendant in one other lawsuit arising out of its
operations in the normal course of business, which the Company believes is not material.
F-44
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
On January 1, 2005 the Company established a 401(k) Plan and Trust for eligible employees.
During 2008, 2007 and 2006, the Company contributed an aggregate of approximately $317,000,
$274,000 and $240,000, respectively, to the 401(k) Plan. |
|
|
|
The Company leases office space under two non-cancelable operating leases with one expiring
in 2010 and the second lease expiring in 2011. Future annual payments under these operating
leases are approximately $271,000, $107,000 and $31,000 for the years ending December 31,
2009 through May 31, 2011, respectively. Rental expense under the Companys current leases
totaled approximately $240,000, $200,000 and $194,000 for the years ended December 31, 2008,
2007, and 2006, respectively. |
|
|
|
The Company has three field offices and storage facilities. These facilities are located in
Andrews and Snyder, Texas and Hagerman, New Mexico. Rental expense totaled approximately
$6,000, $23,000 and $23,000 for the years ended December 31, 2008, 2007 and 2006,
respectively. |
|
|
|
The Company has an Incentive and Retention Plan which provides for the payment to eligible
officers and employees of a one time performance bonus and retention payment upon the
occurrence of a change of control as defined in the Plan. Because of the uncertainty of the
occurrence of a change of control or corporate transaction within the meaning of the plan,
the amount of these bonuses is undeterminable. As of December 31, 2008, the per share closing
price of the Companys stock was $2.01. This closing price is under the base of $3.73 and
$8.62. Therefore, the officers and employees would not receive any monetary compensation
under this plan. |
|
|
|
In January 2006, the Company adopted a Non-officer Employee Severance Plan for the purpose of
providing the Companys non-officer employees with an incentive to remain employed with the
Company. This Plan provides for a one-time severance payment to the non-officer employees
equal to one year of their then current base salary upon the occurrence of a change of
control within the meaning of the Plan. Based on the aggregate non-officer base salaries in
effect as of December 31, 2008, the total severance amount payable under the plan would have
been approximately $4.4 million. |
|
(17) |
|
Supplemental Oil and Natural Gas Reserve Data (Unaudited) |
|
|
|
The Company has presented the reserve estimates utilizing an oil price of $40.00, $89.93 and
$54.67 per Bbl and a natural gas price of $5.18, $6.77 and $5.00 per Mcf as of December 31,
2008, 2007 and 2006, respectively. Information for oil is presented in barrels (Bbl) and for
natural gas in thousands of cubic feet (Mcf). |
|
|
|
The estimates of the Companys proved oil and natural gas reserves and related future net
cash flows that are presented in the following tables are based upon estimates made by
independent petroleum engineering consultants as of December 31, 2008, 2007 and 2006. The
Company cautions that there are many inherent uncertainties in estimating proved reserve
quantities, projecting future production rates, and timing of development expenditures.
Accordingly, these estimates are likely to change as future information becomes available.
Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas
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 reserves are those reserves expected to be recovered through existing wells,
with existing equipment and operating methods. |
F-45
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A summary of changes in reserve balances is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Condensate (Bbls) |
|
|
For the Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
(In thousands) |
Proved developed and undeveloped reserves |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
|
28,434 |
|
|
|
28,721 |
|
|
|
21,192 |
|
Purchase of oil and natural gas properties |
|
|
1,839 |
|
|
|
|
|
|
|
3,270 |
|
Sales of oil and natural gas properties |
|
|
(1 |
) |
|
|
(75 |
) |
|
|
|
|
Extensions and discoveries |
|
|
243 |
|
|
|
1,146 |
|
|
|
8,182 |
|
Revisions of previous estimates |
|
|
(8,282 |
) |
|
|
(307 |
) |
|
|
(2,786 |
) |
Production |
|
|
(1,027 |
) |
|
|
(1,051 |
) |
|
|
(1,137 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year |
|
|
21,206 |
|
|
|
28,434 |
|
|
|
28,721 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves at year end |
|
|
12,137 |
|
|
|
14,378 |
|
|
|
14,932 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (MCF) |
