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, 2009
Commission file number: 001-32997
Magnum Hunter Resources Corporation
(Name of registrant as specified in its charter)
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DELAWARE
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86-0879278 |
(State or other jurisdiction of
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(I.R.S. Employer |
incorporation or organization)
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Identification No.) |
777 Post Oak Boulevard, Suite 910, Houston, Texas 77056
(Address of principal executive offices, including zip code)
Registrants telephone number including area code: (832) 369-6986
Securities registered under Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered |
$0.01 par value Common Stock
10.25% Series C Cumulative Perpetual Preferred Stock
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NYSE Amex
NYSE Amex |
Securities registered under 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
15(d) of the Exchange Act. Yes o No þ
Indicate by check mark if 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 past 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
whether the registrant has submitted electronically and posted on its corporate
Web site, if any, every Interactive Data File required to be submitted and
posted pursuant to Rule 405 of Regulation S-T during the preceding
12 months (or for such shorter period that the registrant was required to
submit and post such files). Yes o No 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 (as defined in Rule 12b-2 of the Act):
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Large accelerated filer o
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company þ |
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
State the aggregate market value of voting and non-voting common equity held by non-affiliates
computed by reference to the price at which the common equity was last sold, or the average bid and
asked price of such common equity, as of the last business day of the registrants most recently
completed second fiscal quarter: $21,172,701.
As of March 29, 2010, 57,979,111 shares of the registrants common stock were issued and
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrants definitive proxy statement for its Annual Meeting of Stockholders for
2010 to be filed with the Commission within 120 days after the close of its fiscal year are
incorporated by reference into Part III hereof.
FORM 10-K ANNUAL REPORT
FISCAL YEAR ENDED DECEMBER 31, 2009
MAGNUM HUNTER RESOURCES CORPORATION
2
CAUTIONARY NOTICE
The statements and information contained in this annual report on Form 10-K that are not statements
of historical fact, including all of the estimates and assumptions contained herein, are forward
looking statements as defined in Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended. These forward looking statements
include, among others, statements, estimates and assumptions relating to our business and growth
strategies, our oil and gas reserve estimates, our ability to successfully and economically explore
for and develop oil and gas resources, our exploration and development prospects, future
inventories, projects and programs, expectations relating to availability and costs of drilling
rigs and field services, anticipated trends in our business or industry, our future results of
operations, our liquidity and ability to finance our exploration and development activities, market
conditions in the oil and gas industry and the impact of environmental and other governmental
regulation. Forward-looking statements generally can be identified by the use of forward-looking
terminology such as may, will, could, should, expect, intend, estimate,
anticipate, believe, project, pursue, plan or continue or the negative thereof or
variations thereon or similar terminology.
These forward-looking statements are subject to numerous assumptions, risks, and uncertainties.
Factors that may cause our actual results, performance, or achievements to be materially different
from those anticipated in forward-looking statements include, among others, the following:
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adverse economic conditions in the United States and globally; |
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difficult and adverse conditions in the domestic and global capital and credit markets; |
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changes in domestic and global demand for oil and natural gas; |
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volatility in the prices we receive for our oil and natural gas; |
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the effects of government regulation, permitting, and other legal requirements; |
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future developments with respect to the quality of our properties,
including, among other things, the existence of reserves in economic
quantities; |
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uncertainties about the estimates of our oil and natural gas reserves; |
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our ability to increase our production and oil and natural gas income through exploration and development; |
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our ability to successfully apply horizontal drilling techniques and tertiary recovery methods; |
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the number of well locations to be drilled, the cost to drill, and the time frame within which they will be drilled; |
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drilling and operating risks; |
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the availability of equipment, such as drilling rigs and transportation pipelines; |
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changes in our drilling plans and related budgets; |
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the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity; |
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other factors discussed under Risk Factors in Item 1A of this report. |
These factors are in addition to the risks described in the Risk Factors and Managements
Discussion and Analysis of Financial Condition and Results of Operations sections of this
document. Most of these factors are difficult to anticipate and beyond our control. Because
forward-looking statements are subject to risks and uncertainties, actual results may differ
materially from those expressed or implied by such statements. You are cautioned not to place undue
reliance on forward-looking statements, contained herein, which speak only as of the date of this
document. Other unknown or unpredictable factors may cause actual results to differ materially from
those projected by the forward-looking statements. Unless otherwise required by law, we undertake
no obligation to publicly update or revise any forward-looking statements, whether as a result of
new information, future events, or otherwise. We urge readers to review and consider disclosures we
make in this and other reports that discuss factors germane to our business. See in particular our
reports on Forms 10-K, 10-Q, and 8-K subsequently filed from time to time with the Securities and
Exchange Commission.
All forward-looking statements attributable to us are expressly qualified in their entirety by
these cautionary statements.
3
SPECIAL NOTE REGARDING THE REGISTRANT
In this Annual Report on Form 10-K, the words Magnum Hunter, Company, we, our, and us
refer to Magnum Hunter Resources Corporation and its consolidated subsidiaries unless stated or the
context otherwise requires.
We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on form 8-K,
registration statements and other items with the Securities and Exchange Commission (SEC). We
provide access free of charge to all of these SEC filings, as soon as reasonably practicable after
filing, on our Internet site located at
www.MagnumHunterResources.com. In addition, the public may
read and copy any materials we file with the SEC at the SECs Public Reference Room at 100 F
Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the
Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet
website that contains reports, proxy and information statements, and other information regarding
issuers, including Magnum Hunter Resources Corporation, that file electronically with the SEC. The
public can obtain any document we file with the SEC at
www.sec.gov. Information contained on or
connected to our website is not incorporated by reference into this Form 10-K and should not be
considered part of this report or any other filing that we make with the SEC.
Industry terms used in this report are defined in the Glossary of Oil and Natural Gas Term located at the end of Part 1.
4
PART I
Item 1. BUSINESS
Overview
We are an independent oil and gas company engaged in the acquisition, development and production of
oil and natural gas, primarily in West Virginia, North Dakota, Texas and Louisiana. The Company is
presently active in three of the four most prolific shale resource plays in the United States,
including the Marcellus Shale, Eagle Ford Shale and Williston Basin / Bakken Shale. The Company is
a Delaware corporation and was incorporated in 1997. In 2005, the Company began oil and gas
operations under the name Petro Resources Corporation. In May of 2009, the Company restructured its
management team and refocused its business strategy, and in July of 2009, changed its name to
Magnum Hunter Resources Corporation (MHR). The
restructured management team includes Gary C. Evans, former
Founder, Chairman and Chief Executive Officer of Magnum Hunter Resources, Inc.,1 as
Chairman and Chief Executive Officer, Ronald D. Ormand as Executive Vice President and Chief
Financial Officer, H.C. Kip Ferguson as Executive Vice President of Exploration and M. Bradley
Davis as Senior Vice President of Capital Markets. Our management has implemented a new business
strategy consisting of exploiting our inventory of lower-risk drilling locations and the
acquisition of long-lived proved reserves with significant exploitation and development
opportunities. As a result of this new strategy, the Company has substantially increased its assets
and production through three acquisitions and ongoing development efforts, the percentage of
operated properties has increased significantly, its inventory of acreage and drilling locations in
resource plays have grown and its management team has been expanded.
At December 31, 2009, our estimated proved reserves of 6.2 MMboe were approximately 75% oil, had a
standardized measure of $47.4 million and an SEC PV-10 value of $65.6 million. This represents a
97% increase in proved reserves from the level at year ended 2008. Our average daily production
volumes for 2009 were 703 Boepd, which represents a 22% increase from those levels experienced in
2008. Our average daily production volumes were approximately 900 Boe per day at December 31,
2009.
Significant Developments and Achievements
Triad Acquisition. On February 12, 2010, the Company closed the acquisition of substantially all of
the assets of privately-held Triad Energy Corporation and certain of its affiliates (collectively,
Triad), a 23-year old Appalachian Basin focused oil and gas production company. The Company
acquired the assets of Triad in connection with Triads reorganization under Chapter 11 of the
United States Bankruptcy Code. Triads operations are located in
the states of Ohio, West Virginia
and Kentucky, in the Appalachian Basin. The assets acquired from Triad include (i) conventional,
mature oil fields currently under primary and secondary development with approximately 5.1 MMboe of
proved reserves (65% oil); and over 2,000 producing wells (99% of which are operated by Triad) with
a production exit rate on December 31, 2009 of approximately 830 Boepd; (ii) over 87,000 net acres
including approximately 46,000 net acres in the prolific Marcellus Shale; (iii) 182 miles of gas
pipeline and rights-of-way that will allow for the construction of new larger diameter pipeline
that will provide Magnum Hunter with significant take-away capacity for our Marcellus Shale gas as
well as revenue from transporting third-party gas; (iv) service equipment including three drilling
rigs; and (v) commercial salt water disposal facilities. These assets are now held by our
wholly-owned subsidiaries Triad Hunter, LLC, Alpha Hunter Drilling, LLC, Eureka Hunter Pipeline,
LLC, Hunter Disposal, LLC and Hunter Real Estate, LLC. Consideration for the assets acquired from
Triad totaled $81 million consisting of:
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$55 million for the repayment of Triads senior debt, which $55 million was borrowed
by the Company pursuant to the terms of the new Restated Credit Agreement discussed
below; |
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$15 million of our Series B Redeemable Convertible Preferred Stock, issued to certain
banks that were secured creditors of Triad; |
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$8 million in cash; and |
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Assumption of approximately $3 million of equipment indebtedness. |
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The Fair Value of the
consideration approximated its $81 million face value. |
As a result of the Triad acquisition, on a SEC basis, the Company had pro forma reserves of 11.3
MMboe with PV-10 of $122 million (70% oil) at December 31, 2009. On a NYMEX strip basis, our
reserves were 12.3 MMboe with a PV-10 of $237.5 million.
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1 |
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Magnum Hunter Resources, Inc. was a NYSE-listed oil and
gas exploration and production company, unrelated to the Company, that was
acquired by Cimarex Energy Corporation in June 2005. |
5
Bank of Montreal Credit Facilities. On November 23, 2009, we entered into a $150 million Credit
Agreement (the Credit Agreement) with Bank of Montreal. The Credit Agreement provided for an
asset-based, three-year senior secured revolving credit facility (the Revolving Facility), with
an initial borrowing base availability of $25 million. On February 12, 2010 we amended and restated
the Credit Agreement (the Restated Credit Agreement) with Bank of Montreal and Capital One, NA,
providing for a borrowing base of $70 million.
Acquisition of Sharon Resources, Inc. On September 30, 2009, we acquired Sharon Resources, Inc., a
wholly-owned subsidiary of Calgary-based Sharon Energy Ltd., bringing an inventory of drilling
locations focused in the Eagle Ford Shale located in South Texas. Additionally, the Sharon
acquisition enhanced the Companys technical expertise with the addition of experienced geologists
and land professionals.
Equity
Financings. Throughout the fourth quarter of 2009, the Company raised substantial cash through
equity transactions. Those transactions included:
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$15.2 million of common equity financings throughout the course of the fourth
quarter. |
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$5.4 million in gross proceeds from the issuance of our 10.25% Series C
Cumulative Perpetual Preferred Stock, (Series C Preferred Stock) at a price of
$25.00 per share in the fourth quarter of 2009 |
Summary of Proved Reserves, Wells and Production
SEC Case Reserve Summary (1)
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At December 31, 2009 |
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2009 Average |
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Proved |
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% |
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Productive Wells |
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Daily Production |
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Area |
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Reserves (a) |
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PV10% (b)(c) |
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Oil |
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Gross |
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Net |
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Volumes (d) |
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(MMboe) |
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($MMs) |
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(boe) |
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North Dakota |
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3.098 |
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$ |
45.70 |
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96 |
% |
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146 |
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65.7 |
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335 |
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West Texas |
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2.199 |
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12.20 |
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62 |
% |
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87 |
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8.7 |
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302 |
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South Texas / Gulf Coast |
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0.841 |
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7.50 |
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33 |
% |
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10 |
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2.9 |
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33 |
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Other |
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0.031 |
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0.20 |
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0 |
% |
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5 |
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0.5 |
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33 |
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Total |
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6.169 |
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$ |
65.60 |
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74 |
% |
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248 |
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77.8 |
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703 |
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Pro Forma SEC Case Reserve Summary (2)
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Pro Forma At December 31, 2009 * |
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2009 Average |
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Proved |
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% |
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Productive Wells |
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Daily Production |
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Area |
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Reserves (a) |
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PV10% (b)(c) |
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Oil |
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Gross |
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Net |
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Volumes (d) |
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(MMboe) |
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($MMs) |
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(boe) |
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Appalachian Basin |
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5.129 |
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$ |
56.40 |
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65 |
% |
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2,074 |
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1,970.3 |
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1,000 |
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North Dakota |
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3.098 |
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45.70 |
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96 |
% |
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146 |
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65.7 |
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335 |
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West Texas |
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2.199 |
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12.20 |
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62 |
% |
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87 |
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8.7 |
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302 |
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South Texas / Gulf Coast |
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0.841 |
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7.50 |
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32 |
% |
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10 |
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2.9 |
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33 |
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Other |
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0.031 |
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0.20 |
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0 |
% |
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5 |
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0.5 |
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33 |
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Total |
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11.298 |
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$ |
122.00 |
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70 |
% |
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2,322 |
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2,048.1 |
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1,703 |
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* |
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Pro forma information related to the Triad acquisition, which closed February 12, 2010, was prepared by the Companys internal
engineers. |
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(1) |
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Does not include reserves related to our recent acquisition of Triad located in the Appalachian Basin, as the transaction was
completed in February of 2010. |
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(2) |
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Includes reserves related to our recent acquisition of Triad located in the Appalachian Basin, which closed in February of 2010. |
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(a) |
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MMBoe is defined as one million barrels of oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of
crude oil, condensate or natural gas liquids. |
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(b) |
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The prices used to calculate this measure were $61.18 per barrel of oil and $3.866 per MMbtu of natural gas. The prices
represent the average prices per barrel of oil and per MMbtu of natural gas at the beginning of each month in the 12-month
period prior to the end of the reporting period. These prices were adjusted to reflect applicable transportation and quality
differentials on a well-by-well basis to arrive at realized sales prices used to estimate our reserves at this date. |
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(c) |
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The standardized measure for our proved reserves at December 31, 2009 was $47.4 million. See Item 2. Properties for a
definition of pre-tax PV10% and a reconciliation of our standardized measure to our pre-tax PV10% value. |
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(d) |
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Average daily production volumes calculated based on 360 day year. |
6
NYMEX Futures Strip Case Reserve Summary
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At December 31, 2009 |
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2009 Average |
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Proved |
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% |
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Productive Wells |
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Daily Production |
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Area |
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Reserves (e) |
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PV10% (f) |
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Oil |
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Gross |
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Net |
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Volumes (g) |
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(MMboe) |
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($MMs) |
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(boe) |
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North Dakota |
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3.339 |
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$ |
81.5 |
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95 |
% |
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|
146 |
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66 |
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335 |
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West Texas |
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2.337 |
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$ |
27.7 |
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62 |
% |
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|
87 |
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9 |
|
|
|
302 |
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South Texas / Gulf Coast |
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0.896 |
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$ |
9.0 |
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|
32 |
% |
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|
10 |
|
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|
3 |
|
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|
30 |
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Other |
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|
0.038 |
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$ |
0.3 |
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0 |
% |
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|
5 |
|
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|
1 |
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|
36 |
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Total |
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6.610 |
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$ |
118.5 |
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|
75 |
% |
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|
248 |
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|
79 |
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|
703 |
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(e) |
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MMBoe is defined as one million barrels of oil equivalent determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
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(f) |
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The prices used to calculate this measure were the NYMEX futures strip prices as of December
31, 2009. |
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(g) |
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Average daily production volumes calculated based on 360 day year. |
7
Pro Forma NYMEX Futures Strip Case Reserve Summary (2) *
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2009 Average |
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Proved |
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% |
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Productive Wells |
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Daily Production |
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Area |
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Reserves (e) |
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PV10% (f) |
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Oil |
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Gross |
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Net |
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|
Volumes (g) |
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(MMboe) |
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($MMs) |
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(boe) |
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|
|
|
|
Appalachian Basin |
|
|
5.725 |
|
|
$ |
119.0 |
|
|
|
66 |
% |
|
|
2,074 |
|
|
|
1,970 |
|
|
|
1,000 |
|
North Dakota |
|
|
3.339 |
|
|
|
81.5 |
|
|
|
95 |
% |
|
|
146 |
|
|
|
66 |
|
|
|
335 |
|
West Texas |
|
|
2.337 |
|
|
|
27.7 |
|
|
|
62 |
% |
|
|
87 |
|
|
|
9 |
|
|
|
302 |
|
South Texas / Gulf Coast |
|
|
0.896 |
|
|
|
9.0 |
|
|
|
32 |
% |
|
|
10 |
|
|
|
3 |
|
|
|
30 |
|
Other |
|
|
0.038 |
|
|
|
0.3 |
|
|
|
0 |
% |
|
|
5 |
|
|
|
1 |
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
12.335 |
|
|
$ |
237.5 |
|
|
|
70 |
% |
|
|
2,322 |
|
|
|
2,049 |
|
|
|
1,703 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Pro forma information related to the Triad acquisition, which closed February 12, 2010, was
prepared by the Companys internal engineers. |
|
(2) |
|
This table includes reserves related to our recent acquisition of Triad located in the
Appalachian Basin, which closed in February of 2010. |
|
(e) |
|
MMBoe is defined as one million barrels of oil equivalent determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
|
(f) |
|
The prices used to calculate this measure were the NYMEX futures strip prices as of December
31, 2009. |
|
(g) |
|
Average daily production volumes calculated based on 360 day year. |
8
Business Strategy
Our business strategy is to create value for our stockholders by growing reserves, production
volumes and cash flow through cost effective development of our properties and through strategic
acquisitions. The Company employs many of the elements that have proved successful for our
management team in the past. Key elements of our business strategy include:
Focus on Unconventional Resource Plays We intend to focus on the development and expansion of our
properties in the Marcellus Shale, Eagle Ford Shale and Williston / Bakken Shale. As of March 29,
2010, the Company currently had over 95,200 gross acres in these three areas and over 125
identified drilling locations. The Company intends to commence its initial drilling efforts on
these locations in 2010. With recent improvements in drilling and completion technologies, the
development of unconventional resources has become highly economic.
Strategic Acquisitions The Company intends to opportunistically acquire additional acreage and
reserves. Since the restructuring of the Companys management in May of 2009, we have completed
three significant acquisitions, including Sharon, East Chalkley and Triad. We believe that our
acquisition related and operational track record, as well as our extensive industry relationships
will provide for continued growth opportunities in the future.
Focus on Acquisition and Development of Oil Assets We plan to focus our development and
acquisition efforts primarily on oil reserves, as we believe they currently present the most
attractive returns on capital employed, as compared to natural gas. At March 29, 2010, 75% of our
proved reserves and 65% of current production were oil.
Operating Control We believe that operatorship provides the ability to maximize the value of our
assets, including timing of drilling expenditures, enhanced controls on operational costs and the
ability to enhance production volumes. We have significantly increased the number of wells that we
operate. Pro Forma for the Triad acquisition, we operated 95% of our net wells in production and
53% of proved reserves at March 29, 2010.
Employment of Advanced Technologies We utilize state of the art, advanced technologies, allowing
us to achieve the best opportunity for drilling success. Our technical team continually reviews the
most current technologies and applies them to our reserve base for the effective development of our
project inventory.
Leveraging the Experience of our Management Team Management will actively utilize its track
record and relationships with industry partners, commercial banks, investment banks, institutional
equity investors and private equity investors to assist us in rapidly building and developing the
Companys asset base and financing the Companys growth on a cost effective basis.
Development of Pipeline and Infrastructure Assets We are actively pursuing the completion of our
182-mile pipeline asset to support the development of our Marcellus acreage. We have allocated $10
million in our 2010 capital budget to complete the initial 12 mile phase of our pipeline. The
Company is actively pursuing joint venture and other financing structures to support the expansion
of the pipeline, and anticipates ultimately increasing throughput capacity to approximately 200
MMcf/d. We anticipate the initial pipeline expansion to be completed in the third quarter of 2010.
Competitive Strengths
We believe that our key competitive strengths include:
Experienced Management Team Our management team, on average, has over 25 years of experience in
the oil and gas industry. Senior management has extensive experience in managing, financing and
operating public oil and gas companies. Magnum Hunter Resources, Inc., (MHRI), founded by Gary C.
Evans in 1985 and unrelated to the Company, achieved an average annual internal rate of return of
38% to shareholders during the 15 years it was publicly traded. Additionally, our management team
has collectively completed over $30 billion in financing transactions and acquisitions in the oil
and gas industry and our personnel have extensive expertise in key operational disciplines.
Balanced Long-Lived Asset Base with Substantial Oil Reserves As of December 31, 2009, we owned
interests in 248 gross (77.8 net) productive wells across approximately 28,000 gross (8,500 net)
mineral acres. We believe this geographic mix of properties and drilling opportunities, combined
with our continuing business strategy of acquiring and exploiting properties in these areas,
presents us with multiple opportunities in executing our strategy. Our proved reserve life is
approximately 14 years based on year-end 2009 pro forma proved reserves and estimated production
for 2010. Approximately 75% of our proved reserves as of December 31, 2009 were oil and an
estimated 71% of production was oil.
9
Acreage Position and Drilling Inventory in Core Resource Areas As of March 29, 2010, we had
significant acreage of over 68,600 net acres in our core shale areas, including approximately
46,000 net acres in the Marcellus Shale, 15,000 net acres in Eagle Ford
Shale and 7,600 net acres in the Williston/Bakken Shale. We have identified an inventory of over
125 drillable locations in these core areas.
Marcellus Infrastructure Assets The Company controls approximately 182 miles of pipeline,
gathering systems and rights-of-way to provide critical takeaway capacity and third party
transportation in the capacity-constrained Marcellus Shale area of West Virginia. Following our
planned expansion, we estimate our natural gas pipeline system will have throughput capacity of
approximately 200 MMcf/d. In addition, we own and operate a 2,200-5,000 barrel per day commercial
salt water disposal facility that was acquired in the Triad acquisition, which is important to the
efficient operation and development of our assets in the Marcellus Shale area. We also maintain an
inventory of drilling rigs and various oilfield service equipment to be used to develop our oil and
gas assets located in the Appalachian region.
2010 Capital Budget
As of the date of this report, we estimate our capital budget for fiscal year 2010 to be
approximately $25 million, including:
|
|
|
Approximately $17.1 million to be deployed for activities in the Appalachian Basin,
including $10 million to complete the initial phase of the Eureka Hunter Pipeline project
and approximately $7.1 million to drill two horizontal wells targeting the Marcellus Shale
formation. |
|
|
|
Approximately $6.95 million towards operations in the Eagle Ford Shale of South Texas,
including the leasing of additional acreage and the drilling of two horizontal wells in the
Eagle Ford Shale formation. |
|
|
|
Approximately $950,000 for other projects including Cinco Terry. |
|
|
|
Because of the volatility of commodity prices and the risks involved in our industry, we
believe in remaining flexible in our capital budgeting process. When appropriate, we may
defer existing capital projects to seize an attractive acquisition opportunity or
reallocate capital towards projects where we believe we can generate higher rates of return
on capital employed. We also believe in maintaining a strong balance sheet and using
commodity hedging. This allows us to be more opportunistic in lower commodity price
environments as well as providing more consistent financial results in the long-term. |
10
Marketing and Pricing
We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are
determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil
and natural gas on the open market at prevailing market prices. The market price for oil and
natural gas is dictated by supply and demand, and we cannot accurately predict or control the price
we may receive for our oil and natural gas.
We use commodity price hedging instruments to reduce our exposure to oil and natural gas price
fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and
capital programs. From time to time, we may enter into futures contracts, collars and basis swap
agreements, as well as fixed price physical delivery contracts; however, it is our preference to
utilize hedging strategies that provide downside commodity price protection without unduly limiting
our revenue potential in an environment of rising commodity prices. We use hedging primarily to
manage price risks and returns on certain acquisitions and drilling programs. Our policy is to
consider hedging an appropriate portion of our production at commodity prices we deem attractive.
In addition, we are required by our lenders to hedge a significant portion of production through
calendar year 2012.
Our revenues, cash flows, profitability and future rate of growth depend substantially upon
prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for
capital expenditures and our ability to borrow money or raise additional capital. Lower prices may
also adversely affect the value of our reserves and make it uneconomical for us to commence or
continue production levels of natural gas and crude oil. Historically, the prices received for oil
and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:
|
|
|
changes in global supply and demand for oil and natural gas; |
|
|
|
|
the actions of the Organization of Petroleum Exporting Countries, or OPEC; |
|
|
|
|
the price and quantity of imports of foreign oil and natural gas; |
|
|
|
|
acts of war or terrorism; |
|
|
|
|
political conditions and events, including embargoes, affecting oil-producing activity; |
|
|
|
|
the level of global oil and natural gas exploration and production activity; |
|
|
|
|
the level of global oil and natural gas inventories; |
|
|
|
|
weather conditions; |
|
|
|
|
technological advances affecting energy consumption; and |
|
|
|
|
the price and availability of alternative fuels. |
From time to time, we enter into hedging arrangements to reduce our exposure to decreases in the
prices of oil and natural gas. Hedging arrangements may expose us to risk of significant financial
loss in some circumstances including circumstances where:
|
|
|
our production and/or sales of natural gas are less than expected; |
|
|
|
|
payments owed under derivative hedging contracts come due prior to receipt of
the hedged months production revenue; or |
|
|
|
|
the counter party to the hedging contract defaults on its contract obligations. |
In addition, hedging arrangements limit the benefit we would receive from increases in the prices
for oil and natural gas. We cannot assure you that any hedging transactions we may enter into will
adequately protect us from a decline in the price of oil and natural gas. On the other hand, should
we choose not to engage in hedging transactions in the future (assuming we are permitted by our
lenders to do so), we may be more adversely affected by changes in oil and natural gas prices than
our competitors who engage in hedging transactions.
11
As of December 31, 2009, we had the following hedges in place:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4Q09 |
|
|
1Q10 |
|
|
2Q10 |
|
|
3Q10 |
|
|
4Q10 |
|
|
2010 |
|
|
2011 |
|
|
2012 |
|
Natural Gas Hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floors |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMbtu/d) |
|
|
652 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Price per MCF |
|
$ |
7.75 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMbtu/d) |
|
|
N/A |
|
|
|
667 |
|
|
|
659 |
|
|
|
652 |
|
|
|
652 |
|
|
|
658 |
|
|
|
548 |
|
|
|
329 |
|
Floor Price per MCF |
|
|
N/A |
|
|
$ |
5.69 |
|
|
$ |
5.69 |
|
|
$ |
5.69 |
|
|
$ |
5.69 |
|
|
$ |
5.69 |
|
|
$ |
5.00 |
|
|
$ |
5.00 |
|
Ceiling Price per MCF |
|
|
N/A |
|
|
$ |
7.26 |
|
|
$ |
7.26 |
|
|
$ |
7.26 |
|
|
$ |
7.26 |
|
|
$ |
7.26 |
|
|
$ |
8.39 |
|
|
$ |
9.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gas Volume Hedged |
|
|
60,000 |
|
|
|
60,000 |
|
|
|
60,000 |
|
|
|
60,000 |
|
|
|
60,000 |
|
|
|
240,000 |
|
|
|
199,980 |
|
|
|
120,000 |
|
Total PDP |
|
|
141,504 |
|
|
|
73,887 |
|
|
|
74,708 |
|
|
|
75,529 |
|
|
|
75,529 |
|
|
|
299,653 |
|
|
|
249,230 |
|
|
|
217,343 |
|
Total % Natural Gas
Volume Hedged |
|
|
42 |
% |
|
|
81 |
% |
|
|
80 |
% |
|
|
79 |
% |
|
|
79 |
% |
|
|
80 |
% |
|
|
80 |
% |
|
|
55 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floors |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls/d) |
|
|
33 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
Price per bbl |
|
$ |
110.00 |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbls/d) |
|
|
170 |
|
|
|
213 |
|
|
|
187 |
|
|
|
185 |
|
|
|
185 |
|
|
|
192 |
|
|
|
162 |
|
|
|
N/A |
|
Price per bbl |
|
$ |
87.43 |
|
|
$ |
88.84 |
|
|
$ |
102.64 |
|
|
$ |
102.64 |
|
|
$ |
102.64 |
|
|
$ |
99.19 |
|
|
$ |
103.67 |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMbtu/d) |
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
137 |
|
Floor Price per MCF |
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
$ |
80.00 |
|
Ceiling Price per MCF |
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
$ |
100.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oil Volume Hedged |
|
|
18,367 |
|
|
|
19,160 |
|
|
|
17,010 |
|
|
|
17,010 |
|
|
|
17,010 |
|
|
|
70,226 |
|
|
|
59,225 |
|
|
|
50,000 |
|
Total PDP |
|
|
47,336 |
|
|
|
27,893 |
|
|
|
28,203 |
|
|
|
28,513 |
|
|
|
28,513 |
|
|
|
113,123 |
|
|
|
98,692 |
|
|
|
86,489 |
|
Total % Oil Volume Hedged |
|
|
39 |
% |
|
|
69 |
% |
|
|
60 |
% |
|
|
60 |
% |
|
|
60 |
% |
|
|
62 |
% |
|
|
60 |
% |
|
|
58 |
% |
12
Competition
The oil and natural gas industry is highly competitive in all phases. We encounter competition from
other oil and natural gas companies in all areas of operation, including the acquisition of leases.
Our competitors include numerous independent oil and natural gas companies and individuals. Many of
our competitors are large, well established companies that have substantially larger operating
staffs and greater capital resources than we do. Our ability to acquire additional properties in
the future will depend upon our ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment. See Item 1A. Risk Factors
Competition in the oil and natural gas industry is intense, which may adversely affect our ability
to compete.
Operating Hazards and Risks
Drilling activities are subject to many risks, including the risk that no commercially productive
reservoirs will be encountered. There can be no assurance that the new wells we drill will be
productive or that we will recover all or any portion of our investment. Drilling for oil and
natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that are
productive, but do not produce sufficient net revenues to return a profit after drilling, operating
and other costs. The cost and timing of drilling, completing and operating wells is often
uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous
factors, many of which are beyond our control, including low oil and natural gas prices, title
problems, weather conditions, delays by project participants, compliance with governmental
requirements, shortages or delays in the delivery of equipment and services and increases in the
cost for such equipment and services. Our future drilling activities may not be successful and, if
unsuccessful, such failure may have a material adverse effect on our business, financial condition,
results of operations and cash flows.
Our operations are subject to hazards and risks inherent in drilling for and producing and
transporting oil and natural gas, such as fires, natural disasters, explosions, encountering
formations with abnormal pressures, blowouts, craterings, pipeline ruptures and spills, any of
which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and
other damage to our properties and those of others. We maintain insurance against some but not all
of the risks described above. In particular, the insurance we maintain does not cover claims
relating to failure of title to oil and natural gas leases, loss of surface equipment at well
locations, business interruption, loss of revenue due to low commodity prices or loss of revenues
due to well failure. Furthermore, in certain circumstances where such insurance is available, we
may determine not to purchase it due to cost or other factors. The occurrence of an event that is
not covered by, or not fully covered by insurance could have a material adverse effect on our
business, financial condition, results of operations and cash flows in the period such event may
occur.
Governmental Regulation
Our oil and natural gas exploration activities are subject to extensive laws, rules and regulations
promulgated by federal and state legislatures and agencies. Failure to comply with such laws, rules
and regulations can result in substantial penalties, including the delay or stopping of our
operations. The legislative and regulatory burden on the oil and natural gas industry increases our
cost of doing business and affects our profitability. See Item 1A. Risk Factors Our operations
expose us to substantial costs and liabilities with respect to environmental matters.
The commercial risk associated with the production of fossil fuels lies in the uncertainty of
government-imposed climate change legislation, including cap and trade schemes, and regulations
that may affect us, our suppliers, and our customers. The cost of meeting these requirements may
have an adverse impact on our financial condition, results of operations and cash flows, and could
reduce the demand for our products.