|
|
For the Year Ended December 31, |
|
|
2008 |
|
2007 |
|
2006 |
|
|
(In thousands) |
Proved developed and undeveloped reserves |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
|
57,234 |
|
|
|
58,896 |
|
|
|
25,237 |
|
Purchase of oil and natural gas properties |
|
|
1,008 |
|
|
|
|
|
|
|
4,355 |
|
Sales of oil and natural gas properties |
|
|
(188 |
) |
|
|
(3,105 |
) |
|
|
|
|
Extensions and discoveries |
|
|
24,105 |
|
|
|
25,905 |
|
|
|
38,159 |
|
Revisions of previous estimates |
|
|
618 |
|
|
|
(17,040 |
) |
|
|
(2,316 |
) |
Production |
|
|
(10,944 |
) |
|
|
(7,422 |
) |
|
|
(6,539 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year |
|
|
71,833 |
|
|
|
57,234 |
|
|
|
58,896 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves at year end |
|
|
55,751 |
|
|
|
41,556 |
|
|
|
28,741 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company made significant acquisitions in 2006 that resulted in additions to its estimated
proved reserves for that year. In 2006, the Company acquired additional interests in Harris
San Andres Field located in Andrews and Gaines Counties, Texas. Also in 2006, the Company
purchased additional interests in the Barnett Shale Gas Project located in Tarrant County,
Texas. In 2008, the Company exercised a preferential right and purchased the interest owned
by an unrelated third party, in its operated Diamond M properties in Scurry County, Texas
that resulted in additions to its estimated proved reserves for that year.
The Companys drilling programs over the last three years have resulted in significant
natural gas discoveries and extensions in the Companys Barnett Shale resource natural gas
project and the Companys New Mexico projects. Over this same time period, the Companys
drilling in the Carm-Ann, Harris and Diamond M fields of west Texas resulted in significant
increases in extensions and discoveries in the Companys oil reserves.
The Company experienced downward revisions in estimated proved natural gas reserves in 2007.
This was the result of two factors. First, the Company changed its method of recognizing
proved undeveloped reserves related to its horizontal drilling of natural gas projects in
March 2007. Under this new method, which the Company believes conforms with regulatory
requirements applicable to horizontal well reserve booking practices for publicly owned
exploration and production companies, estimates of proved undeveloped reserves from
horizontal wells are limited to two
F-46
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
parallel offset wells to a productive horizontal well,
unless productive continuity is demonstrated through pressure communication between wells
more than an offset location away and on either side of a future horizontal well. Secondly,
the Company adjusted its reserve estimates on certain New Mexico Wolfcamp and Barnett Shale
wells where performance did not meet 2007 production estimates.
The Company experienced downward revisions in estimated proved crude oil in 2008. These
downward revisions were as a result of crude oil prices utilized for the reserve estimate
decreasing by 56% between year-end 2007 and year-end 2008.
The following is a standardized measure of the discounted net future cash flows and changes
applicable to proved oil and natural gas reserves required by SFAS No. 69, Disclosures about
Oil and Gas Producing Activities". The future cash flows are based on estimated oil and
natural gas reserves utilizing prices and costs in effect as of year end, discounted at 10%
per year and assuming continuation of existing economic conditions.
The standardized measure of discounted future net cash flows, in managements opinion, should
be examined with caution. The basis for this table is the reserve studies prepared by
independent petroleum engineering consultants, which contain imprecise estimates of
quantities and rates of production of reserves. Revisions of previous year estimates can have
a significant impact on these results. Also, exploration costs in one year may lead to
significant discoveries in later years and may significantly change previous estimates of
proved reserves and their valuation. Therefore, the standardized measure of discounted future
net cash flow is not necessarily indicative of the fair value of the Companys proved oil and
natural gas properties.
Future income tax expense was computed by applying statutory rates less the effects of tax
credits for each period presented to the difference between pre-tax net cash flows relating to
the Companys proved reserves and the tax basis of proved properties and available net
operating loss and percentage depletion carryovers.