Climate Change
Climate change has become the subject of an important public policy debate. Climate change remains
a complex issue, with some scientific research suggesting that an increase in greenhouse gas
emissions (GHGs) may pose a risk to society and the environment. The oil and natural gas
exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane,
and future restrictions on the combustion of fossil fuels or the venting of natural gas could have
a significant impact on our future operations. See Item 1A. Risk Factors Climate change
legislation or regulations restricting emissions of greenhouse gases could result in increased
operating costs and reduced demand for the oil, natural gas and NGLs that we produce.
13
Formation
We were incorporated in the State of Delaware on June 4, 1997.
Employees
At December 31, 2009, we had 18 full-time employees of which 9 were officers. None of our employees
are represented by a union. Management considers our relations with employees to be very good.
Subsequent to the closing of the acquisition of Triad, we had 139 full-time employees, of which 10
were officers.
Facilities
As of December 31, 2009, our principal executive offices are located in Houston, Texas, where we
lease approximately 7,678 square feet of office space at 777 Post Oak Blvd., Suite 910, Houston,
Texas 77056, under a lease whereby approximately 6,000 and 1,600 square feet expire in May of 2012
and December of 2013, respectively. We have also inherited, through the acquisition of Sharon
Resources, Inc., approximately 6,031 square feet of office space located at 675 Bering, Suite 650,
Houston, Texas 77057 under a lease that expires in February of 2012 which we are actively marketing
to sub-lease candidates. In connection with the acquisition of Triad in February 2010, we acquired
7,608 square feet of leased office space in Marietta, Ohio as well as field offices in Kentucky and
West Virginia.
Website Access
We
make available, free of charge through our website,
www.MagnumHunterResources.com, our annual
report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all
amendments to those reports as soon as reasonably practicable after such material is electronically
filed with the Securities and Exchange Commission. Information on our website is not a part of this
report.
14
Item 1A. RISK FACTORS
In evaluating our company, the factors described below should be considered carefully. The
occurrence of one or more of these events could significantly and adversely affect our business,
prospects, financial condition, results of operations and cash flows.
Risks Related to Our Business
Future economic conditions in the U.S. and global markets may have a material adverse impact on our
business and financial condition that we currently cannot predict.
The U.S. and other world economies are slowly recovering from a recession which began in 2008 and
has extended into 2009 and 2010. While economic growth has resumed, it remains modest and the
timing of an economic recovery is uncertain. There are likely to be significant long-term effects
resulting from the recession and credit market crisis, including a future global economic growth
rate that is slower than what was experienced in recent years. Unemployment rates remain very high
and businesses and consumer confidence levels have not yet fully recovered to pre-recession levels.
In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved.
Global economic growth drives demand for energy from all sources, including for oil and natural
gas. A lower future economic growth rate will result in decreased demand for our crude oil and
natural gas production as well as lower commodity prices, which will reduce our cash flows from
operations and our profitability.
Volatility in oil and natural gas prices may adversely affect our business, financial condition or
results of operations and our ability to meet our capital expenditure obligations and financial
commitments.
The prices we receive for our oil and natural gas production heavily influence our revenue,
profitability, access to capital and future rate of growth. Oil and natural gas are commodities,
and therefore their prices are subject to wide fluctuations in response to relatively minor changes
in supply and demand. Historically, the markets for oil and natural gas have been extremely
volatile. These markets will likely continue to be volatile in the future. The prices we receive
for our production, and the levels of our production, depend on numerous factors beyond our
control. These factors include, but are not limited to, the following:
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the current uncertainty in the global economy; |
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changes in global supply and demand for oil and natural gas; |
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the condition of the U.S. and global economy; |
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the actions of certain foreign countries; |
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the price and quantity of imports of foreign oil and natural gas (LNG); |
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political conditions, including embargoes, war or civil unrest in or affecting other oil producing activities of certain countries; |
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the level of global oil and natural gas exploration and production activity; |
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the level of global oil and natural gas inventories; |
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production or pricing decisions made by the Organization of Petroleum Exporting Countries (OPEC); |
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weather conditions; |
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technological advances affecting energy consumption; and |
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the price and availability of alternative fuels. |
Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but also
may reduce the amount of oil and natural gas that we can produce economically. The higher operating
costs associated with many of our oil fields will make our profitability more sensitive to oil
price declines. A sustained decline in oil or natural gas prices may materially and adversely
affect our future business, financial condition, results of operations, liquidity or ability to
finance planned capital expenditures.
15
We have limited experience in drilling wells to the Eagle Ford Shale, Marcellus Shale, and Bakken
Shale and limited information regarding reserves and decline rates in the Eagle Ford Shale,
Marcellus Shale and Bakken Shale. Wells drilled to the Eagle Ford Shale, Marcellus Shale and Bakken
Shale are more expensive and more susceptible to mechanical problems in drilling and completion
techniques than wells in the other conventional areas.
We have limited experience in the drilling and completion of Eagle Ford Shale, Marcellus Shale and
Bakken Shale wells. As of December 31, 2009, the management members who joined the Company via the
Triad acquisition have drilled 33 gross vertical wells and 30 net vertical wells to the Marcellus
Shale. We have limited horizontal drilling and completion experience in the Eagle Ford Shale and
Bakken Shale. Other operators in the Eagle Ford, Marcellus Shale and Bakken Shale plays may have
significantly more experience in the drilling and completion of these wells, including the drilling
and completion of horizontal wells. In addition, we
have limited information with respect to the ultimate recoverable reserves and production decline
rates. The wells drilled in the Eagle Ford Shale, Marcellus Shale and Bakken Shale are primarily
horizontal and require more stimulation, which makes them more expensive to drill and complete. The
wells will also be more susceptible to mechanical problems associated with the drilling and
completion of the wells, such as casing collapse and lost equipment in the wellbore due to the
length of the lateral portions of these unconventional wells. The fracturing of these shale
formations will be more extensive and complicated than fracturing other geological formations in
our other areas of operation.
If our access to oil and gas markets is restricted, it could negatively impact our production, our
income and ultimately our ability to retain our leases. Our ability to sell natural gas and/or
receive market prices for our natural gas may be adversely affected by pipeline and gathering
system capacity constraints.
Market conditions or the restriction in the availability of satisfactory oil and natural gas
transportation arrangements may hinder our access to oil and natural gas markets or delay our
production. The availability of a ready market for our oil and natural gas production depends on a
number of factors, including the demand for and supply of oil and natural gas and the proximity of
reserves to pipelines and terminal facilities. Our ability to market our production depends in
substantial part on the availability and capacity of gathering systems, pipelines and processing
facilities owned and operated by third parties. Our failure to obtain such services on acceptable
terms could materially harm our business. Our productive properties may be located in areas with
limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking,
or requiring compression facilities. Such restrictions on our ability to sell our oil or natural
gas may have several adverse effects, including higher transportation costs, fewer potential
purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable
to market and sustain production from a particular lease for an extended time, possibly causing us
to lose a lease due to lack of production.
If drilling in the Eagle Ford Shale, Marcellus Shale and Bakken Shale areas proves to be
successful, the amount of oil and natural gas being produced by us and others could exceed the
capacity of the various gathering and intrastate or interstate transportation pipelines currently
available in these areas. If this occurs, it will be necessary for new pipelines and gathering
systems to be built. Because of the current economic climate, certain pipeline projects that are
planned for the Eagle Ford Shale, Marcellus Shale and Bakken Shale areas may not occur for lack of
financing. In addition, capital constraints could limit our ability to build intrastate gathering
systems necessary to transport our gas to interstate pipelines. In such event, we might have to
shut in our wells awaiting a pipeline connection or capacity and/or sell natural gas production at
significantly lower prices than those quoted on NYMEX or than we currently project for these
specific regions, which would adversely affect our results of operations.
A portion of our natural gas and oil production in any region may be interrupted, or shut in, from
time to time for numerous reasons, including as a result of weather conditions, accidents, loss of
pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail
production in response to market conditions. If a substantial amount of our production is
interrupted at the same time, it could temporarily adversely affect our cash flow.
Certain federal income tax deductions currently available with respect to oil and natural gas
exploration and development may be eliminated as a result of future legislation.
Among the changes contained in President Obamas 2011 budget proposal released by the White House
on February 1, 2010, is the elimination of certain key U.S. federal income tax preferences
currently available to oil and gas exploration and production companies. Such changes include, but
are not limited to:
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the repeal of the percentage depletion allowance for oil and gas properties; |
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the elimination of current deductions for intangible drilling and development costs; |
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the elimination of the deduction for certain U.S. production activities; and |
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an extension of the amortization period for certain geological and geophysical
expenditures. It is unclear, however, whether any such changes will be enacted or how soon
such changes could be effective. |
The passage of any legislation as a result of the budget proposal, the Senate bill, or any other
similar change in U.S. federal income tax law could eliminate certain tax deductions that are
currently available with respect to oil and gas exploration and development, and any such change
could negatively affect our financial condition and results of operations.
16
We depend on a relatively small number of purchasers for a substantial portion of our revenue. The
inability of one or more of our purchasers to meet their obligations may adversely affect our
financial results.
We derive a significant amount of our revenue from a relatively small number of purchasers. Our
inability to continue to provide services to key customers, if not offset by additional sales to
our other customers, could adversely affect our financial condition and results of operations.
These companies may not provide the same level of our revenue in the future for a variety of
reasons, including their lack of funding, a strategic shift on their part in moving to different
geographic areas in which we do not operate or our failure to
meet their performance criteria. The loss of all or a significant part of this revenue would
adversely affect our financial condition and results of operations.
Our results of operations and cash flow may be adversely affected by risks associated with our oil
and gas financial derivative activities, and our oil and gas financial derivative activities may
limit potential gains.
We have entered into, and we expect to enter into in the future, oil and gas financial derivative
arrangements corresponding to a significant portion of our oil and natural gas production. Many
derivative instruments that we employ require us to make cash payments to the extent the applicable
index exceeds a predetermined price, thereby limiting our ability to realize the benefit of
increases in oil and natural gas prices. During the twelve months ended December 31, 2009, we
incurred realized gains of $5.4 million from our financial derivatives. Please read Item 7.
Managements Discussion and Analysis of Financial Condition and Results of Operations.
If our actual production and sales for any period are less than the corresponding volume of
derivative contracts for that period (including reductions in production due to operational
delays), or if we are unable to perform our activities as planned, we might be forced to satisfy
all or a portion of our derivative obligations without the benefit of the cash flow from our sale
of the underlying physical commodity, resulting in a substantial diminution of our liquidity. In
addition, our oil and gas financial derivative activities can result in substantial losses. Such
losses could occur under various circumstances, including any circumstance in which a counterparty
does not perform its obligations under the applicable derivative arrangement, the arrangement is
imperfect or our derivative policies and procedures are not followed or do not work as planned.
Under the terms of our senior credit facility with Bank of Montreal, the percentage of our total
production volumes with respect to which we will be allowed to enter into derivative contracts is
limited, and we therefore retain the risk of a price decrease for our remaining production volume.
If oil and natural gas prices decline, we may be required to take additional write-downs of the
carrying values of our oil and natural gas properties, potentially triggering
earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting
the trading value of our securities.
There is a risk that we will be required to write down the carrying value of our oil and gas
properties, which would reduce our earnings and stockholders equity. We account for our natural
gas and crude oil exploration and development activities using the successful efforts method of
accounting. Under this method, costs of productive exploratory wells, developmental dry holes and
productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are
also capitalized. Exploration costs, including personnel costs, certain geological and geophysical
expenses and delay rentals for oil and gas leases are charged to expense as incurred. Exploratory
drilling costs are initially capitalized, but charged to expense if and when the well is determined
not to have found reserves in commercial quantities. The capitalized costs of our oil and gas
properties may not exceed the estimated future net cash flows from our properties. If capitalized
costs exceed future cash flows, we write down the costs of the properties to our estimate of fair
market value. Any such charge will not affect our cash flow from operating activities, but will
reduce our earnings and stockholders equity.
Additional write downs could occur if oil and gas prices decline or if we have substantial downward
adjustments to our estimated proved reserves, increases in our estimates of development costs or
deterioration in our drilling results. Because our properties currently serve, and will likely
continue to serve, as collateral for advances under our existing and future credit facilities, a
write-down in the carrying values of our properties could require us to repay debt earlier than we
would otherwise be required. It is likely that the cumulative effect of a write-down could also
negatively impact the value of our securities, including our common stock.
The application of the successful efforts method of accounting requires managerial judgment to
determine the proper classification of wells designated as developmental or exploratory, which will
ultimately determine the proper accounting treatment of the costs incurred. The results from a
drilling operation can take considerable time to analyze and the determination that commercial
reserves have been discovered requires both judgment and industry experience. Wells may be
completed that are assumed to be productive but may actually deliver oil and gas in quantities
insufficient to be economic, which may result in the abandonment of the wells at a later date.
Wells are drilled that have targeted geologic structures that are both developmental and
exploratory in nature, and an allocation of costs is required to properly account for the results.
The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair
value of these costs with reference to drilling activity in a given area.
We review our oil and gas properties for impairment annually or whenever events and circumstances
indicate a decline in the recoverability of their carrying value. Once incurred, a write down of
oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given
the complexities associated with oil and gas reserve estimates and the history of price volatility
in the oil and gas markets, events may arise that would require us to record an impairment of the
book values associated with oil and gas properties.
17
Drilling for and producing oil and natural gas are high risk activities with many uncertainties
that could adversely affect our business, financial condition and results of operations.
Our future success will depend on the success of our exploitation, exploration, development and
production activities. Our oil and natural gas exploration and production activities are subject to
numerous risks beyond our control, including the risk that drilling will not result in commercially
viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise
exploit prospects or properties will depend in part on the evaluation of data obtained through
geophysical and geological analyses, production data and engineering studies, the results of which
are often inconclusive or subject to varying interpretations. Please read Item 1A. Our estimated
reserves are based on many assumptions that may turn out to be inaccurate. Any significant
inaccuracies in these reserve estimates or underlying assumptions may materially affect the
quantities and present value of our reserves below for a discussion of the uncertainties involved
in these processes. Our costs of drilling, completing and operating wells are often uncertain
before drilling commences. Overruns in budgeted expenditures are common risks that can make a
particular project uneconomical. Further, our future business, financial condition, results of
operations, liquidity or ability to finance planned capital expenditures could be materially and
adversely affected by any factor that may curtail, delay or cancel drilling, including the
following:
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delays imposed by or resulting from compliance with regulatory requirements; |
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unusual or unexpected geological formations; |
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pressure or irregularities in geological formations; |
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shortages of or delays in obtaining equipment and qualified personnel; |
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equipment malfunctions, failures or accidents; |
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unexpected operational events and drilling conditions; |
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pipe or cement failures; |
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casing collapses; |
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lost or damaged oilfield drilling and service tools; |
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loss of drilling fluid circulation; |
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uncontrollable flows of oil, natural gas and fluids; |
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fires and natural disasters; |
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environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases; |
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adverse weather conditions; |
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reductions in oil and natural gas prices; |
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oil and natural gas property title problems; and |
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market limitations for oil and natural gas. |
If any of these factors were to occur with respect to a particular field, we could lose all or a
part of our investment in the field, or we could fail to realize the expected benefits from the
field, either of which could materially and adversely affect our revenue and profitability.
Our proved reserves and related PV-10 as of December 31, 2009 have been reported under new SEC
rules that went into effect on January 1, 2010. The estimates provided in accordance with the new
SEC rules may change materially as a result of interpretive guidance that may be subsequently
released by the SEC.
We have included in this report certain estimates of our proved reserves and related PV-10 at
December 31, 2009 as prepared consistent with our independent reserve engineers interpretations of
the new SEC rules relating to disclosures of estimated natural gas and oil reserves. These new
rules are effective for fiscal years ending on or after December 31, 2009. These newly adopted
rules will require SEC reporting companies to prepare their reserve estimates using revised reserve
definitions and revised pricing based on 12-month unweighted first-day-of-the-month average
pricing. The SEC has not specifically reviewed our reserve estimates under the new rules and has
released only limited interpretive guidance regarding reporting of reserve estimates under the new
rules. Accordingly, while the estimates of our proved reserves and related PV-10 at December 31,
2009 included in this report have been prepared based on what we and our independent reserve
engineers believe to be reasonable interpretations of the new SEC rules, those estimates could
ultimately differ materially from any estimates we might prepare applying more specific SEC
interpretive guidance.
We may be limited in our ability to book additional proved undeveloped reserves under the new SEC
rules.
Another impact of the new SEC reserve rules is a general requirement that, subject to limited
exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be
drilled within five years of the date of booking. This new rule may limit our potential to book
additional proved undeveloped reserves as we pursue our drilling program on our undeveloped
properties.
18
Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any
significant inaccuracies in these reserve estimates or underlying assumptions may materially affect
the quantities and present value of our reserves.
Estimates of oil and natural gas reserves are inherently imprecise. The process of estimating oil
and natural gas reserves is complex. It requires interpretations of available technical data and
many assumptions, including assumptions relating to economic factors. Any significant inaccuracies
in these interpretations or assumptions could materially affect the estimated quantities and
present value of reserves. To prepare our estimates, we must project production rates and the
timing of development expenditures. We must also analyze available geological, geophysical,
production and engineering data. The extent, quality and reliability of this data can vary. The
process also requires economic assumptions about matters such as oil and natural gas prices,
drilling and operating expenses, capital expenditures, taxes and availability of funds for capital
expenditures.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures,
operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary
from our estimates. Any significant variance could materially affect the estimated quantities and
present value of reserves shown in this report. In addition, we may adjust estimates of proved
reserves to reflect production history, results of exploration and development activities,
prevailing oil and natural gas prices and other factors, many of which are beyond our control.
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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actual cost of development and production expenditures; |
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the amount and timing of actual production; |
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supply of and demand for oil and natural gas; 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.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable
quantities.
Our prospects are in various stages of evaluation. There is no way to predict with certainty in
advance of drilling and testing whether any particular prospect will yield oil or natural gas in
sufficient quantities to recover drilling or completion costs or to be economically viable,
particularly in light of the current economic environment. The use of seismic data and other
technologies, and the study of producing fields in the same area, will not enable us to know
conclusively before drilling whether oil or natural gas will be present or, if present, whether oil
or natural gas will be present in commercially viable quantities. Moreover, the analogies we draw
from available data from other wells, more fully explored prospects or producing fields may not be
applicable to our drilling prospects.
19
We cannot control activities on properties that we do not operate and are unable to control their
proper operation and profitability.
We do not operate all of the properties in which we own an ownership interest. As a result, we have
limited ability to exercise influence over, and control the risks associated with, the operations
of these non-operated properties. The failure of an operator of our wells to adequately perform
operations, an operators breach of the applicable agreements or an operators failure to act in
ways that are in our best interests could reduce our production, revenues and reserves. The success
and timing of our drilling and development activities on properties operated by others therefore
depend upon a number of factors outside of our control, including the operators:
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nature and timing of drilling and operational activities; |
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timing and amount of capital expenditures; |
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expertise and financial resources; |
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the approval of other participants in drilling wells; and |
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selection of suitable technology. |
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which
would adversely affect our business, financial condition and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates
that vary depending on reservoir characteristics and other factors. Our future oil and natural gas
reserves and production, and therefore our cash flow and income, are highly dependent on our
success in efficiently developing and exploiting our current reserves and economically finding or
acquiring additional recoverable reserves. We may not be able to develop, find or acquire
additional reserves to replace our current and future production at acceptable costs, which would
adversely affect our business, financial condition and results of operations.
Our future acquisitions may yield revenue or production that varies significantly from our
projections.
In acquiring producing properties, we will assess the recoverable reserves, future natural gas and
oil prices, operating costs, potential liabilities and other factors relating to the properties.
Our assessments are necessarily inexact, and their accuracy is inherently uncertain. Our review of
a subject property in connection with our acquisition assessment will not reveal all existing or
potential problems or permit us to become sufficiently familiar with the property to assess fully
its deficiencies and capabilities. We may not inspect every well, and we may not be able to observe
structural and environmental problems even when we do inspect a well or retain a third-party
consultant. If problems are identified, the seller may be unwilling or unable to provide effective
contractual protection against all or part of those problems. Any acquisition of property interests
may not be economically successful, and unsuccessful acquisitions may have a material adverse
effect on our financial condition and future results of operations.
Our development and exploration operations require substantial capital, and we may be unable to
obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties
and a decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make
substantial capital expenditures in our business and operations for the exploration for, and
development, production and acquisition of, oil and natural gas reserves. To date, we have financed
capital expenditures primarily with proceeds from bank borrowings, cash generated by operations and
preferred and common stock equity offerings. We intend to finance our capital expenditures with the
sale of equity, asset sales, cash flow from operations and current and new financing arrangements
with our banks. Our cash flow from operations and access to capital is subject to a number of
variables, including:
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our proved reserves; |
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the amount 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. |
If our revenues 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 sustain our operations at current levels. We may need to seek additional financing in
the future. In addition, we may not be able to obtain debt or equity financing on terms favorable
to us, or at all, depending on market conditions. The failure to obtain additional financing could
result in a curtailment of our operations relating to exploration and development of our prospects,
which in turn could lead to a possible loss of properties and a decline in our oil and natural gas
reserves. Also, our credit facility contains covenants that restrict our ability to, among other
things, materially change our business, approve and distribute dividends, enter into certain
transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell
assets, make loans to others, make investments, enter into mergers, incur liens, and enter into
agreements regarding swap and other derivative transactions.
20
Restrictive covenants in our senior credit facility may restrict our ability to pursue our business
strategies.
The Restated Credit Agreement with our lenders contains certain negative covenants that among other
things, restrict our ability to, with certain exceptions:
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change the nature of our business; |
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dispose of all or substantially all of our assets or enter into mergers, consolidations
or similar transactions; |
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make investments, loans or advances; |
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pay cash dividends, unless certain conditions are met and are subject to a basket of
$2.5 million per year available for payment of dividends on preferred stock; and |
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enter into transactions with affiliates. |
The Restated Credit Agreement with our lenders also requires the Company to satisfy certain
affirmative financial covenants, including maintaining:
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an EBITDAX to interest ratio of not less than 2.5 to 1.0; |
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a debt to EBITDAX ratio of not more than (a) 4.5 to 1.0 for the fiscal quarters ending
March 31, 2010, June 30, 2010, and September 30, 2010, and (b) 4.0 to 1.0 for each fiscal
quarter ending thereafter; and |
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a ratio of consolidated current assets to consolidated current liability of not less
than 1.0 to 1.0. We are also required to enter into certain commodity price hedging
agreements pursuant to the terms of the credit facilities. |
Our ability to comply with these covenants may be affected by events beyond our control, and
any material deviations from our forecasts could require us to seek waivers or amendments of
covenants, alternative sources of financing or reductions in expenditures. We cannot assure you
that such waivers, amendments or alternative financings could be obtained or, if obtained, would be
on terms acceptable to us.
Our substantial indebtedness could adversely affect our financial condition and our ability to
operate our business.
As of March 29, 2010 our outstanding indebtedness was approximately $64 million. Our substantial
debt could have important adverse consequences for holders of our common stock, including the
following:
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it may be difficult for us to satisfy our obligations, including debt
service requirements under our credit agreements; |
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our ability to obtain additional financing for working capital, capital
expenditures, debt service requirements, and other general corporate purposes
may be impaired; |
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a significant portion of our cash flow is committed to payments on our
debt, which will reduce the funds available to us for other purposes, such as
future capital expenditures; |
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we are more vulnerable to price fluctuations and to economic downturns and
adverse industry conditions and our flexibility to plan for, or react to,
changes in our business or industry is more limited; |
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our ability to capitalize on business opportunities, and to react to
competitive pressures, as compared to others in our industry, may be limited |
Our obligations under our Senior Credit Facility are secured by substantially all of our assets,
and any failure to meet our debt obligations would adversely affect our business and financial
condition.
PRC Williston LLC, our majority-owned subsidiary, Sharon Resources, Inc. and Triad Hunter, LLC, our
wholly-owned subsidiaries, and our indirect wholly-owned subsidiary, Eureka Hunter Pipeline, LLC,
have each guaranteed the performance of all of our obligations under the Senior Credit Facility,
and we have collateralized our obligations under the Senior Credit Facility through our grant of a
first priority security interest in our ownership interest in PRC Williston, LLC, Sharon Resources,
Inc., Triad Hunter LLC, Eureka Hunter Pipeline, LLC and substantially all of our oil and gas
properties, subject only to certain permitted liens.
Our ability to meet debt obligations under the Senior Credit Facility will depend on the future
performance of our properties, which will be affected by financial, business, economic, regulatory
and other factors, many of which we are unable to control. Our failure to service this debt could
result in a default under the credit facilities, which could result in the loss of our ownership
interest in PRC Williston, LLC, Sharon Resources, Inc., Triad Hunter LLC, Eureka Hunter Pipeline
LLC and our oil and gas assets and otherwise materially adversely affect our business, financial
condition and results of operations.
21
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field
services could adversely affect our ability to execute on a timely basis our exploration and
development plans within our budget.
We may, from time to time, encounter difficulty in obtaining, or an increase in the cost of
securing, drilling rigs, equipment and supplies. In addition, larger producers may be more likely
to secure access to such equipment by offering more lucrative terms. If we are unable to acquire
access to such resources, or can obtain access only at higher prices, our ability to convert our
reserves into cash flow could be delayed and the cost of producing those reserves could increase
significantly, which would adversely affect our financial condition and results of operations.
We depend on pipelines owned by others to transport and sell our natural gas production. Disruption
of, capacity constraints in, or proximity to pipeline systems could limit sales of our natural gas.
In many instances, we transport our natural gas to market by utilizing pipelines owned by others.
If pipelines do not exist near our producing wells, if pipeline capacity is limited or if pipeline
capacity is unexpectedly curtailed or disrupted, we may have to reduce sales of our production of
gas because we do not have facilities to store excess inventory. If this occurs, our revenues will
be reduced, and our unit costs will also increase. In addition, if pipeline gas quality
requirements change for a pipeline, we might be required to install additional processing
equipment, which could increase our costs. If this should occur, the pipeline could curtail our gas
flows until the gas delivered to their pipeline is in compliance.
New technologies may cause our current exploration and drilling methods to become obsolete.
The oil and gas industry is subject to rapid and significant advancements in technology, including
the introduction of new products and services using new technologies. As competitors use or develop
new technologies, we may be placed at a competitive disadvantage, and competitive pressures may
force us to implement new technologies at a substantial cost. In addition, competitors may have
greater financial, technical and personnel resources that allow them to enjoy technological
advantages and may in the future allow them to implement new technologies before we can. One or
more of the technologies that we currently use or that we may implement in the future may become
obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or
at a cost that is acceptable to us. If we are unable to maintain technological advancements
consistent with industry standards, our operations and financial condition may be adversely
affected.
We may incur substantial losses and be subject to substantial liability claims as a result of our
oil and natural gas operations, and we may not have enough insurance to cover all of the risks that
we may ultimately face.
We maintain insurance coverage against some, but not all, potential losses to protect against the
risks we foresee. We do not carry business interruption insurance. We may elect not to carry
certain types or amounts of insurance if our management believes that the cost of available
insurance is excessive relative to the risks presented. In addition, it is not possible to insure
fully against pollution and environmental risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and
underinsured events could materially and adversely affect our business, financial condition and
results of operations. Our oil and natural gas exploration and production activities are subject to
all of the operating risks associated with drilling for and producing oil and natural gas,
including the possibility of:
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environmental hazards, such as uncontrollable flows of oil, natural
gas, brine, well fluids, toxic gas or other pollution into the
environment, including groundwater and shoreline contamination; |
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abnormally pressured formations; |
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mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses; |
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fires and explosions; |
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personal injuries and death; and |
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natural disasters. |
Any of these risks could adversely affect our ability to conduct operations or result in
substantial losses to us. If a significant accident or other event occurs and is not fully covered
by insurance, then that accident or other event could adversely affect our financial condition,
results of operations and cash flows.
We have completed several recent acquisitions, and there is no assurance that we will be able to
satisfy our contractual and financial obligations thereunder.
In mid-2009 we acquired Sharon Resources, Inc. in a stock acquisition and increased our ownership
interest in the East Chalkley field in Louisiana. More significantly, in February 2010, we closed
the Triad acquisition and in doing so incurred certain significant
contractual and financial obligations, including our commitments under the Senior Credit Facility
and with respect to the Series B Preferred Stock issued to Triad and the 10.25% Series C Cumulative
Perpetual Preferred Stock that represented a portion of the acquisition financing, and other
contractual obligations with respect to the ongoing operations of Triad.
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Although we have consummated the Triad transaction, there is no assurance we will be able to have
sufficient equity capital or borrowing capacity to operate the acquired assets post-closing. There
is also no assurance that we can successfully assimilate Triads properties, operations and
personnel into our organization.
We do not have a significant operating history and, as a result, there is a limited amount of
information about us on which to make an investment decision.
In July 2005, we acquired our initial exploratory drilling prospects, and in November 2005 we
commenced drilling activities. In December 2005, we commenced production from our first oil and gas
prospects, and in February 2006 we received our first revenues from oil and gas production. In
February 2007 we acquired a 43% average working interest in 15 producing oil fields and
approximately 150 producing wells located in the Williston Basin in North Dakota at which point we
began to receive revenue from associated oil and gas production. Since that time, we have expanded
secondary recovery operations in the Williston Basin properties in anticipation of drilling
additional producing wells in the future. Beginning in 2007 to present, we have actively
participated with Approach Resources Corporation in the drilling of approximately 100 wells located
in Crockett County, Texas. Beginning in the last quarter 2008, we participated with Goodrich
Petroleum Corporation in five successful wells located in Nacogdoches County, Texas. On September
30, 2009, we acquired Sharon Resources, Inc., a wholly-owned subsidiary of Calgary based Sharon
Energy Ltd., bringing an inventory of drilling projects in addition to three exploration and
evaluation professionals. In addition, on September 14, 2009, we entered into a Purchase and Sale
Agreement with Centurion to acquire for $1.7 million all of Centurions ownership interest in the
East Chalkley Unit in Cameron Parish, Louisiana. This property acquisition was completed on
October 15, 2009 and is operated by our Company. Our Triad acquisition recently closed on February
12, 2010, and as a result, there is limited information upon which to assess our ability to operate
successfully the acquired assets. Accordingly, there is little operating history upon which to
judge our business strategy, our management team or our current operations.
We have a history of losses and cannot assure you that we will be profitable in the foreseeable
future.
Since we entered the oil and gas business in April 2005, through December 31, 2009, we have
incurred a cumulative net loss from operations of $27.3 million. If we fail to generate profits
from our operations, we will not be able to sustain our business. We may never report profitable
operations or generate sufficient revenue to maintain our company as a going concern.
The acquisition and integration of the Triad operating interests and other assets may divert
management from other important business activities. This diversion, together with other
difficulties in integrating Triads business and properties, may have a material adverse effect on
our business, financial condition and results of operations.
The difficulties and demands of integrating Triads assets and businesses into our Company may
divert management attention from other important business activities. In addition to entering into
new business activities, as a result of the Triad acquisition, we now operate in new geographic
markets and are subject to additional and unfamiliar legal and regulatory requirements. Compliance
with such regulatory requirements may impose substantial additional obligations on us and our
management, cause us to expend additional time and resources in compliance activities and increase
our exposure to penalties or fines for non-compliance with such additional legal requirements. The
demands of integrating an acquired business could have a material adverse effect on our business,
financial condition and results of operations.
We have limited management and staff and will be dependent upon partnering arrangements.
Prior to the Triad acquisition, we had 18 employees, including our nine officers. As a result of
the Triad acquisition the Company and its affiliates, including Triad Hunter LLC, had approximately
139 total employees as of March 29, 2010. Despite this increase in employment, we expect that we
will continue to require the services of independent consultants and contractors to perform various
professional services, including reservoir engineering, land, legal, environmental and tax
services. We will also pursue alliances with partners in the areas of geological and geophysical
services and prospect generation, evaluation and prospect leasing. Our dependence on third party
consultants and service providers creates a number of risks, including but not limited to:
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the possibility that such third parties may not be available to us as and when needed;
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the risk that we may not be able to properly control the timing and quality of work
conducted with respect to our projects. |
If we experience significant delays in obtaining the services of such third parties or poor
performance by such parties, our results of operations and stock price will be materially adversely
affected.
23
Our business may suffer if we lose key personnel.
Our operations depend on the continuing efforts of our executive officers and senior management.
Our business or prospects could be adversely affected if any of these persons does not continue in
their management role with us and we are unable to attract and retain qualified replacements.
Additionally, we do not carry key person insurance for any of our executive officers or senior
management.
We are subject to complex laws and regulations that can adversely affect the cost, manner or
feasibility of doing business.
The exploration, development, production and sale of oil and natural gas are subject to extensive
federal, state, and local laws and regulations. Such regulation includes requirements for permits
to drill and to conduct other operations and for provision of financial assurances (such as bonds)
covering drilling and well operations. Other activities subject to regulation are:
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the location and spacing of wells; |
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the unitization and pooling of properties; |
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the method of drilling and completing wells; |
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the surface use and restoration of properties upon which wells are drilled; |
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the plugging and abandoning of wells; |
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the disposal of fluids used or other wastes generated in connection with our drilling operations; |
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the marketing, transportation and reporting of production; and |
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the valuation and payment of royalties. |
Under these laws, we could be subject to claims for personal injury or property damages, including
natural resource damages, which may result from the impact of our operations. Failure to comply
with these laws also may result in the suspension or termination of our operations and subject us
to administrative, civil and criminal penalties. Moreover, these laws could change in ways that
substantially increase our costs of compliance. Any such liabilities, penalties, suspensions,
terminations or regulatory changes could have a material adverse effect on our financial condition
and results of operations.
We must obtain governmental permits and approvals for our drilling operations, which can be a
costly and time consuming process, which may result in delays and restrictions on our operations.
Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance.
Requirements imposed by these authorities may be costly and time consuming and may result in delays
in the commencement or continuation of our exploration or production operations. For example, we
are often required to prepare and present to federal, state or local authorities data pertaining to
the effect or impact that proposed exploration for or production of natural gas or oil may have on
the environment. Further, the public may comment on and otherwise engage in the permitting process,
including through intervention in the courts. Accordingly, the permits we need may not be issued,
or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our
ability to conduct our operations or to do so profitably.
Our operations expose us to substantial costs and liabilities with respect to environmental
matters.
Our oil and natural gas operations are subject to stringent federal, state and local laws and
regulations governing the release of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may require the acquisition of a permit before
drilling commences, restrict the types, quantities and concentration of substances that can be
released into the environment in connection with our drilling and production activities, limit or
prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected
areas, and impose substantial liabilities for pollution that may result from our operations.
Failure to comply with these laws and regulations may result in the assessment of administrative,
civil and criminal penalties, the imposition of investigatory or remedial obligations or injunctive
relief. Under existing environmental laws and regulations, we could be held strictly liable for the
removal or remediation of previously released materials or property contamination regardless of
whether the release resulted from our operations, or our operations were in compliance with all
applicable laws at the time they were performed. Changes in environmental laws and regulations
occur frequently, and any changes that result in more stringent or costly waste handling, storage,
transport, disposal or cleanup requirements could require us to make significant expenditures to
maintain compliance, and may otherwise have a material adverse effect on our competitive position,
financial condition and results of operations.
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Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could
result in increased costs and additional operating restrictions or delays.
Congress is currently considering legislation to amend the federal Safe Drinking Water Act to
require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic
fracturing process. Hydraulic fracturing is an important and commonly used
process in the completion of unconventional oil and natural gas wells in shale formations. This
process involves the injection of water, sand and chemicals under pressure into rock formations to
stimulate production. Sponsors of two companion bills, which are currently pending in the House
Energy and Commerce Committee and the Senate Committee on Environment and Public Works Committee
have asserted that chemicals used in the fracturing process could adversely affect drinking water
supplies. The proposed legislation would require the reporting and public disclosure of chemicals
used in the fracturing process, which could make it easier for third parties opposing the hydraulic
fracturing process to initiate legal proceedings based on allegations that specific chemicals used
in the fracturing process could adversely affect groundwater. In addition, this legislation, if
adopted, could establish an additional level of regulation at the federal level that could lead to
operational delays or increased operating costs and could result in additional regulatory burdens.
The adoption of any future federal or state laws or implementing regulations imposing reporting
obligations on, or otherwise limiting, the hydraulic fracturing process could make it more
difficult and more expensive to complete new wells in shale formations and increase our costs of
compliance and doing business.
Climate change legislation or regulations restricting emissions of greenhouse gases could result
in increased operating costs and reduced demand for the oil, natural gas and NGLs that we produce.
A variety of regulatory developments, proposals or requirements and legislative initiatives have
been introduced in the United States that are focused on restricting the emission of carbon
dioxide, methane and other greenhouse gases. On June 26, 2009, the U.S. House of Representatives
passed the American Clean Energy and Security Act of 2009, or ACESA, which would establish an
economy-wide cap-and-trade program to reduce emissions of greenhouse gases in the United States,
including carbon dioxide and methane. The U.S. Senate has begun work on its own legislation for
controlling and reducing greenhouse gas emissions in the United States. Although it is not possible
at this time to predict whether or when the Senate may act on climate change legislation, how any
bill passed by the Senate would be reconciled with ACESA, or how federal legislation may be
reconciled with state and regional requirements, any future federal laws or implementing
regulations that may be adopted to address greenhouse gas emissions could require us to incur
increased operating costs and could adversely affect demand for the oil, natural gas and NGLs that
we produce.
In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gas emissions
may be regulated as an air pollutant under the federal Clean Air Act. On December 15, 2009, the
U.S. Environmental Protection Agency, or EPA, officially published its findings that emissions of
carbon dioxide, methane and other greenhouse gases present an endangerment to human health and
the environment because emissions of such gases are, according to the EPA, contributing to warming
of the earths atmosphere and other climatic changes. These findings by the EPA allow the agency to
proceed with the adoption and implementation of regulations that would restrict emissions of
greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009,
the EPA also proposed two sets of regulations in anticipation of finalizing its findings that would
require a reduction in emissions of greenhouse gases from motor vehicles and that could also lead
to the imposition of greenhouse gas emission limitations in Clean Air Act permits for certain
stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the
reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the
United States beginning in 2011 for emissions occurring in 2010.
Although it is not possible at this time to predict whether proposed legislation or regulations
will be adopted as initially written, if at all, or how legislation or new regulations that may be
adopted to address greenhouse gas emissions would impact our business, any such future laws and
regulations could result in increased compliance costs or additional operating restrictions. Any
additional costs or operating restrictions associated with legislation or regulations regarding
greenhouse gas emissions could have a material adverse effect on our business, financial condition
and results of operation. In addition, these developments could curtail the demand for fossil fuels
such as oil and gas in areas of the world where our customers operate and thus adversely affect
demand for our products and services, which may in turn adversely affect our future results of
operations.
The adoption of derivatives legislation by Congress and related regulations could have an adverse
impact on our ability to hedge risks associated with our business.
The U.S. Congress is currently considering legislation to increase the regulatory oversight of the
over-the-counter derivatives markets in order to promote more transparency in those markets, and
impose restrictions on certain derivatives transactions, which could affect the use of derivatives
in hedging transactions. ACESA contains provisions that would prohibit private energy commodity
derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading
Commission (CFTC) to regulate derivative transactions related to energy commodities, including oil
and natural gas, and to mandate clearance of such derivative contracts through registered
derivative clearing organizations. Under ACESA, the CFTCs expanded authority over energy
derivatives would terminate upon the adoption of general legislation covering derivative regulatory
reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to
determine whether to set limits on trading and positions in commodities with finite supply,
particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC
also is evaluating whether position limits should be applied consistently across all markets and
participants. In addition, the Treasury Department recently has indicated that it intends to
propose legislation to subject all OTC derivative dealers and all other major OTC derivative market
participants to substantial supervision and regulation, including by imposing conservative capital
and margin requirements and strong business conduct standards. Derivative contracts that are not
cleared through central clearinghouses and exchanges may be
subject to substantially higher capital and margin requirements. Although it is not possible at
this time to predict whether or when Congress may act on derivatives legislation or how any climate
change bill approved by the Senate would be reconciled with ACESA, any new laws or regulations in
this area may result in increased costs and cash collateral requirements for the types of oil and
gas derivative instruments we use to hedge and otherwise manage our financial risks related to
swings in oil and gas commodity prices. Any legislative changes may impose additional restrictions
on our trading and commodity positions, and could have an adverse effect on our ability to hedge
risks associated with our business and on the cost of our hedging activity.
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Competition in the oil and natural gas industry is intense, which may adversely affect our ability
to compete.
We operate in a highly competitive environment for acquiring properties, exploiting mineral leases,
marketing oil and natural gas and securing trained personnel. Many of our competitors possess and
employ financial, technical and personnel resources substantially greater than ours, which can be
particularly important in the areas in which we operate. Those companies may be able to pay more
for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for
and purchase a greater number of properties and prospects than our financial or personnel resources
permit. Our ability to acquire additional prospects and to find and develop reserves in the future
will depend on our ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. We may not be able to compete successfully in the
future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting
and retaining quality personnel and raising additional capital.
Risks Related to Our Equity Securities
Since being listed on the NYSE Amex (formerly, the American Stock Exchange) in August of 2006, the
price of our common stock has fluctuated substantially and may fluctuate substantially in the
future.
Since being listed on the NYSE Amex (formerly, the American Stock Exchange), the price of our
common stock has fluctuated substantially. From August 30, 2006 to March 29, 2010, the trading
price at the close of the market of our common stock ranged from a low of $0.20 per share to a high
of $3.86 per share. We expect our common stock to continue to be subject to fluctuations as a
result of a variety of factors, including factors beyond our control. These factors include:
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changes in oil and natural gas prices; |
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variations in quarterly drilling, recompletions, acquisitions, and operating results; |
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changes in financial estimates by securities analysts; |
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changes in market valuations of comparable companies; |
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additions or departures of key personnel; |
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the level of our overall indebtedness; |
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future issuances of our stock; and |
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the other risks and uncertainties described in this Risk Factors section and elsewhere in this report. |
We may fail to meet the expectations of our stockholders or of securities analysts at some time in
the future, and our stock price could decline as a result. Volatility or depressed market prices of
our common stock could make it difficult for you to resell shares of our common stock when you want
or at attractive prices.
The market for our common stock is limited and may not provide investors with either liquidity or a
market based valuation of our common stock.
Our common stock is traded on the NYSE Amex (formerly known as the American Stock Exchange) stock
exchange market under the symbol MHR. On March 29, 2010, the last reported sale price of our
common stock on the NYSE Amex was $3.04 per share. The present volume of trading in our common
stock may not provide investors sufficient liquidity in the event they wish to sell their shares of
common stock. There can be no assurance that an active market for our common stock will be
available for trading in large volumes. In addition, the stock market in general, and early stage
public companies in particular, have experienced extreme price and volume fluctuations that have
often been unrelated or disproportionate to the operating performance of such companies. If we are
unable to further develop an active market for our common stock, you may not be able to sell our
common stock at prices you consider to be fair or at times that are convenient for you, or at all.
We will likely issue additional common stock in the future, which would dilute our existing
stockholders.
In the future we may issue up to our previously authorized and unissued securities, including
shares of our common stock or securities convertible into or exchangeable for our common stock,
resulting in the dilution of the ownership interests of our stockholders. We are authorized under
our amended and restated certificate of incorporation to issue 100,000,000 shares of common stock
and 10,000,000 shares of preferred stock with such designations, preferences, and rights as may be
determined by our board of directors. As of March 29, 2010, there were 57,979,111 shares of our
common stock issued and outstanding and there were no shares of our Series A Preferred Stock issued
and outstanding, 4 million shares of our Series B Preferred Stock issued and outstanding and
356,152 shares of our Series C Preferred Stock issued and outstanding.
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We have an effective shelf registration statement from which additional shares of our common stock
and other securities can be issued. We may also issue additional shares of our common stock or
securities convertible into or exchangeable for our common stock in connection with the hiring of
personnel, future acquisitions, future private placements of our securities for capital raising
purposes or for other business purposes. Future issuances of our common stock, or the perception
that such issuances could occur, could have a material adverse effect on the price of our common
stock at any given time.
Additionally, we are engaged in the issuance and sale of our common stock and our Series C
Preferred Stock from time to time through Wm. Smith & Co., as our exclusive sales manager pursuant
to an At The Market sales agreement between the Company and Wm. Smith & Co. Sales of shares of
our common stock, if any, by Wm. Smith & Co. will be made in privately negotiated transactions or
in any method permitted by law deemed to be an At The Market offering as defined in Rule 415
promulgated under the Securities Act of 1933, as amended, at negotiated prices, at prices
prevailing at the time of sale or at prices related to such prevailing market prices, including
sales made directly on the NYSE Amex or sales made through a market maker other than on an
exchange.
We may issue additional Series C Preferred stock in the future, which could dilute our existing
holders of our outstanding Series C Preferred Stock.
We have an effective shelf registration statement from which additional shares of our common stock
and other securities can be issued. In addition, we may also issue additional shares of our Series
C Preferred Stock in connection with the hiring of personnel, future acquisitions, future private
placements of our securities for capital raising purposes or for other business purposes.
Additionally, we are engaged in the issuance and sale of up to an additional $9,626,250 of our
Series C Preferred Stock from time to time through Wm. Smith & Co., as our exclusive sales
manager. Sales of shares of our Series C Preferred Stock, if any, by Wm. Smith & Co. will be made
in privately negotiated transactions or in any method permitted by law deemed to be an At The
Market offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended,
at negotiated prices, at prices prevailing at the time of sale or at prices related to such
prevailing market prices, including sales made directly on the NYSE Amex or sales made through a
market maker other than on an exchange.
Our amended and restated certificate of incorporation, amended and restated bylaws, and Delaware
law contain provisions that could make it more difficult for a third party to acquire us without
the consent of our board of directors, our Chairman and other executive officers, who collectively
beneficially own approximately 10% of the fully diluted outstanding shares of our common stock as
of March 29, 2010.
Provisions in our amended and restated certificate of incorporation and amended and restated bylaws
could have the effect of delaying or preventing a change of control of us and changes in our
management. These provisions include the following:
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the ability of our board of directors to issue shares of our common
stock and preferred stock without stockholder approval; |
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the ability of our board of directors to make, alter, or repeal our bylaws without further stockholder approval; |
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the requirement for advance notice of director nominations to our
board of directors and for proposing other matters to be acted upon at
stockholder meetings; |
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the prohibition on stockholders taking action by written consent; |
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requiring that special meetings of stockholders be called only by our
Chairman, by a majority of our board of directors, by our Chief
Executive Officer or by our President; and |
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allowing our directors, and not our stockholders, to fill vacancies on
the board of directors, including vacancies resulting from removal or
enlargement of the board of directors. |
In addition, we are subject to the provisions of Section 203 of the Delaware General Corporation
Law. These provisions may prohibit large stockholders, in particular those owning 15% or more of
our outstanding voting stock, from merging or combining with us.
As of March 29, 2010, our board of directors and our other executive officers collectively owned
approximately 13% of the outstanding shares of our common stock. Although this is not a majority of
our outstanding common stock, these stockholders, acting together, will have the ability to exert
substantial influence over all matters requiring stockholder approval, including the election and
removal of directors, any proposed merger, consolidation, or sale of all or substantially all of
our assets and other corporate transactions.
The provisions in our amended and restated certificate of incorporation and amended and restated
bylaws and under Delaware law, and the concentrated ownership of our common stock by our Chairman
and other executive officers, could discourage potential takeover attempts and could reduce the
price that investors might be willing to pay for shares of our common stock.
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Because we have no plans to pay dividends on our common stock, stockholders must look solely to
appreciation of our common stock to realize a gain on their investments.
We do not anticipate paying any dividends on our common stock in the foreseeable future. We
currently intend to retain future earnings, if any, to finance the expansion of our business. Our
future dividend policy is within the discretion of our board of directors and will depend upon
various factors, including our business, financial condition, results of operations, capital
requirements and investment opportunities. In addition, our Senior Credit Facility limits the
payment of dividends without the prior written consent of the lenders. Accordingly, stockholders
must look solely to appreciation of our common stock to realize a gain on their investment, which
may not occur.
We are able to issue shares of preferred stock with greater rights than our common stock.
Our amended and restated certificate of incorporation authorizes our board of directors to issue
one or more series of preferred stock and set the terms of the preferred stock without seeking any
further approval from our stockholders. Any preferred stock that is issued may rank ahead of our
common stock in terms of dividends, liquidation rights, or voting rights. If we issue preferred
stock, it may adversely affect the market price of our common stock.
Our assets are subject to liquidation preferences in favor of the holders of our Series B and
Series C Preferred Stock, which will impact the rights of holders of our common stock if we
liquidate.
On December 14, 2009, we issued and sold 214,950 shares of our Series C Preferred Stock. We have
also issued and sold additional shares of Series C Preferred Stock pursuant to the At The Market
sales agreement relating to the Series C Preferred. Pursuant to the Prospectus Supplement
relating to such At The Market sales of Series C Preferred Stock, filed January 6, 2010, we may
sell an additional $9,626,250 of Series C Preferred Stock pursuant to such At The Market sales
agreement. Under the Certificate of Designations of the Series C Preferred Stock, holders of the
Series C Preferred Stock are entitled to receive the repayment of their original investment,
together with any accrued but unpaid dividends, before any payment is made to holders of our common
stock.
The 4,000,000 shares of Series B Preferred Stock issued as partial consideration for the Triad
acquisition have an aggregate liquidation preference of $15 million, which pursuant to the
Certificate of Designations for the Series B Preferred Stock, must be paid, together with any
accrued but unpaid dividends, before any payment is made to holders of junior securities, including
holders of common stock.
In addition to the ongoing At The Market offerings of shares of our common stock, our Series C
Preferred Stock described above, and the Series B Preferred Stock described above, we may also seek
to raise additional capital through the issuance of debt securities, preferred stock or other
securities, and the holders of such securities may also have rights and preferences that are
effectively senior to those of the holders of our common stock. The holders of our common stock
might therefore receive nothing in liquidation, or receive much less than they would if there were
no Series B, Series C or other Preferred Stock or other senior securities outstanding.
Our outstanding Warrants which are exercisable into our common stock, may be exercised, which would
dilute our existing common stockholders.
We have outstanding 8,577,688 warrants that have a final maturity of 2012 exercisable into common
stock of Magnum Hunter. Any such exercise will be dilutive to our existing shareholders.
The market price of our common stock could be adversely affected by sales of substantial amounts of
our common stock and securities convertible into, or exchangeable for, shares of our common stock
in the public markets and the issuance of shares of common stock and securities convertible into,
or exchangeable for, shares of our common stock in future acquisitions.
Sales of a substantial number of shares of our common stock by us or by other parties in the public
market, or the perception that such sales may occur could cause the market price of our common
stock to decline. In addition, the sale of such shares in the public market could impair our
ability to raise capital through the sale of common stock or securities convertible into, or
exercisable for, shares of common stock.
In addition, in the future, we may issue shares of our common stock and securities convertible
into, or exchangeable for, shares of our
common stock in furtherance of our acquisitions and development of assets or businesses. If we use
our shares for this purpose, the issuances could have a dilutive effect on the value of the shares
of common stock, depending on market conditions at the time of such an event, the price we pay, the
value of the assets or business acquired and our success in exploiting the properties or
integrating the businesses we acquire and other factors.
Item 1B. UNRESOLVED STAFF COMMENTS
As of the date of this filing, we have no unresolved comments from the staff of the SEC.
28
Item 2. PROPERTIES
PROPERTIES
Appalachian Basin / Marcellus Shale
With the completion of the acquisition of Triad in February of 2010, as of March 29, 2010, the
Company held approximately 87,000 net acres in the Appalachian Basin including approximately 46,000
net acres overlying the Marcellus Shale. At year-end 2009, proved reserves from our Appalachian
Basin area of operations on an SEC basis were 5.1 MMboe, consisting of 65% oil and an estimated 61%
were classified as proved developed producing, with a PV10 of $56.4 million. Using NYMEX strip
prices, our proved reserves were 5.7 MMboe and our PV-10 was $119 million. We operate 2,048 wells
and exited 2009 with a production rate of approximately 830 Boepd.
The Appalachian Basin includes the states of West Virginia, Ohio, Kentucky, Pennsylvania, Maryland,
New York, Virginia, and Tennessee and is considered the most mature oil and gas producing region in
the United States. Because the Appalachian Basin is located near the energy-consuming regions of
the mid-Atlantic and northeastern United States, Appalachian producers have historically sold their
natural gas at a premium to the benchmark price for natural gas on the NYMEX. Historically,
producers in the Appalachian Basin developed oil and natural gas from Upper Devonian age shallow
sandstones with low permeability, which are prevalent in the region. Traditional shallow wells in
the Appalachian Basin generally produce little or no water, contributing to a low cost of
operation. In addition, most wells produce dry natural gas, which does not require processing.
However, times have changed for the Appalachian Basin. In recent years, the application of lateral
well drilling and completion technology has lead to the development of the Marcellus Shale;
transforming the Appalachian Basin into one of the countrys premier economic shale gas reserves.
The productive limits of the Marcellus Shale cover a large area within New York, Pennsylvania, Ohio
and West Virginia. This Devonian age shale is a black, organic rich shale deposit productive at
depths between 5,000 and 8,500 feet and ranges in thickness from 50 to over 200 feet. It is
considered the largest natural gas field in the country. Marcellus gas is best produced from
hydraulically fractured horizontal wellbores. These horizontal laterals exceed 2,000 feet in
length, and typically involve multistage fracturing completions. The Companys Marcellus acreage
covers Pleasants, Tyler and Ritchie counties within West Virginia. As of March 29, 2010 the
Company operates 32 vertical Marcellus wells defining the potential within our existing acreage.
The Companys mineral lease acreage covers Pleasants, Tyler, Ritchie, Calhoun, Clay, Roane, Wayne,
Wirt, Wood, and Lewis Counties in West Virginia, Leigh, Elliott and Morgan Counties in Kentucky and
Morgan, Noble and Washington Counties in Ohio. As of March 29, 2010, we had over 87,000 net acres
in the Appalachian Basin including approximately 46,000 net acres in the Marcellus Shale. As of
March 29, 2010, approximately 75% of our leases are held by production. Our shallow production
comes from the Berea, Macksburg 500 Sand, Devonian Shale and the Clinton/Medina Sands and we also
believe that our acreage may also have the possibility of producing from the Trenton-Black River
and Huron formations. The Huron formation has also benefited from lateral well drilling
technology. In addition to our Marcellus Shale acreage, we also have significant enhanced
waterflood oil recovery operations in Calhoun, Clay and Roane counties in West Virginia including
our Grannys Creek Field, Richardson Unit and Tariff unit.
In 2010, we plan to expand our Marcellus program, drilling a minimum of two horizontal wells from
our inventory of over 25 identified horizontal drilling locations at a cost of approximately $7.0
million.
North Dakota-Williston Basin / Madison Group / Bakken Shale
At December 31, 2009, the Company owned an approximately 43% average working interest in 15 fields
located in the Williston Basin in North Dakota comprising 146 wells
and approximately 18,600 gross
acres (approximately 90% of which is held by production) located in Burke, Renville, Ward,
Bottineau and McHenry counties in North Dakota. As of December 31, 2009, our proved reserves on an
SEC basis were an estimated 3.1 Mmboe with a PV-10 of $45.7 million with approximately 94 % and 89%
of our reserves and production, respectively, consisting of oil. As of December 31, 2009, on a
NYMEX strip basis, our proved reserves were 3.3 Mmboe with a PV-10 of $81.5 million. At December 31,
2009, we had a production exit rate of approximately 440 Boepd from our North Dakota properties.
The Williston Basin is spread across North Dakota, Montana and parts of southern Canada with the
United States portion of the basin encompassing approximately 143,000 square miles. The basin
produces oil and gas from numerous producing horizons including the Madison, Bakken, Three
Forks/Sanish and Red River formations.
29
The Bakken formation is a Devonian-age shale found within the Williston Basin. The Bakken Shale is
estimated to contain up to 4.3 billion barrels of recoverable crude oil according to a report
issued by the United State Geological Survey (USGS) in April 2008, making it the largest
continuous crude oil accumulation ever assessed by the USGS. Generally the Bakken formation
underlies portions of North Dakota and Montana and is generally found at vertical depths of 9,000
to 10,500 feet. Below the Lower Bakken Shale lies the Three Forks/Sanish formation, and the Three
Forks Shale has also proven to contain reservoir rock. The Three Forks/Sanish typically consists
of interbedded dolomites and shale with local development of a discontinuous sandy member at the
top, known as the Sanish sand. Crude oil production from the Bakken Shale and Three Forks/Sanish
reservoirs is made possible through the combination of advanced horizontal drilling and fracture
stimulation technology. Combining these two technologies to produce crude oil from the Bakken
formation began to evolve around year 2000. Horizontal wells in these formations are typically
drilled on 320,640 acre or 1,280 acre spacing with horizontal laterals extending 4,500 to 9,500
feet into the reservoir. Fracture stimulation techniques vary but most commonly utilize multi-stage
mechanically diverted stimulations using un-cemented liners and packers.
Eagle Operating is the current operator of our Williston Basin properties. Re-pressurization
efforts commenced in November of 2002, which have resulted in the ability to begin secondary
recovery efforts through conventional and horizontal drilling activities in seven of the 15
producing fields. We have identified approximately 80 horizontal drilling locations. We drilled
three horizontal wells in the fourth quarter of 2009 with a combined initial production rate of
approximately 525 Boe per day (gross). These wells cost approximately $1.1 million gross per well
and have estimated average of approximately 200,000 boe EUR gross per well.
South Texas / Eagle Ford Shale
As of March 29, 2010, we had approximately 15,000 net acres (20,000 gross) primarily targeting the
Eagle Ford Shale. At year-end 2009, on an SEC basis, the Company had 590 Mboe of proved reserves
and PV-10 of $3.6 million. Using NYMEX strip pricing, we had proved reserves of 603 Mboe with a
PV-10 of $9.0 million.
The Eagle Ford Shale is a Cretaceous aged shale ranging in thickness of less than 100 feet to over
500 feet. The Eagle Ford Shale is present within the subsurface along the entire Gulf Coast of
Texas and is productive within the majority of the trend, producing from the more brittle
calcareous or dolomitic shale sections. The Eagle Ford Shale produces from depths that range from
approximately 6,500 feet to 15,000 feet deep. To date, the Eagle Ford Shale produces in the Texas
counties of Atascosa, Brazos, Burleson, Dewitt, Dimmit, Gonzales, Karnes, La Salle, Lee, Live Oak,
Maverick, McMullen and Webb, spanning approximately 300 miles of the Texas Gulf Coast and is
becoming one of newest emerging successful shale reserves in the country.
The Company has focused in the up-dip oil trend of the Eagle Ford Shale (7,000 feet to 11,000 feet)
to provide better economics metrics and commodity stability. As of March 29, 2010, Magnum Hunter
Resources had over 20,000 gross acres leased in the Eagle Ford Shale within the up-dip oil trend in
Atascosa, Gonzales, Lee and Fayette counties, Texas. At March 20, 2010, we controlled approximately
15,000 net acres of Eagle Ford Shale and operate all of our Eagle Ford Shale properties. We have
identified approximately 35 horizontal Eagle Ford Shale drilling locations. Working interest varies
from 50% in Lee and Fayette Counties, Texas to 100% in Gonzales and Atascosa Counties, Texas.
In February 2010, as part of the Companys ongoing evaluation of the Eagle Ford Shale, we fraced
and tested a vertical Eagle Ford Shale well, the Barbara Ann Unit #1, in Lee County, Texas. We
believe that frac stimulation is the most important element in the successful completion of these
shale wells and understanding frac dynamics within these shales using existing vertical wells will
allow us to better plan completions within our proposed horizontal wells. Our South Texas acreage
has conventional oil and natural gas potential derived from both the Austin Chalk and Wilcox
formations. Our Eberstadt # 1 well, located in the South Caesar Field of Bee County, Texas, began
flowing to sales on February 1, 2010 with a daily production rate of approximately 1,500 Mcf,
producing from a gross 100 foot thick section of the middle Wilcox formation. We believe that at
least two additional Wilcox wells can be drilled offsetting the Eberstadt #1.
We have budgeted an estimated $6.95 million in capital expenditures for 2010 associated with
leasing new acreage and the drilling of two horizontal wells, which are currently expected to
commence in the second quarter of 2010. We are also exploring multiple Joint Venture opportunities
with third parties in the Eagle Ford Shale.
30
South Louisiana / East Chalkley
Our East Chalkley field is located in Cameron Parish, Louisiana. The unit consists of
approximately 714 gross acres. This developmental project is an exploitation of bypassed oil
reserves remaining in a natural gas field located at depths between 9,300 feet and 9,400 feet.
Proved reserves on an SEC basis at December 31, 2009 totaled 285 Mboe, consisting of 88% oil and
49% proved developed, with PV-10 of $3.9 million. On a NYMEX strip basis, our proved reserves were
293 Mboe with a PV-10 of $7.3 million. On October 15, 2009, we acquired Centurion Exploration
Company LLCs ownership interest East Chalkley for $1.7 million. Subsequently, on October 23, 2009,
we divested a portion of our ownership interest for $500,000. Following the acquisition of
additional ownership interest and subsequent partial divestiture, we now operate East Chalkley and
own a 62% working interest with a
42.78% net revenue interest. During 2009, we added a salt water disposal well to reduce operating
expenses and we put in electrification of the facilities. We estimate the future potential of the
project to include three producing wells and three injection wells. As of March 29, 2010, we have
two wells producing at a rate of approximately 100 gross Bbls per day. We have not allocated any
capital to this project in 2010, as of March 29, 2010.
West Texas / Cinco Terry
We own a 10% working interest in an exploratory prospect area in Crockett County, Texas. The Cinco
Terry project area has oil and natural gas potential from multiple horizons, including the Canyon
(approximately 7,500 feet to 8,100 feet) and Ellenburger Sands (approximately 8,200 feet to 8,800
feet). We exited 2009 producing approximately 280 boepd, compared with 287 bbls per day in 2008.
Our proved reserves at December 31, 2009 on an SEC PV-10 basis were 2.3 Mmboe, consisting of 62%
oil and NGLs and 41% were classified as proved developed, with PV-10 of $12.2 million. On a NYMEX
strip basis we had proved reserves of 2.3 Mmboe and a PV-10 of $27.8 million. Cinco Terry is
operated by Approach Resources, Inc. and consists of approximately
50,000 gross acres (5,000 net).
In 2009, we successfully drilled and completed 23 gross wells for total capital cost of about $2.2
million to the Company. We have identified approximately 150 additional drilling locations. In
2010, we plan to spend approximately $1 million in the Cinco Terry Prospect.
Other Properties
East Texas / Surprise The Surprise Project is located in Nacogdoches County, Texas with natural
gas potential from multiple horizons including James Lime, Pettit, Travis Peak, Expanded Bossier,
Cotton Valley, and Haynesville Shale formations. The prospect is operated by Goodrich Petroleum
Corporation. The prospect area consists of approximately 3,000 gross (300 net) acres and we have a
10% working interest in the prospect and a net revenue interest of 7.4%. As
of March 29, 2010, we do not have any capital allocated to this project in 2010.
Other In addition to our unconventional and other conventional properties, we have approximately
184,300 gross (31,287 net) undeveloped acres in the States of New Mexico, Kentucky and Utah. As of
March 29, 2010, we do not plan to allocate capital to these areas in 2010. Furthermore, in 2009, we
allowed our acreage positions in Allen Parish, Louisiana and Floyd and Motley Counties, Texas to
expire, as they were not deemed conducive to our new business strategy.
Reserves
Our Oil and gas properties are primarily located in the (i) Appalachian Basin in West Virginia,
Ohio and Kentucky with substantial acreage in the Marcellus Shale area in West Virginia; (ii)
Williston Basin in North Dakota: (iii) Texas, including substantial acreage in the Eagle Ford Shale
area; and (iv) Southern Louisiana. Our natural gas and crude oil reserves have been estimated as
of December 31, 2009 by Cawley, Gillespie & Associates, Inc. (CGA), and DeGolyer & MacNaughton
(DM). Natural gas and crude oil reserves and the estimates of the present value of future net
revenues therefrom, were determined based on prices and costs as of December 31, 2009. Since
January 1, 2009, we have not filed, nor were we required to file, any reports concerning our oil
and gas reserves with any federal authority or agency.
There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves
and estimates of reserve quantities and values must be viewed as being subject to significant
change as more data about the properties becomes available.