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
Future cash inflows |
|
$ |
1,220,173 |
|
|
$ |
2,944,746 |
|
|
$ |
1,864,860 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future costs: |
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(535,074 |
) |
|
|
(824,261 |
) |
|
|
(606,138 |
) |
Development |
|
|
(92,001 |
) |
|
|
(117,981 |
) |
|
|
(138,715 |
) |
Future income taxes |
|
|
(20,782 |
) |
|
|
(536,227 |
) |
|
|
(292,954 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
572,316 |
|
|
|
1,466,277 |
|
|
|
827,053 |
|
10% annual discount for estimated timing of cash flows |
|
|
(264,396 |
) |
|
|
(831,839 |
) |
|
|
(490,565 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
307,920 |
|
|
$ |
634,438 |
|
|
$ |
336,488 |
|
|
|
|
|
|
|
|
|
|
|
F-47
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Changes in Standardized Measure of
Discounted Future Net Cash Flows From Proved Reserves
($ in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
Increase (decrease): |
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of minerals in place |
|
$ |
20,149 |
|
|
$ |
|
|
|
$ |
20,698 |
|
Extensions and discoveries and improved recovery,
net of future production and development costs |
|
|
45,387 |
|
|
|
97,918 |
|
|
|
104,622 |
(1) |
Accretion of discount |
|
|
88,392 |
|
|
|
46,996 |
|
|
|
47,281 |
|
Net change in sales prices net of production costs |
|
|
(537,396 |
) |
|
|
341,421 |
|
|
|
(78,387 |
) |
Changes in estimated future development costs |
|
|
43,696 |
|
|
|
28,424 |
|
|
|
12,726 |
|
Revisions of quantity estimates |
|
|
(87,091 |
) |
|
|
(64,408 |
) |
|
|
(44,561 |
) |
Net change in income taxes |
|
|
245,791 |
|
|
|
(116,010 |
) |
|
|
(21,452 |
) |
Sales, net of production costs |
|
|
(147,284 |
) |
|
|
(89,818 |
) |
|
|
(86,130 |
) |
Changes of production rates (timing) and other |
|
|
1,838 |
|
|
|
53,427 |
|
|
|
20,901 |
(1) |
|
|
|
|
|
|
|
|
|
|
Net increase |
|
|
(326,518 |
) |
|
|
297,950 |
|
|
|
(24,302 |
) |
Standardized measure of discounted future net cash flows: |
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year |
|
|
634,438 |
|
|
|
336,488 |
|
|
|
360,790 |
|
|
|
|
|
|
|
|
|
|
|
End of year |
|
$ |
307,920 |
|
|
$ |
634,438 |
|
|
$ |
336,488 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
During 2006, the Company revised its method of calculating Extensions and
discoveries and improved recovery, net of future production and development costs. |
F-48
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(18) |
|
Selected Quarterly Financial Data (Unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter |
|
|
|
First |
|
|
Second |
|
|
Third |
|
|
Fourth |
|
|
|
($ in thousands, except per share data) |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
43,941 |
|
|
$ |
56,075 |
|
|
$ |
56,201 |
|
|
$ |
26,298 |
|
Total costs and expenses |
|
|
21,188 |
|
|
|
23,998 |
|
|
|
25,051 |
|
|
|
322,524 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
22,753 |
|
|
|
32,077 |
|
|
|
31,150 |
|
|
|
(296,226 |
)(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges |
|
$ |
(21,886 |
) |
|
$ |
(71,609 |
) |
|
$ |
65,661 |
|
|
$ |
59,852 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(2,740 |
) |
|
$ |
(29,205 |
) |
|
$ |
58,677 |
|
|
$ |
(158,626 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share basic |
|
$ |
(0.07 |
) |
|
$ |
(0.70 |
) |
|
$ |
1.41 |
|
|
$ |
(3.81 |
)(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share diluted |
|
$ |
(0.07 |
) |
|
$ |
(0.70 |
) |
|
$ |
1.41 |
|
|
$ |
(3.81 |
)(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenues |
|
$ |
23,116 |
|
|
$ |
27,354 |
|
|
$ |
29,487 |
|
|
$ |
36,074 |
|
Total costs and expenses |
|
|
14,827 |
|
|
|
15,291 |
|
|
|
18,206 |
|
|
|
18,742 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
8,289 |
|
|
|
12,063 |
|
|
|
11,281 |
|
|
|
17,332 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on derivatives not classified as hedges |
|
$ |
(4,435 |
) |
|
$ |
(2,170 |
) |
|
$ |
(4,556 |
) |
|
$ |
(25,615 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(96 |
) |
|
$ |
3,464 |
|
|
$ |
293 |
|
|
$ |
(8,322 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share basic |
|
$ |
|
|
|
$ |
0.09 |
|
|
$ |
0.01 |
|
|
$ |
(0.21 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share diluted |
|
$ |
|
|
|
$ |
0.09 |
|
|
$ |
0.01 |
|
|
$ |
(0.21 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Fourth quarter 2008 results includes a $300.5 million impairment to the Companys