31
Proved Reserves
In December 2008, the SEC released its finalized rule for Modernization of Oil and Gas Reporting.
The new rule requires disclosure of oil and gas proved reserves by significant geographic area,
using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to
using year-end prices as was practiced in all previous years. The rule also allows for the use of
reliable technologies to estimate proved oil and gas reserves, contingent on demonstrated
reliability in conclusions about reserve volumes. Under the new rules, companies are required to
report on the independence and qualifications of its reserve preparer or auditor, and file reports
when a third-party is relied upon to prepare reserve estimates or conduct a reserve audit. The
following table sets forth our estimated proved reserves based on the new SEC rules as defined in
Rule 4.10(a) of Regulation S-X and Item 1200 of Regulation S-K.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Reserves (SEC Prices at 12/31/09) |
|
Category |
|
Oil |
|
|
NGL |
|
|
Gas |
|
|
PV-10 |
|
|
|
(Barrels) |
|
|
(Barrels) |
|
|
(Mcf) |
|
|
($MM) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed |
|
|
1,693,973 |
|
|
|
361,557 |
|
|
|
5,055,269 |
|
|
$ |
35.0 |
|
Proved Undeveloped |
|
|
2,127,115 |
|
|
|
425,933 |
|
|
|
4,512,127 |
|
|
$ |
30.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved |
|
|
3,821,088 |
|
|
|
787,490 |
|
|
|
9,567,396 |
|
|
$ |
65.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The table below summarizes our proved reserves, based on NYMEX futures strip pricing as of December
31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Reserves (Based on Futures Prices at 12/31/09) |
|
Category |
|
Oil |
|
|
NGL |
|
|
Gas |
|
|
PV-10 |
|
|
|
(Barrels) |
|
|
(Barrels) |
|
|
(Mcf) |
|
|
($MM) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed |
|
|
1,880,794 |
|
|
|
384,076 |
|
|
|
5,304,369 |
|
|
$ |
61.3 |
|
Proved Undeveloped |
|
|
2,178,966 |
|
|
|
457,002 |
|
|
|
4,719,557 |
|
|
$ |
64.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved |
|
|
4,059,760 |
|
|
|
841,078 |
|
|
|
10,023,926 |
|
|
$ |
125.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All of our reserves are located within the continental United States. Reserve estimates are
inherently imprecise and remain subject to revisions based on production history, results of
additional exploration and development, prices of oil and natural gas and other factors. Please
read Item 1A. Risk Factors Our estimated reserves are based on many assumptions that may turn out
to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions
may materially affect the quantities and present value of our reserves You should also read the
notes following the table below and our Consolidated and Combined Financial Statements for the year
ended December 31, 2009 in conjunction with the following reserve estimates.
The following tables include reserves related to our recent acquisition of Triad located in the
Appalachian Basin, which closed in February of 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma Net Reserves (SEC Prices at 12/31/09)* |
|
Category |
|
Oil |
|
|
NGL |
|
|
Gas |
|
|
PV-10 |
|
|
|
(Barrels) |
|
|
(Barrels) |
|
|
(Mcf) |
|
|
($MM) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed |
|
|
3,799,567 |
|
|
|
361,000 |
|
|
|
11,949,768 |
|
|
$ |
76.8 |
|
Proved Undeveloped |
|
|
3,367,568 |
|
|
|
426,000 |
|
|
|
8,112,153 |
|
|
$ |
45.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved |
|
|
7,167,135 |
|
|
|
787,000 |
|
|
|
20,061,921 |
|
|
$ |
122.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma Net Reserves (Based on Futures Prices at 12/31/09)* |
|
Category |
|
Oil |
|
|
NGL |
|
|
Gas |
|
|
PV-10 |
|
|
|
(Barrels) |
|
|
(Barrels) |
|
|
(Mcf) |
|
|
($MM) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed |
|
|
4,397,991 |
|
|
|
384,076 |
|
|
|
13,436,040 |
|
|
$ |
143.1 |
|
Proved Undeveloped |
|
|
3,422,341 |
|
|
|
457,002 |
|
|
|
8,375,001 |
|
|
$ |
101.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved |
|
|
7,820,332 |
|
|
|
841,078 |
|
|
|
21,811,041 |
|
|
$ |
244.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
|
Pro forma information related to the Triad acquisition, which closed February 12, 2010, was
prepared by the Companys internal engineers. |
32
The following table sets forth our estimated proved reserves at the end of each of the past three
years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Description |
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
1,694,700 |
|
|
|
1,092,730 |
|
|
|
1,522,500 |
|
NGLs (Bbls) |
|
|
361,000 |
|
|
|
301,577 |
|
|
|
0 |
|
Natural Gas (Mcf) |
|
|
4,952,500 |
|
|
|
2,549,496 |
|
|
|
1,261,300 |
|
Proved Undeveloped Reserves |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
|
2,126,800 |
|
|
|
769,309 |
|
|
|
847,000 |
|
NGLs (Bbls) |
|
|
426,000 |
|
|
|
245,636 |
|
|
|
0 |
|
Natural Gas (Mcf) |
|
|
4,411,700 |
|
|
|
1,703,450 |
|
|
|
820,700 |
|
|
|
|
|
|
|
|
|
|
|
Total Proved Reserves (Boe) (1)(2) |
|
|
6,169,200 |
|
|
|
3,118,076 |
|
|
|
2,716,500 |
|
|
|
|
|
|
|
|
|
|
|
PV-10 Value ($MMs) (3) |
|
$ |
65.6 |
|
|
$ |
21.0 |
|
|
$ |
9.4 |
|
Standardized Measure ($MMs) |
|
$ |
47.4 |
|
|
$ |
15.6 |
|
|
$ |
40.1 |
|
|
|
|
(1) |
|
The estimates of reserves in the table above conform to the guidelines of the SEC. Estimated recoverable proved
reserves have been determined without regard to any economic impact that may result from our financial derivative
activities. These calculations were prepared using standard geological and engineering methods generally accepted
by the petroleum industry. The reserve information shown is estimated. The certainty of any reserve estimate is a
function of the quality of available geological, geophysical, engineering and economic data, the precision of the
engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and present
value are based on various assumptions, and are inherently imprecise. Although we believe these estimates are
reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and
quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. |
|
(2) |
|
We converted crude oil and NGLs to Mcf equivalent at a ratio of one barrel to six Mcfe. |
|
(3) |
|
Represents the present value, discounted at 10% per annum (PV-10), of estimated future cash flows before income
tax of our estimated proved reserves. The estimated future cash flows set forth above were determined by using
reserve quantities of proved reserves and the periods in which they are expected to be developed and produced
based on prevailing economic conditions. The estimated future production is priced based on the 12-month
unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2009,
using $61.18 per bbl and $3.866 per MMBtu and adjusted by lease for transportation fees and regional price
differentials. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides
useful information to investors because it is widely used by professional analysts and sophisticated investors in
evaluating oil and natural gas companies. For an explanation of why we show PV-10 and a reconciliation of PV-10
to the standardized measure of discounted future net cash flow. Please read Item 1A. Risk FactorsOur estimated
reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these
reserve estimates or underlying assumptions may materially affect the quantities and present value of our
reserves. |
Marcellus Infrastructure Assets
The Triad acquisition brought important infrastructure assets for the effective development of the
Marcellus Shale unconventional resource. With increased drilling activity in the region, relying
on third-party oilfield service providers and pipeline operators can be costly. We feel that
control of key oil field services allows us to manage the timing and costs of drilling and
production. Furthermore, we believe that access to a pipeline system is vital to flow natural gas
to sales, often being a deciding factor on drilling and production decisions. The summary below
provides a brief overview of such services we operate and control, which mitigate certain risks
associated with development of the Marcellus Shale. Additionally, we anticipate these assets will
generate an attractive revenue stream as we actively market them to third-party producers in the
Appalachian Basin.
Eureka Hunter Pipeline The Eureka Hunter Pipeline consists of approximately 182 miles of
pipeline, gathering and rights-of-way located in Northern West Virginia, in the Marcellus Shale.
Specifically, the existing pipeline system runs through Pleasants, Tyler, Ritchie, Wetzel, Marion,
Harrison, Doddridge, Lewis and Monongalia Counties. We are currently reviewing completion and
expansion opportunities for the pipeline and we believe that the system can be expanded to up to
200 MMcf/d of throughput capacity. Following our anticipated expansion, we expect to have
sufficient capacity to transport significant quantities of Company-produced natural gas from our
Marcellus Shale development program, as well as third-party gas. We have budgeted $10 million for
the completion of the first 12 miles of the pipeline project and anticipate completion in the third
quarter of 2010.
33
Drilling Rigs and Oilfield Service Equipment As part of the Triad acquisition in February of
2010, we acquired drilling rigs and oilfield service equipment. Our oilfield service equipment
primarily consists of three drilling rigs, a workover rig and heavy machinery which are operated
for us and third parties by our wholly-owned subsidiary, Alpha Hunter Drilling, LLC. We anticipate
using our rigs to drill the vertical portion of our Marcellus Shale wells and then switching to
larger rigs for the horizontal sections. This flexibility is expected to reduce the overall
drilling costs, as well as improve the timing of drilling activity. As of March 29, 2010, two of
our rigs are under a multi well drilling contract to a large producer in the area.
Salt Water Disposal Facility Typically, Marcellus Shale wells produce significant amounts of
water that, in most cases, requires disposal. Producers often remove the water in trucks for
proper disposal in approved facilities. While this method has been the only option to many
producers in the Appalachian Basin, it adds a significant operating burden and increases costs. We
own and operate salt water disposal facilities with the current capacity of approximately 2,500
barrels of water per day. In addition to benefiting from our own disposal facilities, we market our
disposal capabilities to third-party operators. In 2010, we anticipate disposal capacity will
increase to over 4,000 barrels of water per day, following a $250,000 planned capital improvement.
Recent SEC Rule-Making Activity
In December 2008, the SEC announced that it had approved revisions designed to modernize the oil
and gas company reserves reporting requirements. The most significant amendments to the
requirements included the following:
|
|
|
Commodity Prices: Economic producibility of reserves and discounted
cash flows are now based on a 12-month average commodity price unless
contractual arrangements designate the price to be used. |
|
|
|
|
Disclosure of Unproved Reserves: Probable and possible reserves may be disclosed separately on a voluntary basis. |
|
|
|
|
Proved Undeveloped Reserve Guidelines: Reserves may be classified as
proved undeveloped if there is a high degree of confidence that the
quantities will be recovered and they are scheduled to be drilled
within the next five years, unless the specific circumstances justify
a longer time. |
|
|
|
|
Reserves Estimation Using New Technologies: Reserves may be estimated
through the use of reliable technology in addition to flow tests and
production history. |
|
|
|
|
Reserves Personnel and Estimation Process: Additional disclosure is
required regarding the qualifications of the chief technical person
who oversees the reserves estimation process. We are also required to
provide a general discussion of our internal controls used to assure
the objectivity of the reserves estimate. |
|
|
|
|
Non-Traditional Resources: The definition of oil and gas producing
activities has expanded and focuses on the marketable product rather
than the method of extraction. |
We adopted the rules effective December 31, 2009, as required by the SEC.
34
Effect of Adoption.
Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for
both oil and gas than would have resulted under the previous rules. Use of new 12-month average
pricing rules at December 31, 2009 resulted in proved reserves of approximately 6.2 MMboe. Use of
the old year-end prices rules would have resulted in proved reserves of approximately 6.5 MMboe at
December 31, 2009. Therefore, the total impact of the new price methodology rules resulted in
negative reserves revisions of 0.4 MMboe.
Proved Undeveloped Reserves (PUDs)
As of December 31, 2009, our proved undeveloped reserves totaled 2.1 MMboe of crude oil, 0.4 MMboe
of NGLs and 4.4 Bcf of natural gas, for a total of 3.3 MMboe. Changes in PUDs that occurred during
the year were due to:
|
|
|
Successful drilling of 23 PUD locations in West Texas |
|
|
|
|
Successful drilling of 2 PUD locations in the Mohall Madison Unit in North Dakota and
the re-drill of a Probable Undeveloped location in the East Flaxton Madison Unit in North
Dakota. |
|
|
|
|
Successful re-pressurization results associated with two fields in North Dakota |
Costs incurred relating to the development of PUDs were approximately $7.6 million in 2009.
Estimated future development costs relating to the development of PUDs are projected to be
approximately $17.0 million in 2010, $9.6 million in 2011, and $5.6 million in 2012.
All PUD drilling locations are scheduled to be drilled prior to the end of 2012. Initial production
from these PUDs is expected to begin between 2010 to 2013. We do not have PUDs associated with
reserves that have been booked for longer than three years.
The following table summarizes the changes in our proved reserves for the year ended December 31,
2009:
|
|
|
|
|
|
|
For the Year Ended |
|
Proved Developed Reserves (Mboe) |
|
December 31, 2009 |
|
|
|
|
|
|
Proved Reserves Beginning of year |
|
|
3,118.1 |
|
Revisions of previous estimates |
|
|
1,335.9 |
|
Improved recovery |
|
|
0.0 |
|
Extensions and discoveries |
|
|
1,330.2 |
|
Production |
|
|
(256.6 |
) |
Purchases of reserves in place |
|
|
661.3 |
|
Sales of reserves in place |
|
|
(19.7 |
) |
Proved Reserves End of year |
|
|
6,169.2 |
|
|
|
|
|
|
Proved developed reserves Beginning of year |
|
|
1,819.2 |
|
Proved developed reserves End of year |
|
|
2,880.7 |
|
35
Reserve Estimation.
Cawley, Gillespie & Associates, Inc. (CGA) and DeGolyer & MacNaughton (DM), two independent
petroleum engineering firms, evaluated our oil and gas reserves on a consolidated basis as of
December 31, 2009. At December 31, 2009, these third party consultants collectively reviewed all of
our proved oil and gas reserves. The technical persons responsible for preparing our proved
reserves estimates meet the requirements with regards to qualifications, independence, objectivity
and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and
Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third
party engineers do not own an interest in any of our properties and are not employed by us on a
contingent basis.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely
with CGA and DM to ensure the integrity, accuracy and timeliness of the data used to calculate our
proved oil and gas reserves. Our internal technical team members meet with CGA and DM periodically
throughout the year to discuss the assumptions and methods used in the proved reserve estimation
process. We provide historical information to CGA and DM for our properties such as ownership
interest; oil and gas production; well test data; commodity prices and operating and development
costs. The preparation of our proved reserve estimates are completed in accordance with our
internal control procedures, which include the verification of input data used by CGA and DM, as
well as extensive management review and approval.
Acreage and Productive Wells Summary
The following table sets forth, for our continuing operations, our gross and net acreage of
developed and undeveloped oil and natural gas leases and our gross and net productive oil and
natural gas wells as of December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
|
Undeveloped |
|
|
|
|
|
|
Acreage (1) |
|
|
Acreage (2) |
|
|
Total Acreage |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North Dakota |
|
|
15,200 |
|
|
|
6,536 |
|
|
|
3,411 |
|
|
|
1,116 |
|
|
|
18,611 |
|
|
|
7,652 |
|
West Texas |
|
|
10,318 |
|
|
|
1,032 |
|
|
|
39,963 |
|
|
|
3,996 |
|
|
|
50,281 |
|
|
|
5,028 |
|
South Texas / Gulf Coast |
|
|
1,471 |
|
|
|
485 |
|
|
|
10,527 |
|
|
|
4,811 |
|
|
|
11,998 |
|
|
|
5,296 |
|
Other |
|
|
185,014 |
|
|
|
31,730 |
|
|
|
0 |
|
|
|
0 |
|
|
|
185,014 |
|
|
|
31,730 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
212,003 |
|
|
|
39,783 |
|
|
|
53,901 |
|
|
|
9,923 |
|
|
|
265,904 |
|
|
|
49,706 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Developed acreage is the number of acres allocated or assignable to producing wells or wells capable of production. |
|
(2) |
|
Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of
oil and natural gas, regardless of whether such acreage includes proved reserves. |
The following two tables represent the pro forma calculation, as they include the Triad transaction
which did not close until February of 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma Developed |
|
|
Pro Forma Undeveloped |
|
|
|
|
|
|
Acreage (1) |
|
|
Acreage (2) |
|
|
Pro Forma Total Acreage |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Appalachia |
|
|
67,000 |
|
|
|
60,000 |
|
|
|
35,602 |
|
|
|
21,449 |
|
|
|
102,602 |
|
|
|
81,449 |
|
North Dakota |
|
|
15,200 |
|
|
|
6,536 |
|
|
|
3,411 |
|
|
|
1,116 |
|
|
|
18,611 |
|
|
|
7,652 |
|
West Texas |
|
|
10,318 |
|
|
|
1,032 |
|
|
|
39,963 |
|
|
|
3,996 |
|
|
|
50,281 |
|
|
|
5,028 |
|
South Texas / Gulf Coast |
|
|
1,471 |
|
|
|
485 |
|
|
|
10,527 |
|
|
|
4,811 |
|
|
|
11,998 |
|
|
|
5,296 |
|
Other |
|
|
185,014 |
|
|
|
31,730 |
|
|
|
0 |
|
|
|
0 |
|
|
|
185,014 |
|
|
|
31,730 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
279,003 |
|
|
|
99,783 |
|
|
|
89,503 |
|
|
|
31,372 |
|
|
|
368,506 |
|
|
|
131,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Developed acreage is the number of acres allocated or assignable to producing wells or wells capable of production. |
|
(2) |
|
Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and
natural gas, regardless of whether such acreage includes proved reserves. |
36
The table below lists our wells by category and area.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma Producing |
|
|
Pro Forma Producing |
|
|
Pro Forma Total Producing |
|
|
|
Oil Wells |
|
|
Gas Wells |
|
|
Oil and Gas Wells |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Appalachia |
|
|
800.0 |
|
|
|
760.0 |
|
|
|
1,274.0 |
|
|
|
1,210.3 |
|
|
|
2,074.0 |
|
|
|
1,970.3 |
|
North Dakota |
|
|
0.0 |
|
|
|
0.0 |
|
|
|
146.0 |
|
|
|
65.7 |
|
|
|
146.0 |
|
|
|
65.7 |
|
West Texas |
|
|
87.0 |
|
|
|
8.7 |
|
|
|
0.0 |
|
|
|
0.0 |
|
|
|
87.0 |
|
|
|
8.7 |
|
South Texas / Gulf Coast |
|
|
8.0 |
|
|
|
1.1 |
|
|
|
2.0 |
|
|
|
1.2 |
|
|
|
10.0 |
|
|
|
2.3 |
|
Other |
|
|
5.0 |
|
|
|
0.5 |
|
|
|
0.0 |
|
|
|
0.0 |
|
|
|
5.0 |
|
|
|
0.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
900 |
|
|
|
770 |
|
|
|
1,422 |
|
|
|
1,277 |
|
|
|
2,322 |
|
|
|
2,048 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Substantially all of the leases summarized in the preceding table will expire at the end of their
respective primary terms unless the existing lease is renewed or we have obtained production from
the acreage subject to the lease before the end of the primary term; in which event, the lease will
remain in effect until the cessation of production.
The following table sets forth, for our continuing operations, the gross and net acres of
undeveloped land subject to leases summarized in the preceding table that will expire during the
periods indicated:
|
|
|
|
|
|
|
|
|
|
|
Expiring |
|
Year Ending |
|
Acreage |
|
December 31, |
|
Gross |
|
|
Net |
|
2010 |
|
|
858 |
|
|
|
337 |
|
2011 |
|
|
9,200 |
|
|
|
6,299 |
|
2012 |
|
|
750 |
|
|
|
610 |
|
2013 |
|
|
10,000 |
|
|
|
7,509 |
|
|
|
|
|
|
|
|
Total |
|
|
20,808 |
|
|
|
14,755 |
|
|
|
|
|
|
|
|
Drilling Results
The following table summarizes our drilling activity for the past three years. Gross wells reflect
the sum of all wells in which we own an interest. Net wells reflect the sum of our working
interests in gross wells. All of our drilling activities were conducted on a contract basis by
independent drilling contractors.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Exploratory Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
3 |
|
|
|
0.70 |
|
|
|
25 |
|
|
|
2.45 |
|
|
|
15 |
|
|
|
2.11 |
|
Unproductive |
|
|
1 |
|
|
|
0.10 |
|
|
|
11 |
|
|
|
2.20 |
|
|
|
6 |
|
|
|
0.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
4 |
|
|
|
0.80 |
|
|
|
36 |
|
|
|
4.65 |
|
|
|
21 |
|
|
|
3.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developmental Wells: |
|
|
27 |
|
|
|
3.80 |
|
|
|
8 |
|
|
|
1.41 |
|
|
|
4 |
|
|
|
1.96 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
30 |
|
|
|
4.50 |
|
|
|
33 |
|
|
|
3.86 |
|
|
|
19 |
|
|
|
4.07 |
|
Unproductive |
|
|
1 |
|
|
|
0.10 |
|
|
|
0 |
|
|
|
0.00 |
|
|
|
6 |
|
|
|
0.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
31 |
|
|
|
4.60 |
|
|
|
33 |
|
|
|
3.86 |
|
|
|
25 |
|
|
|
5.00 |
|
Success Ratio (1) |
|
|
96.8 |
% |
|
|
97.8 |
% |
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
76.0 |
% |
|
|
81.4 |
% |
|
|
|
(1) |
|
The success ratio is calculated as follows: (total wells drillednon-productive
wellswells awaiting completion) / (total wells drilledwells awaiting completion). |
37
Oil and Gas Production, Prices and Costs
The following table shows the approximate net production attributable to our oil and gas interests,
the average sales price and the average production expense attributable to our oil and gas
production for the periods indicated. Production and sales information relating to properties
acquired or disposed of as of December 31, 2009 is reflected in this table only since or up to the
closing date of their respective acquisition or sale and may affect the comparability of the data
between the periods presented.
|
|
|
|
|
|
|
|
|
|
|
Years Ended |
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Oil and Gas Production: |
|
|
|
|
|
|
|
|
Oil (Mbbl) |
|
|
140 |
|
|
|
132 |
|
NGL (Mbbl) |
|
|
40 |
|
|
|
20 |
|
Gas (MMcf) |
|
|
458 |
|
|
|
341 |
|
|
|
|
|
|
|
|
Oil Equivalent (Mboe) |
|
|
256 |
|
|
|
209 |
|
|
|
|
|
|
|
|
|
|
Average Sales Price |
|
|
|
|
|
|
|
|
Oil ($/bbl) |
|
$ |
53.59 |
|
|
$ |
87.11 |
|
NGL ($/bbl) |
|
$ |
28.52 |
|
|
$ |
44.54 |
|
Gas ($/Mcf) |
|
$ |
3.01 |
|
|
$ |
6.21 |
|
|
|
|
|
|
|
|
Oil Equivalent ($/boe) |
|
$ |
39.10 |
|
|
$ |
69.43 |
|
|
|
|
|
|
|
|
|
|
Lease Operating Expense ($/boe) |
|
$ |
16.45 |
|
|
$ |
20.38 |
|
Title to Properties
We believe that we have satisfactory title to all of our producing properties in accordance with
generally accepted industry standards. As is customary in the industry, in the case of undeveloped
properties, often only minimal investigation of record title is made at the initial time of lease
acquisition. A more comprehensive mineral title opinion review, a topographic evaluation and
infrastructure investigations are made before the consummation of an acquisition of producing
properties and before commencement of drilling operations on undeveloped properties. Individual
properties may be subject to burdens that we believe do not materially interfere with the use or
affect the value of the properties. Burdens on properties may include:
|
|
|
customary royalty interests; |
|
|
|
|
liens incident to operating agreements and for current taxes; |
|
|
|
|
obligations or duties under applicable laws; |
|
|
|
|
development obligations under oil and gas leases; |
|
|
|
|
net profit interests; |
|
|
|
|
overriding royalty interests; |
|
|
|
|
non-surface occupancy leases; and |
|
|
|
|
lessor consents to placement of wells. |
Item 3. LEGAL PROCEEDINGS
No legal proceedings are pending other than ordinary routine litigation incidental to our business,
the outcome of which management believes will not have a material adverse effect on the Company.
38
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
Executive Officers of the Registrant
Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3) to
Form 10-K, the following information is included in Part I of this report. The following are our
executive officers as of March 31, 2010.
|
|
|
|
|
|
|
Name |
|
Age |
|
Position |
Gary C. Evans
|
|
|
52 |
|
|
Chairman and Chief Executive Officer |
Ronald D. Ormand
|
|
|
51 |
|
|
Executive Vice President and Chief Financial Officer |
James W. Denny, III
|
|
|
62 |
|
|
Executive Vice President Operations |
H.C. Ferguson, III
|
|
|
44 |
|
|
Executive Vice President Exploration |
M. Bradley Davis
|
|
|
50 |
|
|
Senior Vice President of Capital Markets |
Don Kirkendall
|
|
|
52 |
|
|
Senior Vice President of Marketing and Administration |
David S. Krueger
|
|
|
60 |
|
|
Senior Vice President and Chief Accounting Officer |
Brian
G. Burgher
|
|
|
47 |
|
|
Vice President of Land |
David Lipp
|
|
|
28 |
|
|
Vice President of Business Development and Legal |
Victor Ponce de Leon
|
|
|
41 |
|
|
Vice President of Finance and Treasurer |
Gary C. Evans serves as Chairman of the Board and Chief Executive Officer. Mr. Evans founded and
served as Chairman and Chief Executive Officer of Magnum Hunter Resources, Inc. (MHRI), a NYSE
listed company, for 20 years before selling MHRI to Cimarex Energy for approximately $2.2 billion
in June 2005. In 2005, Mr. Evans formed Wind Energy, LLC, a renewable energy company which was
acquired in December 2006 by Green Hunter Energy, Inc., a NYSE Amex listed renewable energy
company focusing on biodiesel, wind and biomass power, where he additionally serves as Chairman
and CEO. Mr. Evans serves as an Individual Trustee of TEL Offshore Trust, a NASDAQ listed oil and
gas trust, and is the Lead Director of Novavax Inc., a NASDAQ listed clinical-stage vaccine
biotechnology company.
Ronald D. Ormand serves as Executive Vice President, Chief Financial Officer, and Board Member.
Mr. Ormand is a member of the Board of Directors of Green Hunter Energy Inc, and previous member
of the Board of Directors of Tremisis Energy Acquisition Corporation II, both NYSE Amex listed
companies. Mr. Ormand also previously served as President and Chief Financial Officer of
Tremisis. Mr. Ormand has over 25 years of energy investment banking experience, previously
serving for 16 years with CIBC as Managing Director, Head of CIBC World U.S. Oil and Gas
Investment Banking Group and member of U.S. Investment Banking Management Committee and as
Managing Director and Head of the Oil and Gas Investment Banking Group for the Americas at West
LB, a German-based international bank. Mr. Ormand received a B.A. and an M.B.A. from UCLA and
attended Cambridge University where he studied Economics.
James W. Denny, III serves as Executive Vice President of Operations. Mr. Denny brings more than
35 years of industry related experience. Mr. Denny previously served as President and CEO of Gulf
Energy Management Co., a wholly owned subsidiary of Harken Energy Corporation. He is a registered
Professional Engineer (Louisiana) and is a Certified Earth Scientist. He is also a member of
various industry associations, including the American Petroleum Institute, National Society of
Professional Engineers, Society of Petroleum Engineers, and the Society of Petroleum Evaluation
Engineers. He is a graduate of the University of Louisiana-Lafayette with a B. S. in Petroleum
Engineering.
H.C. Kip Ferguson, III serves as Executive Vice President of Exploration. Mr. Ferguson is a
Houston, Texas native and a third generation geologist. Graduating from the University of Texas
in Austin, he has 16 years of experience in oil and gas exploration throughout the Gulf Coast,
West Texas, and the Rocky Mountain Region. Mr. Ferguson began his career with Sterling Production
Company, handling exploration, development, and operations of its west Texas activities for 6
years, until co-founding a private energy company, Sable Energy Corp.
M. Bradley Davis serves as Senior Vice President of Capital Markets. Mr. Davis has 28 years of
experience and direct involvement in all facets of the energy industry, including nine years as a
Wall Street Senior Equity Research Analyst specializing in the small-to-mid capitalization
independent exploration and production sector. He served from September 2002 until June 2005 as
Senior Vice President of Capital Markets and Corporate Development and as Senior Vice President
and Chief Financial Officer of Magnum Hunter Resources, Inc. Mr. Davis received a Bachelor of
Arts degree with majors in Business Administration and Political Science from Baylor University.
39
David S. Krueger serves as Senior Vice President and Chief Accounting Officer. Mr. Krueger served
as Vice President and Chief Accounting Officer of Magnum Hunter Resources, Inc. from January 1997
to June 2005. From June 2005 to May 2006, Mr. Krueger was Vice President and Chief Financial
Officer for Sulphur River Exploration, Inc. in Dallas, Texas. Also, Mr. Krueger
has served as Vice President and Chief Financial Officer of GreenHunter Energy Inc. since May
2006. Magnum Hunter Resources, Inc., Sulphur River Exploration, Inc. and GreenHunter Energy Inc.
are not parents, subsidiaries or affiliates of the Company. Mr. Krueger, a certified public
accountant, graduated from the University of Arkansas with a B.S. degree in Business
Administration and earned his M.B.A. from the University of Tulsa.
Don Kirkendall serves as Senior Vice President of Administration and Product Marketing. Mr.
Kirkendall brings more than 25 years of diversified energy experience to Magnum Hunter Resources
Corporation. His background includes interstate pipeline business along with natural gas
marketing and exploration experience. He co-founded and managed a successful natural gas
marketing company along with an associated exploration company that specialized in drilling Texas
Gulf Coast and South Texas oil and gas prospects. Mr. Kirkendall received his B.B.A. from
Southwest Texas State University.
Brian Burgher serves as Vice President of Land. Mr. Burgher brings more than 25 years of
continuous experience in land related areas to Magnum Hunter Resources Corporation. Mr. Burgher
is a fourth generation oil and gas landman. In addition to being an independent operator, Mr.
Burgher has worked as field landman, field land broker, in-house landman, and land manager. Mr.
Burgher attended both Baylor University and the University of Houston.
David Lipp serves as Vice President of Business Development and Legal. He has been with Magnum
Hunter Resources Corporation for two years, working in the finance, treasury, accounting and
legal departments. Mr. Lipp received a Bachelors degree in Finance and a Masters degree in
Accounting from Tulane University. He also received his J.D. from the University of Houston Law
Center and is admitted to practice law in the State of Texas.
Victor Ponce de León serves as Vice President of Finance and Treasurer. Mr. Ponce de León has 15
years of experience in the energy sector. As an investment banker with Morgan Keegan and WestLB
AG, he worked on over 20 transactions, including structured and corporate financing, mergers &
acquisitions and fairness opinions. As an equity research analyst, Mr. Ponce de León covered
the exploration and production sector for CIBC World Markets, Credit Lyonnais and Jefferies & Co.
Mr. Ponce de León received a B.B.A. in Finance from the University of St. Thomas and a
Certificate in Accounting from the University of Houston.
40
Glossary of Oil and Natural Gas Terms
The following is a description of the meanings of some of the oil and natural gas industry
terms used in this report.
bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to
crude oil or other liquid hydrocarbons.
bcf. Billion cubic feet of natural gas.
boe. Barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to
one bbl of crude oil, condensate or natural gas liquids.
boe/d. boepd. boe per day.
Completion. The process of treating a drilled well followed by the installation of permanent
equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of
abandonment to the appropriate agency.
Condensate. Hydrocarbons which are in the gaseous state under reservoir conditions and which
become liquid when temperature or pressure is reduced. A mixture of pentanes and higher
hydrocarbons.
Development well. A well drilled within the proved area of a natural gas or oil reservoir to
the depth of a stratigraphic horizon known to be productive.
Drilling locations. Total gross locations specifically quantified by management to be included
in the Companys multi-year drilling activities on existing acreage. The Companys actual drilling
activities may change depending on the availability of capital, regulatory approvals, seasonal
restrictions, oil and natural gas prices, costs, drilling results and other factors.
Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities
to justify completion as an oil or gas well.
Exploratory well. A well drilled to find and produce natural gas or oil reserves not
classified as proved, to find a new reservoir in a field previously found to be productive of
natural gas or oil in another reservoir or to extend a known reservoir.
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on
or related to the same individual geological structural feature and/or stratigraphic condition.