oil and natural gas properties. See Note 5 Oil and Natural Gas Properties. |
(19) |
|
Subsequent Events |
|
|
|
Second Amendment to Credit Agreement. On February 19,
2009, but effective as of December 31, 2008, the Company entered into a
Second Amendment to its Revolving Credit Agreement (the Second Amendment). Generally, the
Second Amendment increased the Companys annual interest rate for Libor loans by one-fourth of
one percent (0.25%). In addition, the Second Amendment modified one of the financial covenants
that the Company must comply with. Before the amendment, the Companys ratio of consolidated
funded debt to consolidated EBITDA (calculated at the end of each fiscal quarter using the
results of the immediately preceding twelve-month period, each a test period) was not
allowed to exceed 4.00 to 1.00. After the Second Amendment, this ratio is not allowed to
exceed 4.25 to 1.00 as of December 31, 2008 and for any test period during 2009 and 2010, or
4.00 to 1.00 during the year 2011 and thereafter. The bank fees
associated with this second amendment to credit agreement were
$575,000. |
F-49
PARALLEL PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Barnett Shale Farmout Agreement. On February 11, 2009, the Company entered into a farmout
agreement with Chesapeake Energy Corporation, or Chesapeake, related to the Companys
approximate 35% interest in the Barnett Shale gas project. Under the farmout agreement, for
all wells drilled on the Companys Barnett Shale leasehold from November 1, 2008 through
December 31, 2016, the Company has agreed to assign to Chesapeake 100% of its leasehold in the
Barnett Shale, subject to the following terms:
|
|
|
all wells drilled from November 1, 2008 through December 31, 2009, and all
wells drilled during each succeeding calendar year through 2016 will be
treated as a separate project or payout period, creating eight separate
projects or payout periods; |
|
|
|
|
at the time Chesapeake commences the drilling of a well during one of the
payout periods, the Company will assign to Chesapeake 100% of its leasehold
interest within the subject unit or lease, reserving and retaining a 50%
reversionary interest that will vest after Chesapeake recovers 150% of its
costs for a particular payout period. Until 150% payout has been reached,
Chesapeake will fund 100% of the Companys costs for drilling, completing and
operating wells during the payout period; |
|
|
|
|
on each project, Chesapeake is entitled to receive all revenues from the
Companys reversionary interest until Chesapeake receives revenues totaling
150% of the drilling, completion and operating costs Chesapeake incurs in
funding the Companys reversionary interest; |
|
|
|
|
upon reaching the 150% payout level for a given project, 50% of the
interest assigned to Chesapeake will revert back to the Company; |
|
|
|
|
after 150% project payout, the Company will pay all costs and receive all
revenues attributable to its 50% reversionary interest in each project; |
|
|
|
|
for wells drilled after January 1, 2017, the Company will pay all costs
and receive all revenues attributable to its 50% reversionary interest; and |
|
|
|
|
the Company will retain all of its interest in wells commenced prior to
November 1, 2008, except for 3 wells commenced in late October 2008. The
Company will retain all of its interest in approximately 90 gross (22.4 net)
producing wells and 31 gross (9.49 net) wells in progress. |
As non-operator, the
Company does not control the timing of investment in the Barnett Shale
gas project. Therefore, the Company entered into the farmout agreement with Chesapeake.
This farmout agreement had minimal effect on the Companys proved reserves as of December
31, 2008.
The Company estimates that its Barnett Shale leasehold acreage operated by Chesapeake and subject
to the farmout agreement is approximately 25,600 gross (9,300 net) acres. The Company anticipates
that approximately 61 gross (10.0 net) wells will be drilled and included in the 2009 payout period
from November 1, 2008 through December 31, 2009. Payout of each project will depend on drilling
and completion costs, timing of completion and pipeline connection to sales, and natural gas
prices, among other things.
Natural Gas Hedge. On February 18, 2009, the Company executed a trade for 10,000 MMBTU/day
natural gas (WAHA) for calendar 2010 costless collars with a floor of $4.75 and a ceiling of
$5.90 with a total volume of 3,650,000 MMBTU.
F-50
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.
|
|
|
|
|
|
PARALLEL PETROLEUM CORPORATION
|
|
February 23, 2009 |
By: |
/s/ Larry C. Oldham
|
|
|
|
Larry C. Oldham |
|
|
|
President and Chief Executive Officer |
|
|
|
|
|
February 23, 2009 |
By: |
/s/ Steven D. Foster
|
|
|
|
Steven D. Foster |
|
|
|
Chief Financial Officer |
|
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.
|
|
|
|
|
/s/ Jeffrey G. Shrader
|
|
Director and Chairman of
|
|
February 23, 2009 |
|
|
the Board of Directors |
|
|
|
|
|
|
|
/s/ Larry C. Oldham
|
|
President and Chief Executive Officer
|
|
February 23, 2009 |
|
|
(Principal Executive Officer) |
|
|
|
|
|
|
|
/s/ Steven D. Foster
|
|
Chief Financial Officer
|
|
February 23, 2009 |
|
|
(Principal Financial and
Accounting Officer) |
|
|
|
|
|
|
|
/s/ Edward A. Nash
Edward A. Nash
|
|
Director
|
|
February 23, 2009 |
|
|
|
|
|
/s/ Martin B. Oring
Martin B. Oring
|
|
Director
|
|
February 23, 2009 |
|
|
|
|
|
/s/ Ray M. Poage
Ray M. Poage
|
|
Director
|
|
February 23, 2009 |
INDEX TO EXHIBITS
(a) Exhibits
|
|
|
No. |
|
Description of Exhibit |
|
|
|
3.1
|
|
Certificate of Incorporation of Registrant (Incorporated by reference to Exhibit 3.1 to Form
10-Q of the Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
3.2
|
|
Bylaws of Registrant (Incorporated by reference to Exhibit 10.1 of the Registrants Current
Report on Form 8-K filed on November 30, 2007) |
|
|
|
3.3
|
|
Certificate of Formation of Parallel, L.L.C. (Incorporated by reference to Exhibit No. 3.3 of
the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.4
|
|
Limited Liability Company Agreement of Parallel, L.L.C. (Incorporated by reference to Exhibit
No. 3.4 of the Registrants Statement on Form S-3, No. 333-119725 filed on October 13, 2004) |
|
|
|
3.5
|
|
Certificate of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit
No. 3.5 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on
October 13, 2004) |
|
|
|
3.6
|
|
Agreement of Limited Partnership of Parallel, L.P. (Incorporated by reference to Exhibit No.
3.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.1
|
|
Certificate of Designations, Preferences and Rights of Serial Preferred Stock 6%
Convertible Preferred Stock (Incorporated by reference to Exhibit 4.1 of Form 10-Q of the
Registrant for the fiscal quarter ended June 30, 2004) |
|
|
|
4.2
|
|
Certificate of Designations, Preferences and Rights of Series A Preferred Stock (Incorporated
by reference to Exhibit 4.2 of Form
10-K of the Registrant for the fiscal year ended December
31, 2000) |
|
|
|
4.3
|
|
Rights Agreement, dated as of October 5, 2000, between the Registrant and Computershare Trust
Company, Inc., as Rights Agent (Incorporated by reference to Exhibit 1 of Form 8-A of the
Registrant filed with the Securities and Exchange Commission on October 10, 2000) |
|
|
|
4.4
|
|
Form of common stock certificate of the Registrant (Incorporated by reference to Exhibit No.