Formation. An identifiable layer of rocks named after its geographical location and dominant
rock type.
Lease. A legal contract that specifies the terms of the business relationship between an
energy company and a landowner or mineral rights holder on a particular tract of land.
Leasehold. Mineral rights leased in a certain area to form a project area.
mbbls. Thousand barrels of crude oil or other liquid hydrocarbons.
mbblspd. Thousand barrels of crude oil or other liquid hydrocarbons per day.
mboe. Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of
natural gas to one bbl of crude oil, condensate or natural gas liquids
mboepd. Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of
natural gas to one bbl of crude oil, condensate or natural gas liquids per day.
mcf. Thousand cubic feet of natural gas.
mcfpd. Thousand cubic feet of natural gas per day.
mcfe. Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to
one bbl of crude oil, condensate or natural gas liquids.
41
mcfepd. Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas
to one bbl of crude oil, condensate or natural gas liquids per day.
mmbbls. Million barrels of crude oil or other liquid hydrocarbons.
mmblspd. Million barrels of crude oil or other liquid hydrocarbons per day.
mmboe. Million barrels of crude oil equivalent, determined using the ratio of six mcf of
natural gas to one bbl of crude oil, condensate or natural gas liquids.
mmboepd. Million barrels of crude oil equivalent, determined using the ratio of six mcf of
natural gas to one bbl of crude oil, condensate or natural gas liquids per day.
mmbtu. Million British Thermal Units.
mmbtupd. Million British Thermal Units per day.
mmcf. Million cubic feet of natural gas.
mmcfpd. Million cubic feet of natural gas per day.
Net acres, net wells, or net reserves. The sum of the fractional working interests owned in
gross acres, gross wells, or gross reserves, as the case may be.
NYMEX. New York Mercantile Exchange.
ngl. Natural gas liquids, or liquid hydrocarbons found in association with natural gas.
Overriding royalty interest. Is similar to a basic royalty interest except that it is created
out of the working interest. For example, an operator possesses a standard lease providing for a
basic royalty to the lessor or mineral rights owner of 1/8 of 8/8. This then entitles the operator
to retain 7/8 of the total oil and natural gas produced. The 7/8 in this case is the 100% working
interest the operator owns. This operator may assign his working interest to another operator
subject to a retained 1/8 overriding royalty. This would then result in a basic royalty of 1/8, an
overriding royalty of 1/8 and a working interest of 3/4. Overriding royalty interest owners have no
obligation or responsibility for developing and operating the property. The only expenses borne by
the overriding royalty owner are a share of the production or severance taxes and sometimes costs
incurred to make the oil or gas salable.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a
well so that the fluids from one stratum will not escape into another or to the surface.
Regulations of all states require plugging of abandoned wells.
Present value of future net revenues (PV-10). The present value of estimated future revenues
to be generated from the production of proved reserves, before income taxes, of proved reserves
calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated
production and future development costs, using prices and costs as of the date of estimation
without future escalation, without giving effect to hedging activities, non-property related
expenses such a general and administrative expenses, debt service and depreciation, depletion and
amortization, and discounted using an annual discount rate of 10%. PV-10 uses year-end prices for
2008 and prior years and the arithmetic 12-month average beginning-of-the-month price for 2009 and
subsequent years.
Production. Natural resources, such as oil or gas, taken out of the ground.
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty
to be economically produciblefrom a given date forward, from known reservoirs, and under existing
economic conditions, operating methods, and government regulationsprior to the time at which
contracts providing the right to operate expire, unless evidence indicates that renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods are used for the
estimation. The project to extract the hydrocarbons must have commenced or the operator must be
reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
42
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty,
be judged to be continuous with it and to contain economically producible oil or gas
on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by
the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering,
or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO)
elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned
in the structurally higher portions of the reservoir only if geoscience, engineering, or
performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery
techniques (including, but not limited to, fluid injection) are included in the proved
classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties
no more favorable than in the reservoir as a whole, the operation of an installed
program in the reservoir or an analogous reservoir, or other evidence using reliable
technology establishes the reasonable certainty of the engineering analysis on which
the project or program was based; and
(B) The project has been approved for development by all necessary parties and
entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from
a reservoir is to be determined. The price shall be the average price during the 12-month period
prior to the ending date of the period covered by the report, determined as an unweighted
arithmetic average of the first-day-of-the-month price for each month within such period, unless
prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that
can be expected to be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing the natural forces and mechanisms of
primary recovery should be included as proved developed reserves only after testing by a pilot
project or after the operation of an installed program has confirmed through production response
that increased recovery will be achieved.
Proved undeveloped reserves. Proved undeveloped oil and 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. Reserves on undrilled acreage shall be
limited to those drilling units offsetting productive units that are reasonably certain of
production when drilled. Proved reserves for other undrilled units can be claimed only where it can
be demonstrated with certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped reserves he attributable
to any acreage for which an application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual tests in the area and in
the same reservoir.
Probable Reserves. Probable reserves are those additional reserves which analysis of
geoscience and engineering data indicate are less likely to be recovered than proved reserves but
more certain to be recovered than possible reserves. It is equally likely that actual remaining
quantities recovered will be greater than or less than the sum of the estimated proved plus
probable reserves (2P). In this context, when probabilistic methods are used, there should be at
least a 50-percent probability that the actual quantities recovered will equal or exceed the 2P
estimate.
Probable reserves are those additional reserves that are less certain to be recovered than
proved reserves but which, together with proved reserves, are as likely as not to be recovered.
When deterministic methods are used, it is as likely as not that actual remaining quantities
recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic
methods are used, there should be at least a 50% probability that the actual quantities recovered
will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned
to areas of a reservoir adjacent to proved reserves where data control or interpretations of
available data are less certain, even if the interpreted reservoir continuity of structure or
productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to
areas that are structurally higher than the proved area if these areas are in communication with
the proved reservoir. Probable reserves estimates also include potential incremental quantities
associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved
reserves.
Possible Reserves. Possible reserves are those additional reserves which analysis of
geoscience and engineering data suggest are less likely to be recoverable than probable reserves.
The total quantities ultimately recovered from the project have a low probability to exceed the sum
of proved plus probable plus possible reserves (3P), which is equivalent to the high estimate
scenario. In
this context, when probabilistic methods are used, there should be at least a 10-percent
probability that the actual quantities recovered will equal or exceed the 3P estimate.
43
Possible reserves are those additional reserves that are less certain to be recovered than
probable reserves. When deterministic methods are used, the total quantities ultimately recovered
from a project have a low probability of exceeding proved plus probable plus possible reserves.
When probabilistic methods are used, there should be at least a 10% probability that the total
quantities ultimately recovered will equal or exceed the proved plus probable plus possible
reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable
reserves where data control and interpretations of available data are progressively less certain.
Frequently, this will be in areas where geoscience and engineering data are unable to define
clearly the area and vertical limits of commercial production from the reservoir by a defined
project. Possible reserves also include incremental quantities associated with a greater percentage
recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent
portions of a reservoir within the same accumulation that may be separated from proved areas by
faults with displacement less than formation thickness or other geological discontinuities and that
have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are
in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that
are structurally higher or lower than the proved area if these areas are in communication with the
proved reservoir. Where direct observation has defined a highest known oil (HKO) elevation and the
potential exists for an associated gas cap, proved oil reserves should be assigned in the
structurally higher portions of the reservoir above the HKO only if the higher contact can be
established with reasonable certainty through reliable technology. Portions of the reservoir that
do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas
based on reservoir fluid properties and pressure gradient interpretations.
Productive well. A well that is found to be capable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.
Project. A targeted development area where it is probable that commercial gas can be produced
from new wells.
Prospect. A specific geographic area which, based on supporting geological, geophysical or
other data and also preliminary economic analysis using reasonably anticipated prices and costs, is
deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed producing reserves. Reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which
geological and engineering data demonstrate with reasonable certainty to be commercially
recoverable from known reservoirs under current economic and operating conditions, operating
methods, and government regulations.
Proved undeveloped reserves. Proved 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.
Recompletion. The process of re-entering an existing well bore that is either producing or not
producing and completing new reservoirs in an attempt to establish or increase existing production.
Reserves. Oil, natural gas and gas liquids thought to be accumulated in known reservoirs.
Reservoir. A porous and permeable underground formation containing a natural accumulation of
producible nature gas and/or oil that is confined by impermeable rock or water barriers and is
separate from other reservoirs.
Secondary Recovery. A recovery process that uses mechanisms other than the natural pressure of
the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas
remaining after the primary recovery phase.
Shut-in. A well that has been capped (having the valves locked shut) for an undetermined
amount of time. This could be for additional testing, could be to wait for pipeline or processing
facility, or could be for a number of other reasons.
44
Standardized measure. The present value of estimated future cash inflows from proved oil and
natural gas reserves, less future development, abandonment, production and income tax expenses,
discounted at 10% per annum to reflect timing of future cash flows and using the same pricing
assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because
standardized measure includes the effect of future income taxes.
Successful. A well is determined to be successful if it is producing oil or natural gas, or
awaiting hookup, but not abandoned or plugged.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a
point that would permit the production of commercial quantities of oil and natural gas regardless
of whether such acreage contains proved reserves.
Water flood. A method of secondary recovery in which water is injected into the reservoir
formation to displace residual oil and enhance hydrocarbon recovery.
Working interest. The operating interest that gives the owner the right to drill, produce and
conduct operating activities on the property and receive a share of production and requires the
owner to pay a share of the costs of drilling and production operations.
45
PART II
Item 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
Recent Market Prices
Our common stock trades on the NYSE Amex (formerly the American Stock Exchange) under the symbol
MHR.
The following table shows the high and low sales prices of our common stock for the periods
indicated.
|
|
|
|
|
|
|
|
|
|
|
High |
|
|
Low |
|
2009: |
|
|
|
|
|
|
|
|
First quarter |
|
$ |
0.65 |
|
|
|
0.21 |
|
Second quarter |
|
|
0.84 |
|
|
|
0.20 |
|
Third quarter |
|
|
1.43 |
|
|
|
0.54 |
|
Fourth quarter |
|
|
2.24 |
|
|
|
1.20 |
|
|
2008: |
|
|
|
|
|
|
|
|
First quarter |
|
$ |
2.15 |
|
|
$ |
1.27 |
|
Second quarter |
|
|
3.50 |
|
|
|
1.30 |
|
Third quarter |
|
|
3.30 |
|
|
|
0.93 |
|
Fourth quarter |
|
|
1.15 |
|
|
|
0.29 |
|
Our Series C Preferred stock trades on the NYSE Amex under the symbol MHR.PR.C. The Preferred
stock was initially listed in December 2009 and the stock traded at a high of $26 to a low of $24
during the fourth quarter of 2009.
Holders
On
March 29, 2010, there were approximately 168 shareholders on record of our common stock and
approximately one shareholder on record of our Series C Preferred Stock.
Dividends
We have not paid any cash dividends on our common stock since our inception and do not contemplate
paying dividends on our common stock in the foreseeable future. It is anticipated that earnings, if
any, will be retained for the operation of our business. The terms of our credit facilities with
Bank of Montreal restrict our ability to pay dividends on our equity shares.
Pursuant to our Certificate of Designations related to the Series C Preferred Stock issued in the
fourth quarter of 2009, we are not required to pay a cash dividend until March 31, 2010; however,
we will pay a 10.25% dividend on all outstanding shares of Series C Preferred stock in quarterly
payments beginning on March 31, 2010.
46
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information with respect to our common shares issuable under our
equity compensation plans as of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Securities |
|
|
|
|
|
|
|
|
|
|
|
Remaining Available for |
|
|
|
Number of Securities |
|
|
Weighted-Average |
|
|
Future Issuance Under |
|
|
|
to be Issued Upon |
|
|
Exercise Price of |
|
|
Equity Compensation |
|
|
|
Exercise of |
|
|
Outstanding Options, |
|
|
Plans (Excluding |
|
|
|
Outstanding Options, |
|
|
Warrants and |
|
|
Securities Reflected in |
|
|
|
Warrants and Rights (a) |
|
|
Rights (b) |
|
|
Column (a)) (c) |
|
Equity compensation
plans approved by
security holders |
|
|
3,117,000 |
|
|
$ |
0.93 |
|
|
|
2,883,000 |
|
Equity compensation
plans not approved
by security holders |
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
3,117,000 |
|
|
$ |
0.93 |
|
|
|
2,883,000 |
|
|
|
|
|
|
|
|
|
|
|
Recent Sales of Unregistered Securities
We have previously disclosed by way of quarterly reports on Form 10-Q and current reports on Form
8-K filed with the SEC all sales by us of our unregistered securities during 2009.
Item 6. SELECTED FINANCIAL DATA
Not applicable.
47
Item 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist you in understanding our results of operations and
our financial condition. Our consolidated financial statements and the accompanying notes included
elsewhere in this report contain additional information that should be referred to when reviewing
this material. Statements in this discussion may be forward-looking. These forward-looking
statements involve risks and uncertainties, which could cause actual results to differ from those
expressed. See Cautionary Statement Regarding Forward-Looking Statements at the beginning of this
report and Risk Factors in Item 1A. for additional discussion of some of these factors and risks.
General and Business Overview
We are an independent oil and gas company engaged in the acquisition, development and production of
oil and natural gas, primarily in West Virginia, North Dakota, Texas and Louisiana. The Company is
presently active in three of the four most prolific shale resource plays in the United States,
including the Marcellus Shale, Eagle Ford Shale and Williston Basin / Bakken Shale. The Company is
a Delaware corporation and was incorporated in 1997. In 2005, the Company began oil and gas
operations under the name Petro Resources Corporation and was restructured in May of 2009, with a
new management team and refocused business strategy. In July of 2009, the Company changed its name
to Magnum Hunter Resources Corporation (MHR). The new management team includes Gary C. Evans,
former Founder, Chairman and Chief Executive Officer of Magnum Hunter
Resources, Inc.2
as Chairman and Chief Executive Officer, Ronald D. Ormand as Executive Vice President and Chief
Financial Officer, H.C. Kip Ferguson as Executive Vice President of Exploration and M. Bradley
Davis as Senior Vice President of Capital Markets. Our management has implemented a new business
strategy consisting of exploiting our inventory of lower-risk drilling locations and the
acquisition of long-lived proved reserves with significant exploitation and development
opportunities. As a result of this new strategy, the Company has substantially increased its assets
and production through three acquisitions and ongoing development efforts, the percentage of
operated properties has increased significantly, its inventory of acreage and drilling locations in
resource plays has expanded along with its management team.
2009 Recap and 2010 Outlook
Triad Acquisition. On February 12, 2010, the Company closed the acquisition of privately-held Triad
Energy Corporation and certain of its affiliates (collectively, Triad), an Appalachian Basin
focused energy company. Triad had previously been operating under Chapter 11 of the United States
Bankruptcy Code. Triads operations are located in the Ohio, West Virginia and Kentucky portions of
the Appalachian Basin. In addition, the Triad acquisition included (i) conventional, mature oil
fields currently under primary and secondary development with approximately 5.1 MMboe of proved
reserves (65% oil); and over 2,000 producing wells (99% of which are operated) (ii) approximately
87,000 net acres including approximately 46,000 net acres in the prolific Marcellus Shale; (iii)
182 miles of right-of-way that will allow for the construction of a new pipeline system that will
provide Magnum Hunter with significant take-away capacity for our Marcellus Shale gas as well as
revenue from transporting third-party gas; (iv) service equipment including three drilling rigs;
and (v) two commercial salt water disposal facilities. These assets are now held in our
wholly-owned subsidiaries Triad Hunter, LLC, Alpha Hunter Drilling, LLC, Eureka Hunter Pipeline,
LLC, Hunter Disposal, LLC and Hunter Real Estate, LLC. Consideration for the assets acquired from
Triad totaled $81 million, consisting of:
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$8 million in cash; |
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$15 million of our Series B Redeemable Convertible Preferred Stock, issued to certain
banks who were secured creditors of Triad in its Chapter 11 proceedings; |
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$55 million repayment of Triad senior debt via drawing under the new Restated Credit
Facility discussed below; and |
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Assumption of approximately $3 million of equipment indebtedness. |
Bank of Montreal Credit Facilities. On November 23, 2009, we entered into a $150 million Credit
Agreement with Bank of Montreal. The Credit Agreement provided for an asset-based, three-year
senior secured revolving credit facility, with an initial borrowing base availability of $25
million. On February 12, 2010 we amended and restated the Credit Agreement with Bank of Montreal
and Capital One, NA, providing for a borrowing base of $70 million to allow for the acquisition of
Triad.
Acquisition of Sharon Resources, Inc. On September 30, 2009, we acquired Sharon Resources, Inc., a
wholly-owned subsidiary of Calgary-based Sharon Energy Ltd., bringing an inventory of drilling
locations focused in the Eagle Ford Shale located in South Texas.
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Magnum Hunter Resources, Inc. was a NYSE-listed oil and
gas exploration and production company, unrelated to the Company, that was
acquired by Cimarex Energy Corporation in June 2005. |
48
Additionally, the Sharon acquisition enhanced the Companys technical expertise with the addition
of experienced geologists and land professionals.
Equity Financings. Throughout the fourth quarter of 2009, the Company raised substantial cash through
equity transactions. Those transactions included:
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$15.2 million of common equity financings throughout the course of the fourth
quarter. |
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$5.4 million in gross proceeds from the issuance of our 10.25% Series C
Cumulative Perpetual Preferred Stock, at a price of $25.00 per share completed in
the fourth quarter of 2009 |
Appalachian Basin / Marcellus Shale
With the acquisition of Triad in February of 2010, we currently operate approximately 2,048 wells,
producing primarily conventional oil and gas and we own approximately 87,000 net acres, including
approximately 46,000 net acres overlying the Marcellus Shale, as well as the shallow sandstones.
Approximately 70% of our leases are held by production. We have over 2,000 wells producing, of
which 64% are oil and 99% are operated by the Company. In 2010, we plan to expand our Marcellus
development program. We have budgeted $7.1 million for the drilling of two horizontal wells from
our inventory of over 25 identified drilling locations.
North Dakota-Williston Basin / Madison Group / Bakken Shale
The Company owns an approximately 43% average working interest in 15 fields located in the
Williston Basin in North Dakota comprising of 146 wells and
approximately 18,600 gross acres
(approximately 90% of which is held by production) in Burke, Renville, Ward, Bottineau, McHenry
Counties located in North Dakota. We exited 2009 producing approximately 440 bbls per day
equivalent.
South Texas / Eagle Ford Shale
At
year-end 2009, we had approximately 12,000 gross acres (approximately 5,300 net) primarily
targeting the Eagle Ford Shale. We exited 2009 producing approximately 40 bbls per day. We have
budgeted an estimated $6.95 million in capital expenditures for 2010 associated with leasing new
acreage and the drilling of two horizontal wells scheduled to commence in the second quarter of
2010. We are also exploring multiple Joint Venture opportunities to develop and expand our Eagle
Ford acreage.
In February 2010, as part of the Companys ongoing evaluation of the Eagle Ford Shale, we fracd
and tested a vertical Eagle Ford Shale well, the Barbara Ann Unit #1, in Lee County, Texas. We
believe that frac stimulation is the most important element in the successful completion of these
shale wells and understanding the frac dynamics within these shales using vertical wells will allow
us to better plan completion within our horizontal laterals. In addition to the Eagle Ford Shale
position, our South Texas acreage has conventional oil and natural gas potential derived from both
the Austin Chalk and Wilcox formations. Our Eberstadt # 1 well, located in the South Caesar Field
of Bee County, Texas, began flowing to sales on February 1, 2010 with a daily production rate of
approximately 1,500 Mcf, producing from a gross 100 foot thick section of the middle Wilcox
formation. We believe that at least two additional Wilcox wells can be drilled offsetting the
Eberstadt #1.
West Texas / Cinco Terry
We have a 10% working interest in an exploratory prospect area in Crockett County, Texas with oil
and natural gas potential from multiple horizons including the Canyon (producing depths of
approximately 7,500 feet to 8,100 feet) and Ellenburger Sands (producing depths of approximately
8,200 feet to 8,800 feet). We exited 2009 producing approximately 280 bbls per day of oil
equivalent. Cinco Terry is operated by Approach Resources, Inc. and consists of approximately
38,000 gross acres (3,800 net). In 2009, we successfully drilled and completed 23 gross wells for
total capital cost of $2.2 million to the Company. We have identified approximately 150 additional
drilling locations. In 2010, capital expenditures will be approximately $1 million.
Other Properties
South Louisiana / East Chalkley Located in Cameron Parish, Louisiana, this developmental project
is an exploitation of bypassed oil reserves remaining in a natural gas field located at depths
between 9,300 feet and 9,400 feet. The unit consists of approximately 714 gross acres. On October
15, 2009, we acquired Centurion Exploration Company LLCs ownership interest East Chalkley for $1.7
million. Subsequently, on October 23, 2009, we divested a portion of our ownership interest for
$500,000. Following the acquisition of additional ownership interest and subsequent partial
divestiture, we now operate East Chalkley, own a 62% working interest and receive a 42.78% net
revenue interest. During 2009, we added a salt water disposal well to reduce operating costs and
electrification to
the facilities. We estimate the future potential of the project to include three producing wells
and three injection wells. Currently we have two wells producing at a rate of approximately 100
gross Bbls of oil per day. Currently, we do not plan to allocate capital to this project in 2010.
49
East Texas / Surprise The Surprise Project is located in Nacogdoches County, Texas with natural
gas potential from multiple horizons including James Lime, Pettit, Travis Peak, Expanded Bossier,
Cotton Valley, and Haynesville Shale. The prospect is operated by Goodrich Petroleum Corporation.
The prospect area consists of approximately 3,000 gross (300 net) acres. We have a 10% working
interest in the prospect and a net revenue interest of 7.4%. Currently, we
do not plan to allocate capital to this project in 2010.
Other In addition to our unconventional and other conventional properties, we have approximately
184,300 gross (31,287 net) undeveloped acres in the New Mexico, Kentucky and Utah. Currently, we do
not plan to allocate capital to these areas in 2010. Furthermore, in 2009, we allowed our acreage
positions in Allen Parish, Louisiana and Floyd and Motley Counties, Texas to expire, as they were
not central to our strategy.
Marcellus Infrastructure Assets
The Triad acquisition in February 2010, brought important infrastructure assets for the effective
development of the unconventional resource. With increased drilling activity in the region,
relying on third-party oilfield service providers and pipeline operators can be costly. We feel
that control of key oil field services allows us to better manage the timing and costs of drilling
and production. Furthermore, we believe that access to a pipeline system is vital to flow natural
gas to sales, often being a deciding factor on drilling and production decisions. The summary
below provides a brief overview of such services we operate and control, which mitigate certain
risks associated with development of the Marcellus Shale. Additionally, we anticipate these assets
will generate an attractive revenue stream as we actively market them to third-party producers in
the Appalachian Basin.
Eureka Hunter Pipeline The Eureka Hunter Pipeline consists of approximately 182 miles of
pipeline, gathering and rights-of-way located in Northern West Virginia, in what we believe to be
the heart of the Marcellus Shale development for this region. Specifically, the pipeline system
runs through Pleasants, Tyler, Ritchie, Wetzel, Marion, Harrison, Doddridge, Lewis and Monongalia
Counties. We are currently reviewing completion and expansion opportunities and we believe that
the system can be expanded up to 200 MMcf/d of throughput capacity. Following our anticipated
expansion, we expect to have sufficient capacity to transport significant quantities of natural gas
from our Marcellus Shale development, as well as third-party gas. We have budgeted $10 million for
the completion of the first phase of the pipeline project and anticipate completion in the third
quarter of 2010.
Drilling Rigs and Oilfield Service Equipment Our oilfield service equipment primarily consists
of three drilling rigs, a workover rig and heavy machinery which are operated for us and third
parties by our wholly-owned subsidiary, Alpha Hunter Drilling, LLC. We anticipate using our rigs to
drill the vertical portion of our Marcellus Shale wells and then switching to larger rigs for the
horizontal sections. This flexibility is expected to reduce the overall drilling costs, as well as
improve the timing of drilling activity. Currently, two of our rigs are under a multi well
contract to a large producer in the area.
Salt Water Disposal Facility Typically, Marcellus Shale wells produce significant amounts of
water that, in most cases, requires disposal. Producers often remove the water in trucks for
proper disposal in approved facilities. While this method has been the only option to many
producers in the Appalachian Basin, it adds a significant operating burden and increases costs. We
own and operate two commercial salt water disposal facilities with the current capacity for over
2,500 barrels of water per day. In addition to benefiting from our own disposal facilities, we
market our disposal capabilities to third-party operators. In 2010, we anticipate disposal capacity
will increase to over 4,000 barrels of water per day, following a $250 thousand planned expansion.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our
consolidated financial statements, which have been prepared in accordance with accounting policies
generally accepted in the United States. The preparation of our consolidated financial statements
requires us to make estimates and assumptions that affect our reported results of operations and
the amount of reported assets, liabilities and proved oil and gas reserves. Some accounting
policies involve judgments and uncertainties to such an extent that there is reasonable likelihood
that materially different amounts could have been reported under different conditions, or if
different assumptions had been used. Actual results may differ from the estimates and assumptions
used in the preparation of our consolidated financial statements. Described below are the most
significant policies we apply in preparing our consolidated financial statements, some of which are
subject to alternative treatments under U.S. GAAP. We also describe the most significant estimates
and assumptions we make in applying these policies. See Note 2 to our consolidated financial
statements.
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Oil and Gas Activities Successful Efforts
Accounting for oil and gas activities is subject to special, unique rules. We use the successful
efforts method of accounting for our oil and gas activities. The significant principles for this
method are:
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geological and geophysical evaluation costs are expensed as incurred; |
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dry holes for exploratory wells are expensed, and dry holes for
developmental wells are capitalized; and |
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capitalized costs related to proved oil and gas properties, including
wells and related equipment and facilities, are evaluated for
impairment based on an analysis of undiscounted future net cash flows
in accordance with ASC 360, Accounting for the Impairment or Disposal
of Long Lived Assets. If undiscounted cash flows are insufficient to
recover the net capitalized costs related to proved properties, then
we recognize an impairment charge in income from operations equal to
the difference between the net capitalized costs related to proved
properties and their estimated fair values based on the present value
of the related future net cash flows. |
Proved Reserves
On December 31, 2008, the SEC released a Final Rule, Modernization of Oil and Gas Reporting,
approving revisions designed to modernize oil and gas reserve reporting requirements. The new
reserve rules are effective for our financial statements for the year ended December 31, 2009 and
our 2009 year-end proved reserve estimates. The most significant revisions to the reporting
requirements include:
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Commodity prices. Economic producibility of reserves is now based on
the unweighted, arithmetic average of the closing price on the first
day of the month for the 12-month period prior to fiscal year end,
unless prices are defined by contractual arrangements; |
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Undeveloped oil and gas reserves. Reserves may be classified as
proved undeveloped for undrilled areas beyond one offsetting
drilling unit from a producing well if there is reasonable certainty
that the quantities will be recovered; |
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Reliable technology. The rules now permit the use of new technologies
to establish the reasonable certainty of proved reserves if those
technologies have been demonstrated empirically to lead to reliable
conclusions about reserves volumes; |
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Unproved reserves. Probable and possible reserves may be disclosed
separately on a voluntary basis; |
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Preparation of reserves estimates. Disclosure is required regarding
the internal controls used to assure objectivity in the reserves
estimation process and the qualifications of the technical person
primarily responsible for preparing reserves estimates; and |
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Third party reports. We are now required to file the report of any
third party used to prepare or audit our reserve estimates. |
In addition, in January 2010, FASB issued Accounting Standards Update, or the Update, 2010-03, Oil
and Gas Reserve Estimation and Disclosures, to provide consistency with the new reserve rules. The
Update amends existing standards to align the reserves estimation and disclosure requirements under
GAAP with the requirements in the SECs reserve rules. We adopted the new standards effective
December 31, 2009. The new standards are applied prospectively as a change in estimate.
For the year ended December 31, 2009, we engaged Cawley, Gillespie & Associates, Inc. and DeGolyer
and MacNaughton, independent petroleum engineers, to prepare independent estimates of the extent
and value of the proved reserves associated with certain of our oil and gas properties in
accordance with guidelines established by the SEC, including the recent revisions designed to
modernize oil and gas reserve reporting requirements. We adopted these revisions effective December
31, 2009.
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Estimates of proved oil and gas reserves directly impact financial accounting estimates including
depletion, depreciation and amortization expense, evaluation of impairment of properties and the
calculation of plugging and abandonment liabilities. Proved oil and gas reserves are those
quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible from a given date forward, from known
reservoirs, and under existing economic conditions, operating methods, and government regulations
The process of estimating quantities of proved reserves is very complex, requiring significant
subjective decisions in the evaluation of all geological, engineering and economic data for each
reservoir. The data for any reservoir may change substantially over time due to results from
operational activity. Proved reserve volumes at December 31, 2009, were estimated based on the
unweighted, arithmetic average of the closing price on the first day of each month for the 12-month
period prior to December 31, 2009 for natural gas, oil and NGLs in accordance with new reserve
rules.
The new reserve rules resulted in the use of lower prices for natural gas, oil and NGLs than would
have resulted under the previous reporting requirements. Under the new reserve rules, our estimated
proved reserves increased by 3,051 MBoe. Under the previous reserve rules, our estimated total
proved reserves of natural gas, oil and NGLs would have increased by 3,437 MBoe. Therefore, the
effect of the new reserve rules was a negative revision of 386 Mboe.
Changes in commodity prices and operation costs may also affect the overall evaluation of
reservoirs. Under previous reserve rules (year-end 2009 spot prices for natural gas, oil and NGLs),
our depletion expense would have decreased by approximately $145 thousand.
See also Items 1 and 2. Properties Proved Reserves and Note 11 to our consolidated financial
statements for additional information regarding our estimated proved reserves.
Derivative Instruments and Commodity Derivative Activities
Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as
current or non-current assets or liabilities based on the anticipated timing of cash settlements
under the related contracts. Changes in the fair value of our commodity derivative contracts are
recorded in earnings as they occur and included in other income (expense) on our consolidated
statements of operations. We estimate the fair values of swap contracts based on the present value
of the difference in exchange-quoted forward price curves and contractual settlement prices
multiplied by notional quantities. We internally valued the collar contracts using
industry-standard option pricing models and observable market inputs. We use our internal
valuations to determine the fair values of the contracts that are reflected on our consolidated
balance sheets. Realized gains and losses are also included in Gain (loss) on derivative
contracts on our consolidated statements of operations.
We are exposed to credit losses in the event of nonperformance by the counterparties on our
commodity derivatives positions and have considered the exposure in our internal valuations.
However, we do not anticipate nonperformance by the counterparties over the term of the commodity
derivatives positions.
Changes in the derivatives fair value are currently recognized in the statement of operations
unless specific commodity derivative hedge accounting criteria are met and such strategies are
designated. For qualifying cash-flow commodity derivatives, the gain or loss on the derivative is
deferred in accumulated other comprehensive (loss) income to the extent the commodity derivative is
effective. The ineffective portion of the commodity derivative is recognized immediately in the
statement of operations. Gains and losses on commodity derivative instruments included in
accumulated other comprehensive (loss) income are reclassified to oil and gas sales revenue in the
period that the related production is delivered. Derivative contracts that do not qualify for
commodity derivative accounting treatment are recorded as derivative assets and liabilities at fair
value in the balance sheet, and the associated unrealized gains and losses are recorded as current
income or expense in the statement of operations.
Historically, we have not designated our derivative instruments as cash-flow hedges. We record our
open derivative instruments at fair value on our consolidated balance sheets as either unrealized
gains or losses on commodity derivatives. We record changes in such fair value in earnings on our
consolidated statements of operations under the caption entitled Gain (loss) on derivative
contracts.
Although we have not designated our derivative instruments as cash-flow hedges, we use those
instruments to reduce our exposure to fluctuations in commodity prices related to our oil and gas
production. We record both realized and unrealized gains and losses under those instruments in
other revenues on our consolidated statements of operations. We recorded a realized gain from the
settlement of derivative contracts of $5.4 million for the year ended December 31, 2009 and we
recorded a realized loss from the settlement of derivative contracts of $1.2 million for the year
ended December 31, 2008. Realized gains and losses result from actual cash settlements received or
paid under the derivative contracts. For the year ended December 31, 2009, we recognized an
unrealized loss of $7.7 million from the change in the fair value of commodity derivatives. For the
year ended December 31, 2008, we recognized an unrealized gain of $8.6 million from the change in
the fair value of commodity derivatives. Unrealized gains and losses result from changes in the
fair market value of the derivative contracts from period to period, and represent non-cash gains
or losses. Changes in commodity prices could have a significant effect on the fair value of our
derivative contracts. A hypothetical 10% increase in the
NYMEX floating prices would have resulted in a $1.3 million decrease in the December 31, 2009 fair
value recorded on our balance sheet, and a corresponding increase to the loss on commodity
derivatives in our statement of operations. See Notes 2, 3 and 4 to our consolidated financial
statements for additional information on our derivative instruments.
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Asset Retirement Obligation
Our asset retirement obligation primarily represents the estimated present value of the amount we
will incur to plug, abandon and remediate our producing properties at the end of their productive
lives, in accordance with applicable federal, state and local laws. We determine our asset
retirement obligation by calculating the present value of estimated cash flows related to the
liability. The retirement obligation is recorded as a liability at its estimated present value as
of the assets inception, with an offsetting increase to proved properties. Periodic accretion of
discount of the estimated liability is recorded as accretion expense in the Consolidated Statements
of Operations.
Our liability is determined using significant assumptions, including current estimates of plugging
and abandonment costs, annual inflation of these costs, the productive lives of wells and our
risk-adjusted interest rate. Changes in any of these assumptions can result in significant
revisions to the estimated asset retirement obligation. Our liability for asset retirement
obligations was approximately $2.0 million and $1.6 million at December 31, 2009 and 2008,
respectively. See Note 6 to our consolidated financial statements for more information.
Share-Based Compensation
Our 2006 Stock Incentive Plan allows grants of stock and options to employees and outside
directors. Granting of awards may increase our general and administrative expenses subject to the
size and timing of the grants. In 2009 and 2008, we recognized approximately $3.1 million and $1.6
million in non-cash stock compensation, respectively. See Note 8 to our consolidated financial
statements for additional information.
Valuation of Property and Equipment
The Company accounts for the impairment and disposition of long-lived assets in accordance with ASC
360, Accounting for the Impairment or Disposal of Long-Lived Assets. ASC 360 requires that the
Companys long-lived assets, including its oil and gas properties, be assessed for potential
impairment in their carrying values whenever events or changes in circumstances indicate such
impairment may have occurred. An impairment charge to current operations is recognized when the
estimated undiscounted future net cash flows of the asset are less than its carrying value. Any
such impairment is recognized based on the differences in the carrying value and estimated fair
value of the impaired asset.
The guidance provides for future revenue from the Companys oil and gas production to be estimated
based upon prices at which management reasonably estimates such products will be sold. These
estimates of future product prices may differ from current market prices of oil and gas. Any
downward revisions to managements estimates of future production or product prices could result in
an impairment of the Companys oil and gas properties in subsequent periods.
The long-lived assets of the Company which are subject to evaluation consist primarily of oil and
gas properties. Due to the regularly scheduled impairment reviews by management, the Company
recognized a non-cash, pre-tax charge against earnings of approximately $634,000 and $2.0 million
in 2009 and 2008, respectively. See Note 2 to our consolidated financial statements for additional
information.
Revenue Recognition
Revenues associated with sales of crude oil, natural gas, natural gas liquids and petroleum
products, and other items are recognized when title passes to the customer, which is when the risk
of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or
within a fixed delivery schedule that is reasonable and customary in the industry.
Revenues from the production of natural gas and crude oil properties, in which we have an interest
with other producers, are recognized based on the actual volumes we sold during the period. Any
differences between volumes sold and entitlement volumes, based on our net working interest, which
are deemed to be non-recoverable through remaining production, are recognized as accounts
receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and
entitlement volumes are generally not significant.
53
Income Taxes
We account for income taxes under the liability method. Deferred tax assets and liabilities are
determined based on differences between financial reporting and tax bases of assets and liabilities
and are measured using the enacted tax rates and laws that will be in effect when the differences
are expected to reverse. We measure and record income tax contingency accruals in accordance with
ASC 740, Income Taxes.
We recognize liabilities for uncertain income tax positions based on a two-step process. The first
step is to evaluate the tax position for recognition by determining if the weight of available
evidence indicates that it is more likely than not that the position will be sustained on audit,
including resolution of related appeals or litigation processes, if any. The second step requires
us to estimate and measure the tax benefit as the largest amount that is more than 50% likely to be
realized upon ultimate settlement. It is inherently difficult and subjective to estimate such
amounts, as we must determine the probability of various possible outcomes. We reevaluate these
uncertain tax positions on a quarterly basis or when new information becomes available to
management. These reevaluations are based on factors including, but not limited to, changes in
facts or circumstances, changes in tax law, successfully settled issues under audit, expirations
due to statutes, and new audit activity. Such a change in recognition or measurement could result
in the recognition of a tax benefit or an increase to the tax accrual.
We classify interest related to income tax liabilities as income tax expense, and if applicable,
penalties are recognized as a component of income tax expense. The income tax liabilities and
accrued interest and penalties that are anticipated to be due within one year of the balance sheet
date are presented as current liabilities in our consolidated balance sheets. See Note 10 to our
consolidated financial statements for additional information.
Recently Issued Accounting Pronouncements
In December 2007, FASB issued guidance related to Business Combinations under ASC 805, Business
Combinations, and guidance related to the accounting and reporting of noncontrolling interest under
ASC 810-10-65-1, Consolidation. This guidance significantly changes the accounting for and
reporting of business combination transactions and noncontrolling (minority) interests in
consolidated financial statements. This guidance became effective January 1, 2009. We applied this
guidance to our majority interests in PRC Williston, LLC. This guidance did not have an impact on
our acquisitions completed in 2009. Please see Note 9 Shareholders Equity in the Notes to
Consolidated Financial Statements for additional information.
In March 2008, the FASB issued guidance related to the disclosures about derivative instruments and
hedging activities under FASB ASC 815-10-50, Derivatives and Hedging. This guidance requires
companies to provide enhanced disclosures about (a) how and why they use derivative instruments,
(b) how derivative instruments and related hedged items are accounted for under applicable
guidance, and (c) how derivative instruments and related hedged items affect a companys financial
position, financial performance, and cash flows. These disclosure requirements are effective for
financial statements issued for fiscal years and interim periods beginning after November 15, 2008.
Our adoption of ASC 815-10-50 on January 1, 2009 did not have a material impact on our consolidated
financial statements. See Note 4 Financial Instruments and Derivatives in the Notes to
Consolidated Financial Statements for additional information.
In June 2008, the FASB issued guidance to evaluate whether an instrument (or embedded feature) is
indexed to an entitys own stock under ASC 815-40-15, Derivatives and Hedging. The guidance
requires entities to evaluate whether an equity-linked financial instrument (or embedded feature)
is indexed to its own stock in order to determine if the instrument should be accounted for as a
derivative under the scope of ASC 815-10-15. This guidance is effective for financial statements
issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal
years. We adopted ASC 815-40-15 beginning January 1, 2009, which did not have a material impact on
our consolidated financial statements.
In December 2008, the Securities and Exchange Commission published a Final Rule, Modernization of
the Oil and Gas Reporting Requirements. 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 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. In January 2010, the FASB issued Accounting Standards Update
No. 2010-03, Oil and Gas Reserve Estimation and Disclosure, to align the oil and gas reserve
estimation and disclosure requirement of the SEC Final Rule with the ASC 932. The new disclosure
requirements are effective for annual reports on Form 10-K for fiscal years ending on or after
December 31, 2009. Our adoption of this Final rule for this annual report dated December 31, 2009
affected our oil and gas disclosures and resulted in $145,000 additional depletion expense in the
fourth quarter. See Note 2 Oil and Gas Properties and Note 11 Supplemental Oil and Gas
Disclosures (Unaudited) in the Notes to Consolidated Financial Statements.
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In May 2009, the FASB issued guidance related to subsequent events under ASC 855-10, Subsequent
Events. This guidance sets forth the period after the balance sheet date during which management or
a reporting entity should evaluate events or transactions that may occur for potential recognition
or disclosure, the circumstances under which an entity should recognize events or transactions
occurring after the balance sheet date, and the disclosures that an entity should make about events
or transactions that occurred after the balance sheet date. It requires disclosure of the date
through which an entity has evaluated subsequent events and the basis for that date, whether that
date represents the date the financial statements were issued or were available to be issued. This
guidance is effective for interim and annual periods ending after June 15, 2009. We adopted ASC
855-10 beginning June 30, 2009 and have included the required disclosures in our consolidated
financial statements. See Note 14 Subsequent Events in the Notes to Consolidated Financial
Statements for additional information.
In June 2009, the FASB issued Accounting Standards Update No. 2009-01 which amends ASC 105,
Generally Accepted Accounting Principles. This guidance states that the ASC will become the source
of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Once
effective, the Codifications content will carry the same level of authority. Thus, the U.S. GAAP
hierarchy will be modified to include only two levels of U.S. GAAP: authoritative and
non-authoritative. This is effective for financial statements issued for interim and annual periods
ending after September 15, 2009. We adopted ASC 105 as of September 30, 2009 and thus have
incorporated the new Codification citations in place of the corresponding references to legacy
accounting pronouncements.
In August 2009, the FASB issued Accounting Standards Update No. 2009-05, Measuring Liabilities at
Fair Value, which amends ASC 820, Fair Value Measurements and Disclosures. This Update provides
clarification that in circumstances in which a quoted price in an active market for the identical
liability is not available, a reporting entity is required to measure the fair value using one or
more of the following techniques: a valuation technique that uses the quoted price of the identical
liability or similar liabilities when traded as an asset, which would be considered a Level 1
input, or another valuation technique that is consistent with ASC 820. This Update is effective for
the first reporting period (including interim periods) beginning after issuance. Thus, we adopted
this guidance as of September 30, 2009, which did not have a material impact on our consolidated
financial statements.
Effects of Inflation
Inflation in the United States has been relatively low in recent years and did not have a material
impact on our results of operations for the years ended December 31, 2009 and 2008. Although the
impact of inflation has been insignificant in recent years, it is still a factor in the United
States economy and may increase the cost to acquire or replace property, plant and equipment. It
may also increase the cost of labor or supplies. To the extent permitted by competition, regulation
and our existing agreements, we have and will continue to pass along increased costs to our
customers in the form of higher prices.
55
Results of Operations
Years Ended December 31, 2009 and 2008
The following table sets forth summary information regarding natural gas, oil and NGL revenues,
production, average product prices and average production costs and expenses for the last two
years. Gas is converted at the rate of one Bbl equals six Mcf.
|
|
|
|
|
|
|
|
|
|
|
Years Ended |
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Revenues (in thousands) |
|
|
|
|
|
|
|
|
Oil |
|
$ |
7,513 |
|
|
$ |
11,471 |
|
Gas |
|
|
1,377 |
|
|
|
2,118 |
|
NGLs |
|
|
1,145 |
|
|
|
897 |
|
|
|
|
|
|
|
|
Total oil and gas sales |
|
$ |
10,035 |
|
|
$ |
14,486 |
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
Oil (MBbls) |
|
|
140 |
|
|
|
132 |
|
Gas (MMcfs) |
|
|
458 |
|
|
|
341 |
|
NGLs (MBbls) |
|
|
40 |
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
Total (MBoe) |
|
|
257 |
|
|
|
209 |
|
Total (Boe/d) |
|
|
703 |
|
|
|
570 |
|
|
|
|
|
|
|
|
|
|
Average prices |
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
53.59 |
|
|
$ |
87.11 |
|
Gas (per Mcf) |
|
|
3.01 |
|
|
|
6.21 |
|
NGLs (per Bbl) |
|
|
28.52 |
|
|
|
44.54 |
|
|
|
|
|
|
|
|
|
|
Total average price (per Boe) |
|
$ |
39.10 |
|
|
$ |
69.43 |
|
|
|
|
|
|
|
|
|
|
Costs and expenses (per Boe) |
|
|
|
|
|
|
|
|
Lease operating |
|
$ |
16.45 |
|
|
$ |
20.38 |
|
Severance tax and marketing |
|
|
4.12 |
|
|
|
5.40 |
|
Exploration |
|
|
3.49 |
|
|
|
35.22 |
|
Impairment of properties |
|
|
2.47 |
|
|
|
9.46 |
|
General and administrative (see Note) |
|
|
33.09 |
|
|
|
19.00 |
|
Depletion, depreciation and accretion |
|
|
17.53 |
|
|
|
36.82 |
|
|
|
|
Note: General and administrative
includes acquisition related expenses
of $4.04 per Boe in 2009 and none in
2008 and non-cash stock compensation of
$12.03 per Boe in 2009 and $7.61 per Boe
in 2008. |
Oil
and gas production. Production increased by 48 MBoe to 257 MBoe for the year ended December
31, 2009 from 209 MBoe for the year ended December 31, 2008, or 23%. Production for 2009 on a Boe
basis was 70% oil and NGLs and 30% natural gas compared to 73% oil and NGLs and 27% natural gas for
2008. Our average daily production on a boe basis was 703 boe per day during 2009 compared to 570
boe per day for the 2008 year. The increase in production in 2009 compared to 2008 is primarily
attributable to the effect of development expenditures. We expect production to increase in 2010
due to our acquisition of Triad which closed in February, 2010 and our continuing development
efforts in our other fields.
Oil and gas sales. Oil and gas sales decreased $4.4 million, or 30.7%, for the year ended December
31, 2009 to $10.0 million from $14.5 million for the year ended December 31, 2008. The decrease in
oil and gas sales principally resulted from sharp decreases in the prices we received for our oil,
natural gas and NGL production. The average price we received for our production decreased from
$69.43 per Boe to $39.10 per Boe, or a 43.7% decrease. Of the $4.4 million decrease in revenues,
approximately $6.3 million was attributable to a decrease in oil and gas prices, offset by $1.9
million in revenues attributable to the increase in production volumes from 209 Mboe in 2008 to 257
Mboe in 2009. The prices we receive for our products are generally tied to commodity index prices.
We periodically enter into commodity derivative contracts in an attempt to offset some of the
variability in prices. See the discussion of commodity derivative activities below.
56
Other income. Other income for the year ended December 31, 2009 included $0.2 million in a
liquidating damage penalty assessed against an operating partner. Other income for the year ended
December 31, 2008 included a $1.2 million gain from the sale of our 5.33% interest in the Hall
Houston Exploration II partnership and $0.2 million of liquidated damage penalty assessed against
an operating partner.
Lease operating expense. Our lease operating expenses, or LOE, decreased $32,000, or 1%, for the
year ended December 31, 2009 to $4.2 million ($16.45 per Boe) from $4.3 million ($20.38 per Boe)
for the year ended December 31, 2008. The decrease in the per Boe cost is due to our increased
overall production and lower costs overall and per Boe produced in our North Dakota operations ,
where we benefited from lower power and service costs. We expect this trend to continue in our
North Dakota fields where fixed costs are a relatively high percentage of total LOE and where we
have seen response to our unitization and secondary recovery efforts.
Severance taxes and marketing. Our severance taxes decreased $334,000, or 35.2%, for the year
ended December 31, 2009 to $614,000 from $948,000 for the year ended December 31, 2008. The
decrease in production taxes was a function of the decrease in oil and gas sales between 2009 and
2008. Marketing expenses increased $266,000, or 149.2%, for the year ended December 31, 2009 to
$444,000 from $178,000 for the year ended December 31, 2008. The increase in marketing costs was a
function of the necessity to increase compression capacity to maintain low gas pressure in several
of our fields in 2009. Severance taxes and marketing amounted to approximately 10.5% and 7.8% of
oil and gas sales for December 31, 2009 and 2008, respectively.
Exploration. We recorded $0.9 million of exploration expense for the year ended December 31, 2009,
compared to $7.3 million for the year ended December 31, 2008. Exploration expense in the 2009
period resulted primarily from dry hole costs in the Boomerang and Hound Dog fields, 3-D seismic
acquired across our Cinco Terry field, the expiration of leases in our LeBlanc Prospect, and other
lease extensions. Exploration expense for the 2008 period resulted from dry hole costs in our North
Dakota fields and the write-off of costs in our South San Arroyo and Whitewater prospects. Due to
additional 3-D expenses from the seismic acquisition across Cinco Terry, lease renewals and
expirations, and potential exploration costs in Northern New Mexico and Eagle Ford Shale in Texas,
we expect exploration expense to increase in 2010.
Impairment of oil and gas properties. We review for impairment our long-lived assets to be held
and used, including proved and unproved oil and gas properties accounted for under the successful
efforts method of accounting. As a result of this review of the recoverability of the carrying
value of our assets, we recorded an impairment of oil and gas properties of $634,000 and $2.0
million in 2009 and 2008, respectively. The 2009 impairment resulted from a write-off of $634,000
of unproved acreage costs in the Boomerang and LeBlanc Prospect areas. In 2008, we took an
impairment write-down of $2.0 million on the East Flaxton Unit in North Dakota due to reduced
expected future cash flows for the unit.
Depletion, depreciation and accretion. Our depletion, depreciation and accretion expense, or DD&A,
decreased $3.2 million, or 41.2%, to $4.5 million for the year ended December 31, 2009 from $7.7
million for the year ended December 31, 2008. Our DD&A per Boe decreased by $19.28, or 52.4%, to
$17.53 per Boe for the year ended December 31, 2009, compared to $36.82 per Boe for the year ended
December 31, 2008. The decrease in DD&A was primarily attributable to the increase in proved
developed producing reserves and total proved reserves in North Dakota of 55.9% and 113%,
respectively, at December 31, 2009 compared to December 31, 2008, due to an upward trend in
production during the third and fourth quarters of 2009 as a response to our new drilling,
unitization and secondary recovery efforts, and lower LOE costs per Boe produced.
General and administrative. Our general and administrative expenses, or G&A, increased $4.5
million, or 114.2%, to $8.5 million ($33.09 per Boe) for the year ended December 31, 2009 from $4.0
million ($19.00 per Boe) for the year ended December 31, 2008. Our G&A for 2009 included higher
share-based compensation, as well as higher salaries, related employee benefit costs attributable
to an increase in staff from the prior year period, higher rent and office costs, and consulting
and professional services, all due to the increased level of activity which began in the second
quarter of 2009 and is continuing. Non-cash G&A expenses totaled $3.1 million and $1.6 million for
the 2009 and 2008 periods, respectively, and represent noncash stock compensation granted our
employees. Also included in G&A in the 2009 period are acquisition related costs of $1.0 million
which were for legal, consulting and other costs related to the acquisition of Sharon Resources,
Inc. on September 30, 2009 and the acquisition of the Triad Companied which closed on February 12,
2010. These costs were expensed due to the requirements of ASC 805 which states that acquisition
costs must be expensed rather than capitalized as part of the cost of the asset being acquired for
years beginning in 2009. Additional acquisition related expenses related to the Triad acquisition
were incurred in 2010. We expect overall G&A costs to increase in 2010 due to the acquisition of
Triad.
Interest expense, net. Our interest expense, net of interest income, increased $0.8 million, or
32.2%, to $3.3 million for the year ended December 31, 2009 from $2.5 million for the year ended
December 31, 2008. This increase was substantially the result of our higher average debt level
during 2009 and our write off of deferred finance costs related to the Revolving Credit Borrowing
and Term Loan paid off on November 23, 2009, in connection with the closing of our new Senior
Revolving Credit Facility.
57
Loss on debt extinguishment. We recorded a loss from debt extinguishment of $2.8 million for the
year ended December 31, 2008, due to the payoff of a credit facility with a different previous
lender.
Commodity derivative activities. Realized gains and losses from our commodity derivative activity
decreased our earnings by $5.4 million and $1.2 million for the years ended December 31, 2009 and
2008, respectively. Realized gains and losses are derived from the relative movement of oil and gas
prices on the products we sell in relation to the range of prices in our derivative contracts for
the respective years. The unrealized loss on commodity derivatives was $7.7 million for 2009 and
the unrealized gain on commodity derivatives was $8.6 million for 2008. As commodity prices
increase, the fair value of the open portion of those positions decreases, and vice versa. As
commodity prices decrease, the fair value of the open portion of those positions increases.
Historically, we have not designated our derivative instruments as cash-flow hedges. We record our
open derivative instruments at fair value on our consolidated balance sheets as either unrealized
gains or losses on commodity derivatives. We record all changes in realized and unrealized gains
and losses on our consolidated statements of operations under the caption entitled Gain (loss) on
derivative contracts. Our gain or loss from realized and unrealized derivative contracts was a
loss of $2.3 million and a gain of $7.3 million for the years ended December 31, 2009 and 2008,
respectively.
Net loss attributable to non-controlling interest. Net loss from non-controlling interest was
$63,000 in 2009 versus $1.6 million in 2008. This represents 12.5% of the loss incurred by our
subsidiary, PRC Williston. We record a non-controlling interest in the results of operations of
this subsidiary because we are contractually obligated to make distributions to the holders of this
interest whenever we make distributions to ourselves from the subsidiary company.
Dividends on Preferred Stock. Dividends on our Series C Preferred Stock were $26,000 in 2009
versus none in 2008. The Series C Preferred Stock has a stated value of $5.4 million, carries a
cumulative dividend rate of 10.25% per annum, and was issued on December 13, 2009. In 2008, we
recorded a dividend of $0.7 million on our Series A Convertible Preferred Stock. We redeemed all of
our Series A Stock was redeemed on September 26, 2008 for $8.0 million.
Liquidity and Capital Resources
We generally will rely on cash generated from operations, borrowings under our revolving credit
facility and, to the extent that credit and capital market conditions will allow, future public and
private equity and debt offerings to satisfy our liquidity needs. Our ability to fund planned
capital expenditures and to make acquisitions depends upon our future operating performance,
availability of borrowings under our revolving credit facility, and more broadly, on the
availability of equity and debt financing, which is affected by prevailing economic conditions in
our industry and financial, business and other factors, some of which are beyond our control. We
cannot predict whether additional liquidity from equity or debt financings beyond our revolving
credit facility will be available, or acceptable on our terms, or at all, in the foreseeable
future.
Our cash flow from operations is driven by commodity prices and production volumes and the effect
of commodity derivatives. Prices for oil and gas are affected by national and international
economic and political environments, national and global supply and demand for hydrocarbons,
seasonal influences of weather and other factors beyond our control. Our working capital is
significantly influenced by changes in commodity prices, and significant declines in prices will
cause a decrease in our production volumes and exploration and development expenditures. Cash flows
from operations are primarily used to fund exploration and development of our oil and gas
properties.
We intend to fund 2010 capital expenditures, excluding any acquisitions, primarily out of
internally-generated cash flows and, as necessary, borrowings under our revolving credit facility.
As of December 31, 2009, we had $12.0 million available to borrow under our revolving credit
facility.
For the year ended December 31, 2009, our primary sources of cash were from financing and operating
activities and cash on hand at the beginning of the year. Approximately $19.1 million of cash from
sale of common and preferred stock, $3.4 million of cash from operating activities and $6.1 million
of cash on hand was used to fund our acquisitions and drilling program, repay debt under our
revolving credit facility, and purchase new derivative contracts.
For the year ended December 31, 2008, our primary sources of cash were from operating activities,
investing activities, financing activities and cash on hand at the beginning of the year.
Approximately $3.4 million of cash from operations and $7.1 million of net borrowings under our
credit facility, along with cash on hand of $15.4 million, were used to fund our drilling program.
We realized $7.8 million of cash from sale of assets which was used to redeem preferred stock.
In comparing 2009 and 2008, our cash flows from operations decreased only slightly in 2009, despite
sharply lower oil and gas sales, due to realized gains on derivative contracts and lower
exploratory costs offsetting the increase in general and administrative costs.
58
The following table summarizes our sources and uses of funds for the periods noted:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Cash flows provided by operating activities |
|
$ |
3,372 |
|
|
$ |
3,437 |
|
Cash flows used in investing activities |
|
|
(16,624 |
) |
|
|
(10,378 |
) |
Cash flows provided by (used in) financing activities |
|
|
9,413 |
|
|
|
(2,338 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
$ |
(3,839 |
) |
|
$ |
(9,279 |
) |
|
|
|
|
|
|
|
Despite the adverse price environment in 2009, we were able to secure a new $150 million credit
facility with an initial borrowing base of $25 million. We define liquidity as funds available
under our revolving credit facility plus year-end cash and cash equivalents. At December 31, 2009,
we had $13.0 million in long-term debt outstanding under our revolving credit facility, compared to
$6.5 million in long-term debt outstanding under the revolving credit facility at December 31,
2008. The following table summarizes our liquidity position at December 31, 2009 compared to
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Borrowing base |
|
$ |
25,000 |
|
|
$ |
17,000 |
|
Cash and cash equivalents |
|
|
2,282 |
|
|
|
6,120 |
|
Long-term debt |
|
|
(13,000 |
) |
|
|
(6,500 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquidity |
|
$ |
14,282 |
|
|
$ |
16,620 |
|
|
|
|
|
|
|
|
There are several factors that will affect our liquidity in 2010. We will have increased operating
cash flows as a result of the Triad acquisition along with increased interest expense due to higher
debt levels and higher dividend costs due to the issuance of our Series B and C Preferred Stock. We
also expect to have increased salary and other administrative costs associated with the
increased number of employees resulting from the Triad acquisition. We will be required to pay back
any borrowing on Tranche B of our Senior Credit Facility no later than February 13, 2011. At March
31, 2010 we had borrowed $9 million under Tranche B. We expect the additional operating cash flows
from the Triad acquisition and cash provided by the issuance of new common and preferred stock in
2010 will provide the cash necessary to meet these requirements. See
Item 7 Managements Discussion and Analysis of
Financial Condition and Results of
Operations Amended and Restated Credit Facility.
Operating Activities
For the year ended December 31, 2009, our cash flow from operations, borrowings under our revolving
credit facility and available cash were used for property development activities. The $3.4 million
in cash flows generated in the 2009 period decreased $0.1 million from the same period in 2008 due
primarily to a $4.4 million decline in oil and gas sales, a $3.0 million increase in the cash
component of G&A expense, a $1.3 million increase in the cash component of interest expense
partially offset by a $1.4 million decrease in working capital components and a $0.1 million
increase in LOE, severance tax and marketing.
Investing Activities
The majority of our cash flows used in investing activities for the years ended 2009 and 2008 were
for the continued development of our Williston Basin properties in North Dakota, Cinco Terry
properties in West Texas, Surprise Prospect properties in East Texas, East Chalkley Prospect in
Louisiana, and other properties. We had $13.3 in capital expenditures in 2009 versus $16.2 million
in 2008. We also advanced $1.3 million to other operators as cash call advances on pending capital
expenditures in 2009. Other uses of funds for investing activities in 2009 were $2.7 million to
purchase a net derivative position upon closeout of our previous credit facility and the unwinding
of most of our previous derivatives. Other sources of funds from investing activities in 2009 were
proceeds from the sale of a portion of our increased interests in the East Chalkley field for
$500,000 and cash we received in the Sharon acquisition of $235,000. In 2008, other uses of cash in
investing activities included an investment in a partnership for $2.0 million and proceeds from the
sale of a partnership interest for $7.8 million.
59
Financing Activities
We borrowed $25.7 million under our revolving credit facility in 2009 compared to $9.4 million in
2008. We repaid $34.2 million and $2.3 million of amounts outstanding under our revolving credit
facility for the years ended December 31, 2009 and 2008, respectively.
In 2009 we also received $14.1 million in net proceeds from the sale of approximately 8.9 million
shares of our common stock (some of which were issued along with approximately 1.7 million common
stock warrants) and $5.0 million in net proceeds from the issuance of approximately 215 thousand
shares of our Series C Preferred Stock. In 2009 we also paid $0.1 million on the contingent
liability associated with our sale of the Hall-Houston Partnership and paid $1.0 million of
deferred financing costs on our new $25 million revolving credit facility. In 2008 we paid $1.5
million in deferred financing costs and paid $8.0 million to redeem our Series A Convertible
Preferred Stock.
We believe that cash flows from operations and borrowings under our revolving credit facility will
finance substantially all of our capital needs through 2010. We may also use our revolving credit
facility for possible acquisitions and temporary working capital needs. Further, we may decide to
access the public or private equity or debt markets for potential acquisitions, working capital or
other liquidity needs, if such financing is available on acceptable terms. In September 2009, we
filed a shelf registration statement on Form S-3 registering up to $100 million of common stock,
preferred stock, warrants and debt securities. The registration statement was declared effective by
the SEC on October 15, 2009.
2010 Capital Expenditures
The following table summarizes our estimated capital expenditures for 2010. We intend to fund 2010
capital expenditures, excluding any acquisitions, primarily out of internally-generated cash flows
and, as necessary, borrowings under our revolving credit facility.
|
|
|
|
|
|
|
Year Ending |
|
|
|
December 31, |
|
|
|
2010 |
|
|
|
(In thousands) |
|
Appalachian Basin |
|
|
|
|
Eureka Hunter Pipeline |
|
$ |
10,000 |
|
Marcellus Shale drilling |
|
|
7,100 |
|
Exploratory Eagle Ford Shale leases and drilling |
|
|
6,950 |
|
Other |
|
|
950 |
|
|
|
|
|
Total capital expenditures |
|
$ |
25,000 |
|
|
|
|
|
Our capital expenditure budget for 2010 is subject to change depending upon a number of factors,
including economic and industry conditions at the time of drilling, prevailing and anticipated
prices for oil and gas, the results of our development and exploration efforts, the availability of
sufficient capital resources for drilling prospects, our financial results, the availability of
leases on reasonable terms and our ability to obtain permits for the drilling locations.
Revolving Credit Facility
On November 23, 2009 we entered into a new asset based, three year senior secured revolving credit
facility with an initial borrowing base availability set at $25 million. The borrowing base is
re-determined semi-annually based on our proved oil and gas reserves, and based on such
re-determination, the borrowing base may be increased up to a maximum amount of $150 million. We or
the lenders can each request one additional borrowing base redetermination each calendar year.
The maturity date under our revolving credit facility is November 23, 2012. Borrowings bear
interest based on the agent banks prime rate plus an applicable margin ranging from 1.50% to
2.50%, or the sum of the LIBOR rate plus an applicable margin ranging from 2.50% to 3.50%. Margins
vary based on the borrowings outstanding compared to the borrowing base. In addition, we pay an
annual commitment ranging from 0.50% to 0.75% of non-used borrowings available under our revolving
credit facility.
We had outstanding borrowings of $13.0 million under our revolving credit facility at December 31,
2009. The weighted average interest rate applicable to our outstanding borrowings under this
revolving credit facility was 3.255% at December 31, 2009. We also have a $5.0 million sublimit
under the agreement for letters of credit, but we had none outstanding at December 31, 2009. Any
letters of credit issued would reduce our amounts available for borrowing under the revolving
credit facility.
Loans under our revolving credit facility are secured by first priority liens on 85% of our and any
of our subsidiary companies oil and gas properties. All liabilities of any of the borrowers under
this revolving credit agreement are guaranteed by the Company and substantially all of our
subsidiaries.
The terms of the credit agreement provide that the revolving facility may be used for loans and
letters of credit with the limitation stated earlier. We used the initial advance under the
facility to repay all borrowings under our prior loan facility with another lender
which had interest rates of 5.5% and 10% on the revolver and term loan, respectively. Borrowings
may be used for working capital for exploration, development and production purposes, to re-finance
existing debt and for general corporate purposes.
60
Amended and Restated Credit Facility
On February 12, 2010 we entered into an amended and restated credit agreement which increased the
current borrowing base to $70 million. The initial $70 million borrowing base consists of a $60
million A tranche and a $10 million B tranche. Borrowings under the $10 million tranche must be
reduced to an amount less than or equal to $9 million, $7 million, and $4 million on the three, six
and nine month anniversaries, respectively, of the execution of the restated credit agreement. Such
$10 million tranche will terminate entirely on the first anniversary of the restated credit
agreement. Subject to certain exceptions, any equity raised by the Company through a fully marketed
offering must be used to repay this $10 million tranche. As of March 1, 2010, we have reduced our
borrowings under the B Tranche to $9 million. The restated credit agreement has a commitment fee
which ranges between 0.50% and 0.75%, based upon the unused portion of the borrowing base.