4.6 of the Registrants Registration Statement on Form S-3, No. 333-119725 filed on October
13, 2004) |
|
|
|
4.5
|
|
Warrant Purchase Agreement, dated November 20, 2001, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
4.6
|
|
Warrant Purchase Agreement, dated December 23, 2003, between the Registrant and Stonington
Corporation (Incorporated by reference to Exhibit 4.8 of Form 10-K of the Registrant for the
fiscal year ended December 31, 2004) |
|
|
|
4.7
|
|
Purchase Warrant Agreement, dated as of October 1, 1980, between the Registrant and American
Stock Transfer, Inc. (Incorporated by reference to Exhibit 4.7 of Form 10-K of the Registrant
for the fiscal year ended December 31, 2006) |
|
|
|
4.8
|
|
First Amendment to Warrant Agreement, dated as of February 22, 2007, among the Registrant,
Computershare Shareholder Services, Inc. and Computershare Trust Company, N.A. (Incorporated
by reference to Exhibit 4.8 of Form 10-K of the Registrant for the fiscal year ended December
31, 2006) |
|
|
|
4.9
|
|
Form of Rule 144A 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.2 to the
Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
No. |
|
Description of Exhibit |
|
|
|
4.10
|
|
Form of IAI 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.3 to the
Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.11
|
|
Form of Regulation S 101/4% Senior Note due 2014 (Incorporated by reference to Exhibit 4.4 to
the Registrants Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.12
|
|
Indenture, dated as of July 31, 2007, among the Registrant as Issuer and Wells Fargo Bank,
National Association as Trustee (Incorporated by reference to Exhibit 4.1 to the Registrants
Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.13
|
|
Registration Rights Agreement, dated as of July 31, 2007, by and among the Registrant,
Jefferies & Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP
Paribas Securities Corp. (Incorporated by reference to Exhibit 10.2 to the Registrants
Current Report on Form 8-K filed on August 1, 2007) |
|
|
|
4.14
|
|
Purchase Agreement, dated as of July 26, 2007, by and among the Registrant, Jefferies &
Company, Inc., Merrill Lynch, Pierce, Fenner and Smith Incorporated and BNP Paribas Securities
Corp. (Incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K
filed on August 1, 2007) |
|
|
|
4.15
|
|
Form of 101/4% Unrestricted Senior Note due 2014 (Incorporated by reference to Exhibit 4.13 of
Form S-4 of the Registrant, Registration No. 333-148465) |
|
|
|
|
|
Executive Compensation Plans and Arrangements (Exhibit No.s 10.1 through 10.11): |
|
|
|
10.1
|
|
1992 Stock Option Plan (Incorporated by reference to Exhibit 10.1 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2004) |
|
|
|
10.2
|
|
Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Form 10-Q of the Registrant for the fiscal quarter ended June 30, 2005) |
|
|
|
10.3
|
|
1998 Stock Option Plan (Incorporated by reference to Exhibit 10.4 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.4
|
|
2001 Non-Employee Directors Stock Option Plan (Incorporated by reference to Exhibit 10.7 of
the Registrants Form 10-Q Report for the fiscal quarter ended March 31, 2004) |
|
|
|
10.5
|
|
2004 Non-Employee Director Stock Grant Plan (Incorporated by reference to Exhibit 10.1 of the
Registrants Form 8-K Report dated September 22, 2004) |
|
|
|
10.6
|
|
Incentive and Retention Plan (Incorporated by reference to Exhibit 10.7 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.7
|
|
2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrants
Form 8-K Report dated March 27, 2008) |
|
|
|
10.8
|
|
Form of Nonqualified Stock Option Agreement for nonqualified stock options granted under the
Registrants 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.2 of the
Registrants Current Report on Form 8-K filed on June 18, 2008) |
|
|
|
10.9
|
|
Form of Outside Director Stock Award Agreement for stock awards granted under the
Registrants 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.3 of the
Registrants Current Report on Form 8-K filed on June 18, 2008) |
|
|
|
10.10
|
|
Form of Outside Director Restricted Stock Agreement for restricted stock grants under the
Registrants 2008 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.4 of the
Registrants Current Report on Form 8-K filed on June 18, 2008) |
|
|
|
No. |
|
Description of Exhibit |
|
|
|
10.11
|
|
Agreement of Limited Partnership of West Fork Pipeline Company LP (Incorporated by reference
to Exhibit 10.21 of Form 10-K of the Registrant for the fiscal year ended December 31, 2004) |
|
|
|
10.12
|
|
ISDA Master Agreement, dated as of October 13, 2005, between Parallel, L.P. and Citibank,
N.A. (Incorporated by reference to Exhibit 10.5 of the Registrants Form 8-K Report dated
October 14, 2005 and filed with the Securities and Exchange Commission on October 20, 2005) |
|
|
|
10.13
|
|
Third Amended and Restated Credit Agreement, dated as of December 23, 2005, among Parallel
Petroleum Corporation, Parallel, L.P., Parallel, L.L.C. and Citibank Texas, N.A., BNP Paribas,
CitiBank F.S.B., Western National Bank, Compass Bank, Comerica Bank, Bank of Scotland and
Fortis Capital Corp. (Incorporated by reference to Exhibit No. 10.1 of the Registrants Form
8-K Report, dated December 23, 2005, as filed with the Securities and Exchange Commission on
December 30, 2005) |
|
|
|
10.14
|
|
Second Lien Term Loan Agreement, dated November 15, 2005, among Parallel Petroleum
Corporation, Parallel, L.P., BNP Paribas and Citibank Texas, N.A. (Incorporated by reference
to Exhibit No. 10.4 of the Registrants Form 8-K Report, dated November 15, 2005, as filed
with the Securities and Exchange Commission on November 21, 2005) |
|
|
|
10.15
|
|
Intercreditor and Subordination Agreement, dated November 15, 2005, among Citibank Texas,
N.A., BNP Paribas, Parallel Petroleum Corporation, Parallel, L.P. and Parallel, L.L.C.