Borrowings under the revolving facility will, at the Companys election bear interest at either (i)
an alternate base rate (ABR) equal to the higher of (A) Bank of Montreals base rate, (B) the
Federal Funds Effective Rate, plus 0.5% per annum and the (C) the LIBO Rate for a one month
interest period on such day, plus 1.0% or (ii) the adjusted LIBO rate, which is the rate stated on
Reuters BBA Libor Rates C2BORO1 market for one, two, three, six or twelve months, as adjusted for
statutory reserve requirements for Eurocurrency liabilities, plus, in each of the cases described
in (i) or (ii) above, an applicable margin ranging from 3.50% to 6.50% for ABR loans and from 4.50%
to 7.50% for adjusted LIBO Rate loans until the earlier of the repayment of the $10 million tranche
or the first anniversary and thereafter an applicable margin ranging from 1.50% to 2.50% for ABR
loans and from 2.50% to 3.50% for adjusted LIBO Rate loans. The restated facility also granted a
security interest on up to 90% of our proved developed producing oil and gas properties. We used
the initial advance under the facility to finance our acquisition of the Triad Companies on
February 12, 2010.
At March 29, 2010, we had $64 million outstanding under our revolving credit facility, including $9
million borrowed under Tranche B, with a weighted average interest rate of 5.5%.
Covenants
The Credit Agreement, as amended and restated on February 12, 2010, requires the Company to satisfy
certain affirmative financial covenants, including maintaining (a) an interest coverage ratio (as
such term is defined in the Credit Agreement) of not less than 2.5:1.0; (b) a ratio of total debt
(as such term is defined in the Credit Agreement) to EBITDAX of not more than (1) 4.5:1.0 for the
fiscal quarters ending December 31, 2009, March 31, 2010 and June 30, 2010 and (2) 4.0:1.0 for each
fiscal quarter ending thereafter; and (c) a ratio of consolidated current assets (including
available borrowing) to consolidated current liabilities of not less than 1.0:1.0. The Company is
also required to enter into certain commodity price hedging agreements pursuant to the terms of the
Credit Agreement. At December 31, 2009, we were in compliance with all of our then-applicable
covenants and had not committed any acts of default under the credit agreement.
The credit agreement also restricts certain payments, transactions with affiliates, incurrence of
other debt, consolidations and mergers, assets sales, investments in other entities, liens on
properties, and other customary restrictions for agreements of this type In addition, our credit
agreement contains customary events of default that would permit our lenders to accelerate the debt
under our credit agreement if not cured within applicable grace periods, including, among others,
payment defaults, defaults in the performance of affirmative or negative covenants, the inaccuracy
of representations or warranties, bankruptcy or related defaults, defaults relating to judgments
and the occurrence of a change in control (as such term is defined in the Credit Agreement).
To date we have experienced no disruptions in our ability to access our revolving credit facility.
However, our lenders have substantial ability to reduce our borrowing base on the basis of
subjective factors, including the loan collateral value that each lender, in its discretion and
using the methodology, assumptions and discount rates as such lender customarily uses in evaluating
oil and gas properties, assigns to our properties.
Contractual Commitments
Our contractual commitments consist of long-term debt, accrued interest on long-term debt,
operating lease obligations, asset retirement obligations and employment agreements with executive
officers.
Our long-term debt is composed of borrowings under our revolving credit facility. Interest on debt
is based on the rate applicable under our revolving credit facility, which was 3.26% at December
31, 2009. See Note 7 in our consolidated financial statements.
In February 2007, we signed a five-year lease for approximately 2,900 square feet of office space
in Houston, Texas. In February 2009, we expanded our office space by signing a three-year lease
for approximately 3,200 square feet of additional office space. On September 30, 2009 we acquired
Sharon Resources along with its 29 month commitment to rent 6,000 square feet of office space in
Houston, Texas. In November 2009, we expanded our office space under an amendment to the lease by
approximately 1,600 square feet. Our rent payments are approximately $23,600 per month, including
common area expenses.
61
Our asset retirement obligation primarily represents the estimated present value of the amount we
will incur to plug, abandon and remediate our producing properties at the end of their productive
lives, in accordance with applicable federal, state and local laws. We determine our asset
retirement obligation by calculating the present value of estimated cash flows related to the
liability. The retirement obligation is recorded as a liability at its estimated present value as
of the assets inception, with an offsetting increase to proved properties. Periodic accretion of
discount of the estimated liability is recorded as an expense in the income statement.
We have outstanding employment agreements with six of our executive and senior officers for terms
ranging from one to three years. Our maximum commitment under the employment agreements, which
would apply if the employees covered by these agreements were all terminated without cause, was
approximately $1.1 million at December 31, 2009.
The following table summarizes these commitments as of December 31, 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less than |
|
|
|
|
|
|
|
|
|
|
More than |
|
Contractual Obligations |
|
Total |
|
|
1 Year |
|
|
1-3 Years |
|
|
3-5 Years |
|
|
5 Years |
|
Long-term debt(1) |
|
$ |
13,000 |
|
|
$ |
|
|
|
$ |
13,000 |
|
|
$ |
|
|
|
$ |
|
|
Interest on long-term debt(2) |
|
|
1,226 |
|
|
|
423 |
|
|
|
803 |
|
|
|
|
|
|
|
|
|
Operating lease obligations(3) |
|
|
807 |
|
|
|
397 |
|
|
|
380 |
|
|
|
30 |
|
|
|
|
|
Asset retirement obligations(4) |
|
|
2,032 |
|
|
|
|
|
|
|
686 |
|
|
|
104 |
|
|
|
1,242 |
|
Employment agreements with executive officers |
|
|
1,127 |
|
|
|
1,127 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
18,192 |
|
|
$ |
1,947 |
|
|
$ |
14,869 |
|
|
$ |
134 |
|
|
$ |
1,242 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
See Note 7 to our consolidated financial statements for a discussion of our revolving credit facility. |
|
(2) |
|
Interest payments have been calculated by applying the interest rate of 3.26% at December 31, 2009, to
the outstanding long-term debt of $13.0 million at December 31, 2009. |
|
(3) |
|
Operating lease obligations are for office space and equipment. |
|
(4) |
|
See Note 6 to our consolidated financial statements for a discussion of our asset retirement obligations. |
Off-Balance Sheet Arrangements
From time to time, we enter into off-balance sheet arrangements and transactions that can give rise
to off-balance sheet obligations. As of December 31, 2009, the off-balance sheet arrangements and
transactions that we have entered into include undrawn letters of credit, and operating lease
agreements. We do not believe that these arrangements are reasonably likely to materially affect
our liquidity or availability of, or requirements for, capital resources.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not applicable.
62
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
64 |
|
|
|
|
|
|
|
|
|
65 |
|
|
|
|
|
|
|
|
|
F-1 |
|
|
|
|
|
|
|
|
|
F-2 |
|
|
|
|
|
|
|
|
|
F-3 |
|
|
|
|
|
|
|
|
|
F-4 |
|
|
|
|
|
|
|
|
|
F-5 |
|
63
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors
Magnum Hunter Resources Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheet of Magnum Hunter Resources Corporation
(the Company) as of December 31, 2009, and the related consolidated statements of operations,
shareholders equity, and cash flows for the year then ended. These consolidated financial
statements are the responsibility of the Companys management. Our responsibility is to express an
opinion on these consolidated financial statements 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 an audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An audit also 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 audit
provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the financial position of Magnum Hunter Resources Corporation as of December 31, 2009,
and the results of operations and cash flows for the years then ended, in conformity with
accounting principles generally accepted in the United States of America.
We
were not engaged to examine managements assertion about the
effectiveness of Magnum Hunter Resources internal control
over financial reporting as of December 31, 2009 included in
Managements Report on Internal Control over Financial
Reporting, and accordingly, we do not express an opinion thereon.
As
discussed in Note 2 to the Financial Statements, the Company
adopted the provisions of Financial Accounting Standards
Codification 810, Non-controlling Interests in Consolidated
financial statements an amendment to ARB
No. 51, during the year ended December 31, 2009.
Hein & Associates LLP
Dallas, Texas
March 31, 2010
64
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors
Petro Resources Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheet of Petro Resources Corporation (the
Company) as of December 31, 2008, and the related consolidated statements of operations,
shareholders equity, and cash flows for the year then ended. These consolidated financial
statements are the responsibility of the Companys management. Our responsibility is to express an
opinion on these consolidated financial statements 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 an audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. The
Company is not required to have, nor were we engaged to perform, an audit of its internal control
over financial reporting. Our audit included consideration of internal control over financial
reporting as a basis for designing audit procedures that are appropriate in the circumstances, but
not for the purpose of expressing an opinion on the effectiveness of the Companys internal control
over financial reporting. Accordingly, we express no such opinion. An audit also 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 audit
provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the financial position of Petro Resources Corporation as of December 31, 2008,
and the results of operations and cash flows for the year then ended, in conformity with
accounting principles generally accepted in the United States of America.
|
|
|
/s/ MALONE & BAILEY, PC
|
|
|
www.malone-bailey.com |
|
|
Houston, Texas |
|
|
March 30, 2009 |
|
|
65
MAGNUM HUNTER RESOURCES CORPORATION
(FORMERLY PETRO RESOURCES CORPORATION)
CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
December 31, |
|
|
2008 |
|
|
|
2009 |
|
|
Revised |
|
ASSETS |
|
|
|
|
|
|
|
|
CURRENT ASSETS: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
2,281,568 |
|
|
$ |
6,120,402 |
|
Accounts receivable |
|
|
3,236,043 |
|
|
|
1,038,973 |
|
Prepaids |
|
|
94,113 |
|
|
|
75,406 |
|
Derivative assets |
|
|
1,261,534 |
|
|
|
2,944,997 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
6,873,258 |
|
|
|
10,179,778 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT: |
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts accounting |
|
|
|
|
|
|
|
|
Unproved |
|
|
11,887,483 |
|
|
|
18,415,117 |
|
Proved properties, net |
|
|
43,995,567 |
|
|
|
27,264,790 |
|
Advances |
|
|
1,474,704 |
|
|
|
147,815 |
|
Furniture and fixtures, net |
|
|
180,878 |
|
|
|
110,499 |
|
|
|
|
|
|
|
|
Total property and equipment |
|
|
57,538,632 |
|
|
|
45,938,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS: |
|
|
|
|
|
|
|
|
Derivative Assets |
|
|
1,092,152 |
|
|
|
4,338,832 |
|
Deferred financing costs, net of amortization of $35,831 and $129,200, respectively |
|
|
1,012,756 |
|
|
|
1,197,780 |
|
Deposits |
|
|
67,253 |
|
|
|
10,257 |
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
66,584,051 |
|
|
$ |
61,664,868 |
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
4,852,221 |
|
|
$ |
2,617,034 |
|
Accrued liabilities |
|
|
885,622 |
|
|
|
106,592 |
|
Revenue payable |
|
|
342,585 |
|
|
|
|
|
Payable on sale of partnership |
|
|
|
|
|
|
754,255 |
|
Dividend payable |
|
|
25,654 |
|
|
|
|
|
Note payable |
|
|
44,157 |
|
|
|
19,527 |
|
Derivative liability |
|
|
69,136 |
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
6,219,375 |
|
|
|
3,497,408 |
|
|
|
|
|
|
|
|
|
|
Payable on sale of partnership |
|
|
640,695 |
|
|
|
|
|
Revolving credit borrowings |
|
|
13,000,000 |
|
|
|
6,500,000 |
|
Term loan |
|
|
|
|
|
|
15,000,000 |
|
Asset retirement obligation |
|
|
2,032,306 |
|
|
|
1,589,197 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
21,892,376 |
|
|
|
26,586,605 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES (Note 13) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redeemable Preferred Stock |
|
|
|
|
|
|
|
|
Series C
Convertible Preferred Stock cumulative, dividend rate 10.25% per
annum, 214,950 shares outstanding at December 31, 2009, with
liquidation preference of $25.00 per share |
|
|
5,373,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS EQUITY: |
|
|
|
|
|
|
|
|
Common stock, $0.01 par value; 100,000,000 shares authorized, 50,591,610 and 36,768,172 shares issued and
outstanding as of December 31, 2009 and December 31, 2008 respectively |
|
|
505,916 |
|
|
|
367,682 |
|
Additional paid in capital |
|
|
71,936,306 |
|
|
|
51,311,502 |
|
Accumulated deficit |
|
|
(33,135,693 |
) |
|
|
(17,985,830 |
) |
Deposit on Triad |
|
|
(1,310,357 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total Magnum Hunter Resources Corporation shareholders equity |
|
|
37,996,172 |
|
|
|
33,693,354 |
|
Noncontrolling interest |
|
|
1,321,753 |
|
|
|
1,384,909 |
|
|
|
|
|
|
|
|
Total Shareholders Equity |
|
|
39,317,925 |
|
|
|
35,078,263 |
|
Total Liabilities and Shareholders Equity |
|
$ |
66,584,051 |
|
|
$ |
61,664,868 |
|
|
|
|
|
|
|
|
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements.
F-1
MAGNUM HUNTER RESOURCES CORPORATION
(FORMERLY PETRO RESOURCES CORPORATION)
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
|
December 31, |
|
|
|
|
|
|
|
2008 |
|
|
|
2009 |
|
|
Revised |
|
REVENUE: |
|
|
|
|
|
|
|
|
Oil and gas sales |
|
$ |
10,035,033 |
|
|
$ |
14,486,478 |
|
Other income |
|
|
222,668 |
|
|
|
200,000 |
|
Gain on sale of property |
|
|
14,000 |
|
|
|
1,196,963 |
|
|
|
|
|
|
|
|
Total revenue |
|
|
10,271,701 |
|
|
|
15,883,441 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES: |
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
4,220,345 |
|
|
|
4,252,835 |
|
Severance taxes and marketing |
|
|
1,057,818 |
|
|
|
1,126,156 |
|
Exploration |
|
|
896,337 |
|
|
|
7,348,778 |
|
Impairment of oil & gas properties |
|
|
633,953 |
|
|
|
1,973,015 |
|
Depreciation, depletion and accretion |
|
|
4,499,611 |
|
|
|
7,682,293 |
|
General and administrative |
|
|
8,490,364 |
|
|
|
3,964,664 |
|
|
|
|
|
|
|
|
Total expenses |
|
|
19,798,428 |
|
|
|
26,347,741 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS FROM OPERATIONS |
|
|
(9,526,727 |
) |
|
|
(10,464,300 |
) |
|
|
|
|
|
|
|
|
|
OTHER INCOME (EXPENSE): |
|
|
|
|
|
|
|
|
Interest income |
|
|
959 |
|
|
|
188,932 |
|
Interest expense |
|
|
(3,336,346 |
) |
|
|
(2,771,858 |
) |
Loss on debt extinguishment |
|
|
|
|
|
|
(2,790,829 |
) |
Gain (loss) on derivative contracts |
|
|
(2,325,251 |
) |
|
|
7,311,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
(15,187,365 |
) |
|
|
(8,526,800 |
) |
|
|
|
|
|
|
|
|
|
Less: Net loss attributable to non-controlling interest |
|
|
63,156 |
|
|
|
1,640,466 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss attributable to Magnum Hunter Resources Corporation |
|
|
(15,124,209 |
) |
|
|
(6,886,334 |
) |
|
|
|
|
|
|
|
|
|
Dividend on Series A Convertible Preferred |
|
|
|
|
|
|
(734,406 |
) |
Dividend on Series C Preferred |
|
|
(25,654 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss to attributable to common shareholders |
|
$ |
(15,149,863 |
) |
|
$ |
(7,620,740 |
) |
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding, basic and diluted |
|
|
38,953,834 |
|
|
|
36,714,489 |
|
Net loss per common share, basic and diluted |
|
$ |
(0.39 |
) |
|
$ |
(0.21 |
) |
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements.
F-2
MAGNUM HUNTER RESOURCES CORPORATION
(FORMERLY PETRO RESOURCES CORPORATION)
CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number |
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
|
|
|
|
|
|
of Shares |
|
|
Deposit |
|
|
Common |
|
|
Paid in |
|
|
Noncontrolling |
|
|
Accumulated |
|
|
Total |
|
|
|
of Common |
|
|
on Triad |
|
|
Stock |
|
|
Capital |
|
|
Interest |
|
|
Deficit |
|
|
Equity |
|
BALANCE, December 31, 2007 |
|
|
36,599,372 |
|
|
$ |
|
|
|
$ |
365,994 |
|
|
$ |
49,723,515 |
|
|
$ |
3,025,375 |
|
|
$ |
(10,365,090 |
) |
|
$ |
42,749,794 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends on Series A Convertible Preferred |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(734,406 |
) |
|
|
(734,406 |
) |
Restricted stock issued to employees and directors |
|
|
168,800 |
|
|
|
|
|
|
|
1,688 |
|
|
|
341,782 |
|
|
|
|
|
|
|
|
|
|
|
343,470 |
|
Stock compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,246,205 |
|
|
|
|
|
|
|
|
|
|
|
1,246,205 |
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,640,466 |
) |
|
|
(6,886,334 |
) |
|
|
(8,526,800 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE, December 31, 2008 |
|
|
36,768,172 |
|
|
$ |
|
|
|
$ |
367,682 |
|
|
$ |
51,311,502 |
|
|
$ |
1,384,909 |
|
|
$ |
(17,985,830 |
) |
|
$ |
35,078,263 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock issued to employees and directors |
|
|
1,886,200 |
|
|
|
|
|
|
|
18,862 |
|
|
|
1,361,719 |
|
|
|
|
|
|
|
|
|
|
|
1,380,581 |
|
Stock compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,710,753 |
|
|
|
|
|
|
|
|
|
|
|
1,710,753 |
|
Issued 2,294,474 shares for acquisition of Sharon
Resources, Inc. |
|
|
2,294,474 |
|
|
|
|
|
|
|
22,944 |
|
|
|
2,661,591 |
|
|
|
|
|
|
|
|
|
|
|
2,684,535 |
|
Issued 214,950 shares of Series C Preferred Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(418,205 |
) |
|
|
|
|
|
|
|
|
|
|
(418,205 |
) |
Issued 8,881,112 shares of Common Stock |
|
|
8,881,112 |
|
|
|
|
|
|
|
88,811 |
|
|
|
14,006,206 |
|
|
|
|
|
|
|
|
|
|
|
14,095,017 |
|
Dividends on Series C Convertible Preferred |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(25,654 |
) |
|
|
(25,654 |
) |
Issued 761,652 shares as deposit on Triad Acquisition |
|
|
761,652 |
|
|
|
(1,310,357 |
) |
|
|
7,617 |
|
|
|
1,302,740 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(63,156 |
) |
|
|
(15,124,209 |
) |
|
|
(15,187,365 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE, December 31, 2009 |
|
|
50,591,610 |
|
|
$ |
(1,310,357 |
) |
|
$ |
505,916 |
|
|
$ |
71,936,306 |
|
|
$ |
1,321,753 |
|
|
$ |
(33,135,693 |
) |
|
$ |
39,317,925 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements.
F-3
MAGNUM HUNTER RESOURCES CORPORATION
(FORMERLY PETRO RESOURCES CORPORATION)
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Cash flows from operating activities |
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(15,124,209 |
) |
|
$ |
(6,886,334 |
) |
Adjustments to reconcile net income to net cash
provided by operating activities: |
|
|
|
|
|
|
|
|
Noncontrolling interest |
|
|
(63,156 |
) |
|
|
(1,640,466 |
) |
Depletion, depreciation, and accretion |
|
|
4,499,611 |
|
|
|
7,682,293 |
|
Stock-based compensation |
|
|
3,091,334 |
|
|
|
1,589,675 |
|
Impairment |
|
|
633,953 |
|
|
|
1,973,015 |
|
Gain on asset retirement obligation |
|
|
|
|
|
|
(16,837 |
) |
Exploratory costs |
|
|
647,001 |
|
|
|
7,140,013 |
|
Gain on sale of assets |
|
|
(14,000 |
) |
|
|
(1,196,963 |
) |
Loss on extinguishment of debt |
|
|
|
|
|
|
2,790,829 |
|
Unrealized (gain) loss on derivative contracts |
|
|
7,700,129 |
|
|
|
(9,116,145 |
) |
Amortization of deferred financing cost |
|
|
1,233,611 |
|
|
|
1,737,458 |
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
Accounts receivable and accrued revenue |
|
|
(1,908,945 |
) |
|
|
(114,366 |
) |
Prepaid expenses |
|
|
(16,313 |
) |
|
|
(49,887 |
) |
Accounts payable |
|
|
1,571,108 |
|
|
|
(631,563 |
) |
Revenue payable |
|
|
342,585 |
|
|
|
|
|
Accrued liabilities |
|
|
779,030 |
|
|
|
176,607 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
3,371,739 |
|
|
|
3,437,329 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(13,274,656 |
) |
|
|
(16,222,790 |
) |
Change in advances |
|
|
(1,326,889 |
) |
|
|
|
|
Cash received in purchase of Sharon Resources, Inc. |
|
|
235,023 |
|
|
|
|
|
Proceeds from sale of assets |
|
|
500,000 |
|
|
|
7,843,962 |
|
Purchase of Derivatives |
|
|
(2,700,850 |
) |
|
|
|
|
Change in deposits |
|
|
(56,246 |
) |
|
|
|
|
Investment in partnership |
|
|
|
|
|
|
(1,999,800 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(16,623,618 |
) |
|
|
(10,378,628 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities |
|
|
|
|
|
|
|
|
Net proceeds from sale of common stock and warrants |
|
|
14,095,017 |
|
|
|
|
|
Net proceeds from sale of preferred shares |
|
|
4,955,545 |
|
|
|
|
|
Principal payments on debt |
|
|
(34,193,566 |
) |
|
|
(2,253,861 |
) |
Proceeds from debt borrowings |
|
|
25,718,196 |
|
|
|
9,354,295 |
|
Payment on payable on sale of partnership |
|
|
(113,560 |
) |
|
|
|
|
Payment of deferred financing costs |
|
|
(1,048,587 |
) |
|
|
(1,471,545 |
) |
Redemption of preferred stock |
|
|
|
|
|
|
(7,966,735 |
) |
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
9,413,045 |
|
|
|
(2,337,846 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents |
|
|
(3,838,834 |
) |
|
|
(9,279,145 |
) |
Cash and cash equivalents, beginning of year |
|
|
6,120,402 |
|
|
|
15,399,547 |
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of year |
|
$ |
2,281,568 |
|
|
$ |
6,120,402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest |
|
$ |
2,142,454 |
|
|
$ |
1,554,484 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncash transactions |
|
|
|
|
|
|
|
|
Capitalized interest in oil and gas properties |
|
$ |
|
|
|
$ |
1,080,177 |
|
|
|
|
|
|
|
|
Property and equipment included in accounts payable |
|
$ |
|
|
|
$ |
1,527,440 |
|
|
|
|
|
|
|
|
Stock issued for acquisition of Sharon Resources, Inc. |
|
$ |
2,684,535 |
|
|
$ |
|
|
|
|
|
|
|
|
|
Refinancing of Petrobridge loan |
|
$ |
|
|
|
$ |
16,239,152 |
|
|
|
|
|
|
|
|
The accompanying Notes to Consolidated Financial Statements are an integral part of these Statements.
F-4
NOTE 1 ORGANIZATION AND NATURE OF OPERATIONS
Magnum Hunter Resources Corporation and subsidiaries (Magnum Hunter) (a Delaware Corporation) is
a Houston, Texas based independent exploration and production company engaged in the acquisition
and development of producing properties, secondary enhanced oil recovery projects, and production
of oil and natural gas in the United States.
On July 14, 2009, the Company formed a new subsidiary to purchase Magnum Hunter Resources, LP and
the new subsidiary was merged into Petro Resources Corporation in order to effect a name change
from Petro Resources Corporation to Magnum Hunter Resources Corporation.
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Presentation
The consolidated financial statements include the accounts of Magnum Hunter and our wholly-owned
subsidiary, Sharon Resources, Inc. (Sharon) We also have consolidated our 87.5% controlling
interest in PRC Williston, LLC (PRC) with noncontrolling interests recorded for the outside
interest in PRC. All significant intercompany balances and transactions have been eliminated.
Our financial statements are prepared in accordance with accounting principles generally accepted
in the United States of America. The preparation of our financial statements requires management to
make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses. These estimates are based on information that is currently available to us and on
various other assumptions that we believe to be reasonable under the circumstances. Actual results
could differ from those estimates under different assumptions and conditions. Significant
estimates are required for proved oil and gas reserves which, as described in Note 2 Estimates of
Proved Oil and Gas Reserves, may have a material impact on the carrying value of oil and gas
property.
Critical accounting policies are defined as those significant accounting policies that are most
critical to an understanding of a companys financial condition and results of operation. We
consider an accounting estimate or judgment to be critical if (i) it requires assumptions to be
made that were uncertain at the time the estimate was made, and (ii) changes in the estimate or
different estimates that could have been selected could have a material impact on our results of
operations or financial condition.
Cash and cash equivalents
Cash and cash equivalents include cash in banks and highly liquid debt securities that have
original maturities of three months or less. At December 31, 2009, the Company had cash deposits
in excess of FDIC insured limits at various financial institutions.
Financial Instruments
The carrying amounts of financial instruments including cash and cash equivalents, accounts
receivable, notes receivable, accounts payable and accrued liabilities and long-term debt
approximate fair value, as of December 31, 2009 and 2008. See Note 3 for commodity derivative fair
value disclosures.
F-5
Oil and Gas Properties
Capitalized Costs
Our oil and gas properties comprised the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Mineral interests in properties: |
|
|
|
|
|
|
|
|
Unproved properties |
|
$ |
12,490 |
|
|
$ |
18,563 |
|
Proved properties |
|
|
59,897 |
|
|
|
39,266 |
|
Total costs |
|
|
72,387 |
|
|
|
57,977 |
|
Less accumulated depreciation, depletion and impairment |
|
|
(16,504 |
) |
|
|
(12,149 |
) |
Advances |
|
|
1,475 |
|
|
|
148 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs |
|
$ |
57,358 |
|
|
$ |
45,828 |
|
|
|
|
|
|
|
|
We follow the successful efforts method of accounting for our oil and gas producing activities.
Costs to acquire mineral interests in oil and gas properties and to drill and equip development
wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are
capitalized pending determination of whether the wells have proved reserves. If we determine that
the wells do not have proved reserves, the costs are charged to expense. Geological and geophysical
costs, including seismic studies and costs of carrying and retaining unproved properties are
charged to expense as incurred. We capitalize interest on expenditures for significant exploration
and development projects that last more than six months while activities are in progress to bring
the assets to their intended use.
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated
depreciation, depletion, and amortization are eliminated from the property accounts, and the
resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved
property, the cost is charged to accumulated depreciation, depletion, and amortization with a
resulting gain or loss recognized in income.
Capitalized amounts attributable to proved oil and gas properties are depleted by the
unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to
one Bbl of oil. Depreciation and depletion expense for oil and gas producing property and related
equipment was $4.5 million and $7.7 million for the years ended December 31, 2009 and 2008,
respectively.
Unproved oil and gas properties that are individually significant are periodically assessed for
impairment of value, and a loss is recognized at the time of impairment by providing an impairment
allowance. We recorded an impairment charge of $634 thousand during the year ended December 31,
2009 and none in 2008 related to our assessment of unproved properties. The 2009 impairment
resulted from a write-off of $441 thousand in acreage costs in the Boomerang Prospect in Kentucky,
$125 thousand on the LeBlanc Prospect in Louisiana, and $68 thousand in the West Greene Field in
North Dakota.
Capitalized costs related to proved oil and gas properties, including wells and related equipment
and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash
flows in accordance with ASC 360, formerly Statement of Financial Accounting Standards 144,
Accounting for the Impairment or Disposal of Long-Lived Assets. If undiscounted cash flows are
insufficient to recover the net capitalized costs related to proved properties, then we recognize
an impairment charge in income from operations equal to the difference between the net capitalized
costs related to proved properties and their estimated fair values based on the present value of
the related future net cash flows. We noted no impairment of our proved properties based on our
analysis for the year ended December 31, 2009. For the year ended December 31, 2008, we recorded an
impairment of leasehold and well costs of 2.0 million on the East Flaxton Unit in North Dakota.
It is common for operators of oil and gas properties to request that joint interest owners
pay for large expenditures, typically for drilling new wells, in advance of the work commencing.
This right to call for cash advances is typically found in the operating agreement that joint
interest owners in a property adopt. We record these advance payments in Advances in our property
account and release this account when the actual expenditure is later billed to us by the operator.
F-6
On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss
on the sale is recognized, taking into consideration the amount of any recorded impairment if the
property had been assessed individually. If a partial interest in an unproved property is sold, the
amount received is treated as a reduction of the cost of the interest retained.
Estimates of Proved Oil and Gas Reserves
Estimates of our proved reserves included in this report are prepared in accordance with U.S.
generally accepted accounting principles (GAAP) and SEC guidelines. The accuracy of a reserve
estimate is a function of:
|
|
the quality and quantity of available data; |
|
|
|
the interpretation of that data; |
|
|
|
the accuracy of various mandated economic assumptions; |
|
|
|
and the judgment of the persons preparing the estimate. |
Our proved reserve information included in this report was predominately based on evaluations
prepared by independent petroleum engineers. Estimates prepared by other third parties may be
higher or lower than those included herein. Because these estimates depend on many assumptions, all
of which may substantially differ from future actual results, reserve estimates will be different
from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling,
testing and production after the date of an estimate may justify material revisions to the
estimate.
In accordance with SEC requirements, beginning December 31, 2009, we based the estimated discounted
future net cash flows from proved reserves on the unweighted arithmetic average of the prior
12-month commodity prices as of the first day of each of the months constituting the period and
costs on the date of the estimate. In prior years, such estimates had been based on year end prices
and costs. Future prices and costs may be materially higher or lower than these prices and costs
which would impact the estimated value of our reserves.
The estimates of proved reserves materially impact DD&A expense. If the estimates of proved
reserves decline, the rate at which we record DD&A expense will increase, reducing future net
income. Such a decline may result from lower market prices, which may make it uneconomic to drill
for and produce higher cost fields.
The adoption of the new guidance in fiscal 2009 resulted in a downward adjustment of 386 MBOE of proved reserves. The change resulted in an increase of $145 thousand in DD&A expense
in the fourth quarter of 2009.
Oil and Gas Operations
Accounts Receivable
We recognize revenue for our production when the quantities are delivered to or collected by the
respective purchaser. Prices for such production are defined in sales contracts and are readily
determinable based on certain publicly available indices. All transportation costs are included in
marketing expense.
Accounts receivable from joint interest owners consist of uncollateralized joint interest owner
obligations due within 30 days of the invoice date. Accounts receivable, oil and gas sales, consist
of uncollateralized accrued revenues due under normal trade terms, generally requiring payment
within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on
all accounts receivable are applied to the earliest unpaid items. We review accounts receivable
periodically and reduce the carrying amount by a valuation allowance that reflects our best
estimate of the amount that may not be collectible. No such allowance was considered necessary at
December 31, 2009 or 2008.
Revenue Payable
Revenue payable represents amounts collected from purchasers for oil and gas sales which are either
revenues due to other revenue interest owners or severance taxes due to the respective state or
local tax authorities. Generally, we are required to remit amounts due under these liabilities
within 30 days of the end of the month in which the related production occurred.
F-7
Advances from Non-Operators
Advances from non-operators represent amounts collected in advance for joint operating activities.
Such amounts are applied to joint interest accounts receivable as related costs are incurred.
Production Costs
Production costs, including compressor rental and repair, pumpers salaries, saltwater disposal, ad
valorem taxes, insurance, repairs and maintenance, expensed workovers and other operating expenses
are expensed as incurred and included in lease operating expense on our consolidated statements of
operations.
Exploration expenses include dry hole costs, delay rentals and geological and geophysical costs.
Dependence on Major Customers
For the years ended December 31, 2009 and 2008, we sold substantially all of our oil and gas
produced to seven purchasers. Additionally, substantially all of our accounts receivable related to
oil and gas sales were due from those seven purchasers at December 31, 2009 and 2008. We believe
that there are potential alternative purchasers and that it may be necessary to establish
relationships with new purchasers. However, there can be no assurance that we can establish such
relationships and that those relationships will result in increased purchasers. Although we are
exposed to a concentration of credit risk, we believe that all of our purchasers are credit worthy.