(Incorporated by reference to Exhibit No. 10.5 of the Registrants Form 8-K Report, dated
November 15, 2005, as filed with the Securities and Exchange Commission on November 21, 2005) |
|
|
|
10.16
|
|
Guaranty, dated as of December 23, 2005, made by Parallel, L.L.C. to and in favor of
Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.23 of Form 10-K of the
Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.17
|
|
Third Amended and Restated Pledge Agreement, dated as of December 23, 2005, between
Parallel, L.L.C. and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.24 of Form
10-K of the Registrant for the fiscal year ended December 31, 2006) |
|
|
|
10.18
|
|
Second Lien Guarantee and Collateral Agreement, dated as of November 15, 2005, made by
Parallel Petroleum Corporation and Parallel, L.P. to and in favor of BNP Paribas (Incorporated
by reference to Exhibit 10.25 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2006) |
|
|
|
10.19
|
|
Third Amendment to Third Amended and Restated Credit Agreement, dated as of July 31, 2007,
among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank,
Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to
Exhibit 10.3 of the Registrants Current Report on Form 8-K filed on August 1, 2007) |
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10.20
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Fourth Amendment to Third Amended and Restated Credit Agreement, dated as of November 30,
2007, among the Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank,
Comerica Bank, Bank of Scotland, and Fortis Capital Corp. (Incorporated by reference to
Exhibit 10.27 of Form S-4 of the Registrant, Registration No. 333-148465) |
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10.21
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Hagerman Gas Gathering System Joint Venture Agreement, dated as of January 16, 2007, among
the Registrant, Feagan Gathering Company and Capstone Oil and Gas Company, L.P. (Incorporated
by reference to Exhibit 10.28 of Form 10-K of the Registrant for the fiscal year ended
December 31, 2007) |
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10.22
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Fourth Amended and Restated Credit Agreement, dated as of May 16, 2008, among the
Registrant, Citibank, N.A., BNP Paribas, Western National Bank, Compass Bank, Comerica Bank,
Bank of Scotland plc, and Texas Capital Bank, N.A. (Incorporated by reference to Exhibit 10.1
of the Registrants Current Report on Form 8-K filed on May 22, 2008) |
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10.23
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First Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 31,
2008, by and among Parallel Petroleum Corporation, Citibank, N.A., BNP Paribas, Western
National Bank, |
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No. |
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Description of Exhibit |
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Compass Bank, Bank of Scotland plc, Texas Capital Bank, N.A., Bank of America, N.A. and West
Texas National Bank (Incorporated by reference to Exhibit 10.34 of the Registrants Form 10-Q
Report for the third fiscal quarter ended September 30, 2008) |
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*10.24
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Second Amendment to Fourth Amended
and Restated Credit Agreement, executed as of February 19,
2009, by and among Parallel Petroleum Corporation, Citibank, N.A., BNP Paribas, Western
National Bank, Compass Bank, Bank of Scotland plc, Texas Capital Bank, N.A., Bank of America,
N.A. and West Texas National Bank |
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14
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Code of Ethics (Incorporated by reference to Exhibit No. 14 of the Registrants Form 10-K
Report for the fiscal year ended December 31, 2003 and filed with the Securities and Exchange
Commission on March 22, 2004) |
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*23.1
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Consent of BDO Seidman, LLP |
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*23.2 |
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Consent of Cawley, Gillespie & Associates Inc. Independent Petroleum Engineers |
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*31.1
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Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of
the Sarbanes Oxley Act of 2002. |
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*31.2
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Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of
the Sarbanes Oxley Act of 2002. |
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**32.1
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Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes Oxley Act of 2002. |
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**32.2
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Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes Oxley Act of 2002. |
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* |
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Filed herewith. |
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** |
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Furnished herewith. |