Dependence on Suppliers
Our industry is cyclical, and from time to time there is a shortage of drilling rigs, equipment,
supplies and qualified personnel. During these periods, the costs and delivery times of rigs,
equipment and supplies are substantially greater. If the unavailability or high cost of drilling
rigs, equipment, supplies or qualified personnel were particularly severe in the areas where we
operate, we could be materially and adversely affected. We believe that there are potential
alternative providers of drilling services and that it may be necessary to establish relationships
with new contractors. However, there can be no assurance that we can establish such relationships
and that those relationships will result in increased availability of drilling rigs.
Other Property
Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and
equipment is provided using the straight-line method over estimated useful lives ranging from three
to five years. Gain or loss on retirement or sale or other disposition of assets is included in
income in the period of disposition.
Depreciation expense for other property and equipment was $41,000 and $25,000 for the years ended
December 31, 2009 and 2008, respectively.
Deferred financing costs
In connection with debt financings in 2009, we paid $1,048,587 in fees. These fees were recorded as
deferred financing costs and are being amortized over the life of the loans using the straight line
method as the debt is in the form of a line of credit. Amortization of deferred financing costs for
the years ended December 31, 2009 and 2008 were $1,233,611 and $1,737,458, respectively.
Derivative Financial Instruments
We use commodity derivative financial instruments, typically options and swaps, to manage the risk
associated with fluctuations in oil and gas prices. We account for derivatives under the provisions
of FASB Accounting Standards Codification (ASC) 815, Derivatives and Hedging, and related
interpretations and amendments. ASC 815, as amended, establishes accounting and reporting standards
requiring that every derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded in the balance sheet as either an asset or liability measured at its
fair market value. The statement requires that changes in the derivatives fair value be recognized
currently in earnings unless
specific hedge criteria are met. Special accounting for qualifying hedges allows a derivatives
gains and losses to offset related results on the hedged item in the income statement and requires
that a company must formally document, designate, and assess the effectiveness of transactions that
receive hedge accounting. Our oil and gas price derivative contracts are not designated as hedges.
In accordance with provisions of ASC 815, these instruments have been marked-to-market through
earnings.
F-8
Share Based Compensation
The Company accounts for share-based compensation in accordance with the provisions of the ASC
standards which require companies to estimate the fair value of share-based payment awards made to
employees and directors, including stock options, restricted stock and employee stock purchases
related to employee stock purchase plans, on the date of grant using an option-pricing model. The
value of the portion of the award that is ultimately expected to vest is recognized as an expense
ratably over the requisite service periods. We estimate the fair value of each share-based award
using the Black-Scholes option pricing model or a lattice model. These models are highly complex
and dependent on key estimates by management. The estimates with the greatest degree of subjective
judgment are the estimated lives of the stock-based awards and the estimated volatility of our
stock price.
Income Taxes
We account for income taxes under the liability method. Deferred tax assets and liabilities are
determined based on differences between financial reporting and tax bases of assets and liabilities
and are measured using the enacted tax rates and laws that will be in effect when the differences
are expected to reverse. We measure and record income tax contingency accruals in accordance with
ASC 740, Income Taxes.
We recognize liabilities for uncertain income tax positions based on a two-step process. The first
step is to evaluate the tax position for recognition by determining if the weight of available
evidence indicates that it is more likely than not that the position will be sustained on audit,
including resolution of related appeals or litigation processes, if any. The second step requires
us to estimate and measure the tax benefit as the largest amount that is more than 50% likely to be
realized upon ultimate settlement. It is inherently difficult and subjective to estimate such
amounts, as we must determine the probability of various possible outcomes. We reevaluate these
uncertain tax positions on a quarterly basis or when new information becomes available to
management. These reevaluations are based on factors including, but not limited to, changes in
facts or circumstances, changes in tax law, successfully settled issues under audit, expirations
due to statutes, and new audit activity. Such a change in recognition or measurement could result
in the recognition of a tax benefit or an increase to the tax accrual.
We classify interest related to income tax liabilities as income tax expense, and if applicable,
penalties are recognized as a component of income tax expense. The income tax liabilities and
accrued interest and penalties that are anticipated to be due within one year of the balance sheet
date are presented as current liabilities in our consolidated balance sheets.
Loss per Common Share
Basic net income or loss per common share is computed by dividing the net income or loss
attributable to common stockholders by the weighted average number of shares of common stock
outstanding during the period. Diluted net income or loss per common share is calculated in the
same manner, but also considers the impact to net income and common shares for the potential
dilution from stock options, stock warrants and any other outstanding convertible securities.
We have issued potentially dilutive instruments in the form of our Series C Preferred Stock, common
stock warrants and common stock options granted to our employees. There were 19,633,226 and
8,088,962 dilutive securities outstanding at December 31, 2009 and 2008, respectively. We did not
include any of these instruments in our calculation of diluted loss per share during the period
because to include them would be anti-dilutive due to our net loss during the periods.
Reclassification of Prior-Year Balances
Certain prior-year balances in the consolidated financial statements have been reclassified to
correspond with current-year classifications.
F-9
Recently Issued Accounting Pronouncements
In December 2007, FASB issued guidance related to Business Combinations under ASC 805, Business
Combinations, and guidance related to the accounting and reporting of noncontrolling interest under
ASC 810-10-65-1, Consolidation. This guidance significantly changes the accounting for and
reporting of business combination transactions and noncontrolling (minority) interests in
consolidated financial statements. This guidance became effective January 1, 2009. We applied this
guidance to our majority interests in PRC Williston, LLC which resulted in noncontrolling interests
now reported as part of equity and it no longer impacts net loss. Please see Note 9 Shareholders Equity and Note 5 -
Acquisitions and Divestitures for additional information.
In March 2008, the FASB issued guidance related to the disclosures about derivative instruments and
hedging activities under FASB ASC 815-10-50, Derivatives and Hedging. This guidance requires
companies to provide enhanced disclosures about (a) how and why they use derivative instruments,
(b) how derivative instruments and related hedged items are accounted for under
applicable guidance, and (c) how derivative instruments and related hedged items affect a companys
financial position, financial performance, and cash flows. These disclosure requirements are
effective for financial statements issued for fiscal years and interim periods beginning after
November 15, 2008. Our adoption of ASC 815-10-50 on January 1, 2009 did not have a material impact
on our consolidated financial statements. See Note 3 Financial Instruments and Derivatives in
the Notes to Consolidated Financial Statements for additional information.
In June 2008, the FASB issued guidance to evaluate whether an instrument (or embedded feature) is
indexed to an entitys own stock under ASC 815-40-15, Derivatives and Hedging. The guidance
requires entities to evaluate whether an equity-linked financial instrument (or embedded feature)
is indexed to its own stock in order to determine if the instrument should be accounted for as a
derivative under the scope of ASC 815-10-15. This guidance is effective for financial statements
issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal
years. We adopted ASC 815-40-15 beginning January 1, 2009 which did not have a material impact on
our financial statements.
In December 2008, the Securities and Exchange Commission published a Final Rule, Modernization of
the Oil and Gas Reporting Requirements. 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 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. In January 2010, the FASB issued Accounting Standards Update
No. 2010-03, Oil and Gas Reserve Estimation and Disclosure, to align the oil and gas reserve
estimation and disclosure requirement of the SEC Final Rule with the ASC 932. The new disclosure
requirements are effective for annual reports on Form 10-K for fiscal years ending on or after
December 31, 2009. Our adoption of this Final rule for this annual reported dated December 31, 2009
affected our oil and gas disclosures but had no material effect on our
financial position and results of operations.
In May 2009, the FASB issued guidance related to subsequent events under ASC 855-10, Subsequent
Events. This guidance sets forth the period after the balance sheet date during which management or
a reporting entity should evaluate events or transactions that may occur for potential recognition
or disclosure, the circumstances under which an entity should recognize events or transactions
occurring after the balance sheet date, and the disclosures that an entity should make about events
or transactions that occurred after the balance sheet date. It requires disclosure of the date
through which an entity has evaluated subsequent events and the basis for that date, whether that
date represents the date the financial statements were issued or were available to be issued. This
guidance is effective for interim and annual periods ending after June 15, 2009. We adopted ASC
855-10 beginning June 30, 2009 and have included the required disclosures in our consolidated
financial statements. See Note 14 Subsequent Events for additional information.
In June 2009, the FASB issued Accounting Standards Update No. 2009-01 which amends ASC 105,
Generally Accepted Accounting Principles. This guidance states that the ASC will become the source
of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Once
effective, the Codifications content will carry the same level of authority. Thus, the U.S. GAAP
hierarchy will be modified to include only two levels of U.S. GAAP: authoritative and
non-authoritative. This is effective for financial statements issued for interim and annual periods
ending after September 15, 2009. We adopted ASC 105 as of September 30, 2009 and thus have
incorporated the new Codification citations in place of the corresponding references to legacy
accounting pronouncements.
F-10
In August 2009, the FASB issued Accounting Standards Update No. 2009-05, Measuring Liabilities at
Fair Value, which amends ASC 820, Fair Value Measurements and Disclosures. This Update provides
clarification that in circumstances in which a quoted price in an active market for the identical
liability is not available, a reporting entity is required to measure the fair value using one or
more of the following techniques: a valuation technique that uses the quoted price of the identical
liability or similar liabilities when traded as an asset, which would be considered a Level 1
input, or another valuation technique that is consistent with ASC 820. This Update is effective for
the first reporting period (including interim periods) beginning after issuance. Thus, we adopted
this guidance as of September 30, 2009, which did not have a material impact on our consolidated
financial statements.
NOTE 3 FAIR VALUE OF FINANCIAL INSTRUMENTS
Effective January 1, 2008, the Company adopted the provisions of ASC 820, Fair Value measurements
and Disclosures, for all financial instruments. We applied this guidance to our financial assets
and liabilities beginning January 1, 2008 with no material impact on our consolidated statement of
operations or financial condition.
ASC 820 defines fair value as 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. ASC 820
also establishes a framework for measuring fair value and a valuation hierarchy based upon the
transparency of inputs used in the valuation of an asset or liability. Classification within the
hierarchy is based upon the lowest level of input that is significant to the fair value
measurement. The valuation hierarchy contains three levels:
|
|
Level 1 Quoted prices (unadjusted) for identical assets or liabilities in active markets |
|
|
|
Level 2 Quoted prices for similar assets or liabilities in active markets; quoted
prices for identical or similar assets or liabilities in markets that are not active; and
model-derived valuations whose inputs or significant value drivers are observable |
|
|
|
Level 3 Significant inputs to the valuation model are unobservable |
We used the following fair value measurements for certain of our assets and liabilities during the
years ended December 31, 2009 and 2008:
Level 2 Classification:
Derivative Instruments
At December 31, 2009 and 2008, the Company had commodity derivative financial instruments in place
that are accounted for under the ASC standards on derivative instruments. The Company does not
apply hedge accounting as allowed by ASC standards, therefore, the changes in fair value subsequent
to the initial measurement are recorded in income. The estimated fair value amounts of the
Companys derivative instruments have been determined at discrete points in time based on relevant
market information which resulted in the Company classifying such derivatives as Level 2. Although
the Companys derivative instruments are valued using public indexes, the instruments themselves
are traded with third-party counterparties and are not openly traded on an exchange.
As of December 31, 2009 and 2008, the Companys derivative contracts were with major financial
institutions with investment grade credit ratings which are believed to have a minimal credit risk.
As such, the Company is exposed to credit risk to the extent of nonperformance by the
counterparties in the derivative contracts discussed above; however, the Company does not
anticipate such nonperformance.
F-11
The following tables present recurring financial assets and liabilities which are carried at fair
value as of December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements on a recurring basis |
December 31, 2009 |
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
Commodity derivatives |
|
$ |
|
|
|
$ |
2,353,686 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
Total assets as fair value |
|
$ |
|
|
|
$ |
2,353,686 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
$ |
|
|
|
$ |
69,136 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities at fair value |
|
$ |
|
|
|
$ |
69,136 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value measurements on a recurring basis |
December 31, 2008 |
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
Commodity derivatives |
|
$ |
|
|
|
$ |
7,283,829 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
Total assets as fair value |
|
$ |
|
|
|
$ |
7,283,829 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities at fair value |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 4 FINANCIAL INSTRUMENTS AND DERIVATIVES
We enter into certain commodity derivative instruments which are effective in mitigating commodity
price risk associated with a portion of our future monthly natural gas and crude oil production and
related cash flows. Our oil and gas operating revenues and cash flows are impacted by changes in
commodity product prices, which are volatile and cannot be accurately predicted. Our objective for
holding these commodity derivatives is to protect the operating revenues and cash flows related to
a portion of our future crude oil sales from the risk of significant declines in commodity prices.
We have not designated any of our commodity derivatives as hedges under ASC 815.
As of December 31, 2009, the estimated fair values of our commodity derivatives were:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity |
|
Type |
|
Volume/Month |
|
Duration |
|
Price |
|
|
Fair Market Value |
|
Oil |
|
Swap |
|
2,212 Bbls |
|
Jan 10 Feb 10 |
|
$ |
65.40 |
|
|
$ |
(69,136 |
) |
Oil |
|
Swap |
|
670 Bbls |
|
Jan 10 Dec 10 |
|
$ |
81.65 |
|
|
|
(5,139 |
) |
Oil |
|
Swap |
|
4,660 Bbls |
|
Jan 10 Dec 11 |
|
$ |
105.45 |
|
|
|
2,293,729 |
|
Oil |
|
Swap |
|
435 Bbls |
|
Jan 11 Dec 11 |
|
$ |
85.25 |
|
|
|
(4,339 |
) |
Natural Gas |
|
Collar |
|
5,000 Mmbtu |
|
Feb 10 Dec 10 |
|
$ |
5.50 7.75 |
|
|
|
18,028 |
|
Natural Gas |
|
Collar |
|
15,000 Mmbtu |
|
Feb 10 Dec 10 |
|
$ |
5.75 7.10 |
|
|
|
59,342 |
|
Natural Gas |
|
Collar |
|
12,500 Mmbtu |
|
Jan 11 Dec 11 |
|
$ |
5.00 8.20 |
|
|
|
(13,671 |
) |
Natural Gas |
|
Collar |
|
4,165 Mmbtu |
|
Jan 11 Dec 11 |
|
$ |
5.00 8.95 |
|
|
|
1,435 |
|
Natural Gas |
|
Collar |
|
10,000 Mmbtu |
|
Jan 12 Dec 12 |
|
$ |
5.00 9.82 |
|
|
|
4,301 |
|
Natural Gas |
|
Purchase Put |
|
5,000 Mmbtu |
|
Feb 10 Dec 10 |
|
$ |
5.00 |
|
|
|
19,167 |
|
Natural Gas |
|
Sold Put |
|
5,000 Mmbtu |
|
Feb 10 Dec 10 |
|
$ |
5.00 |
|
|
|
(19,167 |
) |
Natural Gas |
|
Purchased Put |
|
15,000 Mmbtu |
|
Feb 10 Dec 10 |
|
$ |
5.00 |
|
|
|
57,502 |
|
Natural Gas |
|
Sold Put |
|
15,000 Mmbtu |
|
Feb 10 Dec 10 |
|
$ |
5.00 |
|
|
|
(57,502 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,284,550 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the year ended December 31, 2009, we incurred a loss of $2,325,251 related to oil and
natural gas derivative contracts which included $5,374,877 of realized gain related to settled
contracts, and $7,700,128 of unrealized losses related to unsettled contracts. Unrealized gain and
losses are based on the changes in the fair value of derivative instruments covering positions
beyond December 31, 2009.
F-12
NOTE 5 ACQUISITIONS AND DIVESTITURES
On September 14, 2009, we entered into a Purchase and Sale Agreement to acquire for $1.7 million an
additional ownership interest in the Company operated East Chalkley Unit located in Cameron Parish,
Louisiana. The purchase of this interest increased the Companys working interest to approximately
72% in the unit. The transaction closed on October 15, 2009.
On October 23, 2009, we entered into a Purchase and Sale Agreement with another joint interest
owner to divest for $500,000 approximately 10% of the Companys ownership interest in the Pine
Pasture et al. No. 2 well and East Chalkley Prospect Area and approximately 35% of the Companys
ownership interest in the Pine Pasture et al. No. 1 well located in Cameron Parish, Louisiana.
On September 30, 2009, we completed the acquisition of 100% of the capital stock of Sharon
Resources, Inc. (Sharon) whereby we acquired 100% of the outstanding common stock of Sharon in
exchange for 2,294,474 shares of our common stock valued at approximately $2.68 million based on
the closing stock price of $1.17 on the effective date of the closing.
The acquisition of Sharon is accounted for using the acquisition method as set out in FAS ASC 805,
Business Combinations, which requires the assets and liabilities to be recorded at their respective
fair values. The following table summarizes the estimated fair values of the net assets acquired
at September 30, 2009:
|
|
|
|
|
Assets |
|
|
|
|
Cash |
|
$ |
235,023 |
|
Accounts receivable |
|
|
288,125 |
|
Prepaid expenses |
|
|
2,394 |
|
Deposits |
|
|
750 |
|
Oil and gas properties |
|
|
2,972,534 |
|
|
|
|
|
|
Liabilities and equity |
|
|
|
|
Accounts payable |
|
|
(664,080 |
) |
Asset retirement obligation |
|
|
(150,211 |
) |
|
|
|
|
Net assets acquired |
|
$ |
2,684,535 |
|
|
|
|
|
NOTE 6 ASSET RETIREMENT OBLIGATIONS
The Company accounts for asset retirement obligations based on the guidance of ASC 410 which
addresses accounting and reporting for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. ASC 410 requires that the fair value
of a liability for an assets retirement obligation be recorded in the period in which it is
incurred and the corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each period, and the
capitalized cost is depreciated over the estimated useful life of the related asset. We have
included estimated future costs of abandonment and dismantlement in our successful efforts
amortization base and amortize these costs as a component of our depreciation, depletion, and
accretion expense in the accompanying consolidated financial statements.
The following table summarizes the Companys asset retirement obligation transactions during the
years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Asset retirement obligation at beginning of period |
|
$ |
1,589,197 |
|
|
$ |
1,434,114 |
|
Purchased in Sharon Resources acquisition |
|
|
150,211 |
|
|
|
|
|
Liabilities incurred |
|
|
150,822 |
|
|
|
93,154 |
|
Liabilities settled |
|
|
(22,914 |
) |
|
|
(17,012 |
) |
Accretion expense |
|
|
164,990 |
|
|
|
138,772 |
|
Revisions in estimated liabilities |
|
|
|
|
|
|
(59,831 |
) |
|
|
|
|
|
|
|
Asset retirement obligation at end of period |
|
$ |
2,032,306 |
|
|
$ |
1,589,197 |
|
|
|
|
|
|
|
|
F-13
NOTE 7 NOTES PAYABLE
Notes payable at December 31, 2009 and 2008 consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Note payable due February 1, 2010, 4.75% |
|
$ |
44,157 |
|
|
$ |
|
|
Note payable due January 1, 2008, 4.057% |
|
|
|
|
|
|
19,527 |
|
Revolving credit borrowing due September 9, 2011, 5.5% |
|
|
|
|
|
|
6,500,000 |
|
Term loan due September 9, 2012, 10% |
|
|
|
|
|
|
15,000,000 |
|
Senior revolving credit facility due November
23, 2012, 3.255% at December 31, 2009 |
|
|
13,000,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
13,044,157 |
|
|
$ |
21,519,527 |
|
Less: current portion |
|
|
(44,157 |
) |
|
|
(19,527 |
) |
|
|
|
|
|
|
|
Total Long-Term Debt |
|
$ |
13,000,000 |
|
|
$ |
21,500,000 |
|
|
|
|
|
|
|
|
The following table presents the approximate annual maturities of debt:
|
|
|
|
|
2010 |
|
$ |
44,157 |
|
2011 |
|
|
|
|
2012 |
|
|
13,000,000 |
|
2013 |
|
|
|
|
Thereafter |
|
|
|
|
|
|
|
|
|
|
$ |
13,044,157 |
|
|
|
|
|
Notes Payable
On April 1, 2008, we executed a promissory note with a finance company to finance its various
insurance policies. The interest rate on the note is 4.057% with payments of $19,593 per month
beginning May 1, 2008 and the final payment due January 1, 2009. The note is secured by the
insurance policies. At December 31, 2009 and 2008, the balance owing was $0 and $19,527,
respectively.
On April 10, 2009, we executed a promissory note for $217,336 with a finance company to finance its
various insurance policies. The interest rate on the note is 4.75% with payments of $22,210 per
month beginning May 1, 2009 and the final payment due February 1, 2010. The note is secured by the
insurance policies. At December 31, 2009, the outstanding balance on the note was $44,157.
Revolving Credit Borrowing and Term Loan
On September 9, 2008, the Company entered into a new $50 million first lien revolving credit
agreement and a $15 million second lien term loan agreement. The revolving credit agreement
provided for an initial borrowing base availability of $17 million and could be used to provide
working capital for exploration and production purposes, to refinance existing debt, and for
general corporate purposes. The agreement provided for both a prime rate and LIBO rate option and a
maturity date of September 9, 2011. At December 31, 2008, we had outstanding borrowings of $6.5
million under this agreement.
The second lien term loan agreement provided for a $15 million second lien term loan facility. All
term loans available under the second lien term loan facility were advanced to the Company on
September 9, 2008 and were used to refinance existing debt. The maturity date of the Second Lien
Term Loan Agreement was September 9, 2012. Under certain circumstances, the Company was permitted
to repay the term loans prior to the maturity date; however, any payments made on or prior to
September 9, 2009 were subject to a prepayment penalty equal to 2% of the amount prepaid, and any
payments made after September 9, 2009 but on or before September 9, 2010 were subject to a
prepayment penalty equal to 1% of the amount prepaid. The agreement provided for both a prime
rate and LIBO rate option. The amount outstanding under the term loan was $15 million at December
31, 2008.
The Company incurred approximately $1.3 million of deferred financing cost on the above notes and
on September 9 and October 14, 2008, the Company borrowed $6.5 million by drawing down $15 million
on its second lien term loan and $6.5 million on its revolving credit agreement. The Company then
paid off other existing indebtedness of $16.2 million and also
incurred $2.8 million of debt extinguishment costs. The debt extinguishment costs consisted
principally of the write off of the note discount and deferred financing costs.
F-14
The credit agreement was amended effective as of March 25, 2009 because the Company was unable to
comply with the interest and debt coverage covenants under the terms of the original revolving
credit agreement and second lien term loan agreement for the fiscal quarter ended December 31,
2008. Pursuant to the amendments, the administrative agent and the lenders agreed to waive the
defaults. In connection with the semi-annual review of the borrowing base, lower commodity prices
resulted in the borrowing base for the revolving credit agreement being reduced from $17 million to
$12 million.
On November 23, 2009, in connection with the closing of our new Senior Revolving Credit Facility,
the Company terminated its then-existing credit agreement and its second lien term loan agreement
by paying off the outstanding balances of $12 million in revolving credit and $15 million in term
loan with that lender at that time.
Senior Revolving Credit Facility
On November 23, 2009, the Company entered into a new Senior Revolving Credit Agreement which
provided for an asset-based, three-year senior secured revolving credit facility with an initial
borrowing base availability of $25 million. The Revolving Facility is governed by a semi-annually
borrowing base redetermination derived from the Companys proved crude oil and natural gas
reserves, and based on such redeterminations, the borrowing base may be increased up to a maximum
commitment level of $150 million.
The terms of the Credit Agreement provide that the Revolving Facility may be used for loans and,
subject to a $5,000,000 sublimit, letters of credit. The Company used the initial advance under
the Revolving Facility to repay all current borrowings under prior loan facilities. Further
borrowings may be used to provide working capital for exploration, development and production
purposes, to refinance existing debt and for general corporate purposes. A commitment fee, which
ranges between 0.5% and 0.75%, based on the unused portion of the borrowing base under the
Revolving Facility, is also payable by the Company.
Borrowings under the Credit Agreement bear interest, at the Companys option, at either
|
|
an alternate base rate (ABR) equal to the greater of the prime
rates, the federal funds effective rate plus 0.5% or the LIBOR rate
plus 1.0%, plus in each such case an applicable margin ranging from
1.5% to 2.5% depending on borrowing base utilization; or |
|
|
an adjusted LIBOR rate equal to the product of (i) the LIBOR rate
multiplied by (ii) the statutory reserve rate (a fraction of which the
numerator is 1 and the denominator is the aggregate of the maximum
reserve percentages required for Eurocurrency funding), plus in each
case an applicable margin ranging from 2.5% to 3.5% based on borrowing
base utilization. |
If an event of default occurs and is continuing, the lenders may increase the interest rate then in
effect by an additional 2% per annum plus the rate applicable to ABR loans.
The Credit Agreement contains negative covenants that, among others things, restrict the ability of
the Company to, with certain exceptions: (i) incur indebtedness; (ii) grant liens; (iii) make
certain payments; (iv) change the nature of its business; (v) dispose of all or substantially all
of its assets or enter into mergers, consolidations or similar transactions; (vi) make investments,
loans or advances; and (vii) enter into transactions with affiliates. The Credit Agreement also
requires the Company to satisfy certain affirmative financial covenants, including maintaining (a)
an interest coverage ratio (as such term is defined in the Credit Agreement) of not less than
2.5:1.0; (b) a ratio of total debt (as such term is defined in the Credit Agreement) to EBITDAX of
not more than (1) 4.5:1.0 for the fiscal quarters ending December 31, 2009, March 31, 2010 and June
30, 2010 and (2) 4.0:1.0 for each fiscal quarter ending thereafter; and (c) a ratio of consolidated
current assets to consolidated current liabilities of not less than 1.0:1.0. The Company is also
required to enter into certain commodity price hedging agreements pursuant to the terms of the
Credit Agreement.
The obligations of the Company under the Credit Agreement may be accelerated upon the
occurrence of an Event of Default (as such term is defined in the Credit Agreement). Events of
default include customary events for a financing agreement of this type, including, without
limitation, payment defaults, defaults in the performance of affirmative or negative covenants, the
inaccuracy of representations or warranties, bankruptcy or related defaults, defaults relating to
judgments and the occurrence of a Change in Control (as such term is defined in the Credit
Agreement).
F-15
Subject to certain permitted liens, the Companys obligations under the Credit Agreement have been
secured by the grant of a first priority lien on not less than 80% of the value of the Company and
its subsidiaries oil and gas properties until thirty days after the effective date and,
thereafter, 85% of the value of the Company and its subsidiaries existing and to-be-acquired oil
and gas properties.
In connection with the Credit Agreement, the Company and its subsidiaries also entered into certain
customary ancillary agreements and arrangements, which, among other things, provide that the
indebtedness, obligations and liabilities of the borrowers arising under or in connection with the
Credit Agreement are unconditionally guaranteed by the Company and substantially all of its
subsidiaries.
At December 31, 2009, the Company had loans outstanding under this credit agreement of $13 million.
NOTE 8 SHARE BASED COMPENSATION
In March 2006, Magnum Hunter Resources adopted the 2006 Stock Incentive Plan. Under the Plan,
options may be granted to key employees and other persons who contribute to the success of Magnum
Hunter. We originally reserved 1,500,000 shares of common stock for the Plan. In June 2007, we
increased the authorized shares to 3,000,000. No options were exercised during the years ended
December 31, 2008 and 2009.
On January 9, 2008 we granted 200,000 stock options to our President at that time. The options have
an exercise price of $2.00 per share. Fifty thousand options vested on January 9, 2008 and the
remaining 150,000 options vest annually on January 10, 2009, 2010 and 2011. The stock options have
a 5 year term expiring on January 10, 2013. The options were valued using the Black-Sholes model
with the following assumption: $2.15 quoted stock price; $2.00 exercise price; 104.83% volatility;
3.25 year estimated life; zero dividend; 2.69% discount rate. The fair value of these options was
$293,364.
Also, on January 9, 2008 we granted 10,000 stock options to our Director of Information Services.
The options have an exercise price of $2.00 per share. Twenty five hundred options vested on
January 10, 2008 and the remaining 7,500 options will vest annually on January 10, 2009, 2010 and
2011. The stock options have a 5 year term expiring on January 10, 2013. The options were valued
using the Black-Sholes model with the following assumption: $2.15 quoted stock price; $2.00
exercise price; 104.83% volatility; 3.25 year estimated life; zero dividend; 2.69% discount rate.
The fair value of these options was $14,668.
On March 1, 2008 we granted 100,000 stock options to our Chief Operating Officer at that time. The
options have an exercise price of $1.70 per share. Twenty five thousand options vested on March 1,
2008 and the remaining 75,000 options will be issued and will vest annually on March 1, 2009, 2010
and 2011. The stock options have a 5 year term expiring on March 1, 2013. The options were valued
using the Black-Sholes model with the following assumption: $1.70 quoted stock price; $1.70
exercise price; 104% volatility; 3.25 year estimated life; zero dividend; 1.87% discount rate. The
fair value of these options was $112,381.
On January 9, 2008, we granted 100,000 shares of restricted common stock to our President at that
time. These common shares vest at 25,000 immediately and 25,000 each on January 10, 2009, 2010 and
2011. These shares were valued at $2.15 per share, based on the quoted market value on the date of
grant, and $107,500 of expense was recognized as of December 31, 2008. The remaining $107,500 will
be recognized over the remaining service term.
On March 1, 2008 we also granted 130,000 shares of restricted common stock to our Chief Operating
Officer at that time. These common shares vest at 40,000 immediately and the remaining shares vest
annually at 30,000 shares annually on March 1, 2009, 2010 and 2011. These shares were valued at
$1.70 per share, based on the quoted market value on the date of grant, and $119,000 of expense was
recognized as of December 31, 2008. The remaining $102,000 will be recognized over the remaining
service term.
F-16
On May 22, 2009, we granted 4,000,000 stock options to two new executives of the Company. The stock
options have an exercise price of $0.37 per share and expire May 22, 2014. The options vest as
follows: (a) Options to purchase 1,000,000 Shares shall vest and first become exercisable subject
to and upon the Companys acquisition of at least $20 million of additional debt capital, equity
capital, or oil and gas properties, or any combination thereof, whether in one transaction or in a
series of transactions, during the period commencing on the grant date and ending on May 22,
2010. (b) Options to purchase 1,000,000 Shares shall vest and first become exercisable subject to
and upon the Common Stock trading at a price of $0.75 per share (as adjusted for splits,
combinations and the like) for 20 of any 30 consecutive trading days during the period commencing
on the grant date and ending on May 22, 2011. (c) Options to purchase 1,000,000 Shares shall vest
and first become exercisable subject to and upon the Common Stock trading at a price of $1.25 per
share (as adjusted for splits, combinations and the like) for 20 of any 30 consecutive trading days
during the period commencing on the grant date and ending on May 22, 2012. (d) Options to purchase
1,000,000 Shares shall vest and first become exercisable subject to and upon the Company achieving
daily production of 1,400 boe per day during the period commencing on the grant date and ending on
May 22, 2011. The term boe means barrels of crude oil equivalent, determined using the ratio of
six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids. These options
were valued using the Black-Sholes model for the performance and service based options and the
Lattice model for the market based options, which made use of the following primary assumptions:
|
|
|
|
|
|
|
|
Black-Sholes |
|
|
Lattice |
Expected volatility |
|
108 |
% |
|
61.5% to 337% |
Expected dividend yield |
|
0 |
|
|
0 |
Risk free rate |
|
1.39 |
% |
|
0.49% to 2.23% |
The combined fair value of these stock options was determined to be $846,065.
On May 22, 2009, we also granted 4,000,000 shares of Restricted Stock to two new executives of the
Company. The shares of Restricted Stock become vested in the following amounts, at the following
times and upon the following conditions, provided that the employee remains in continuous
employment of the Company through and on the applicable vesting date: (a) 1,500,000 Shares shall
vest on January 1, 2010. (b) 625,000 Shares shall vest subject to and the Companys acquisition of
at least $20 million of additional debt capital, equity capital, or oil and gas properties, or any
combination thereof, whether in one transaction or in a series of transactions, during the period
commencing on the grant date and ending on May 22, 2010. (c) 625,000 Shares shall vest subject to
and upon the Common Stock trading at a price of $0.75 per share (as adjusted for splits,
combinations and the like) for 20 of any 30 consecutive trading days during the period commencing
on the grant date and ending on May 22, 2011. (d) 625,000 Shares shall vest subject to and upon
the Common Stock trading at a price of $1.25 per share (as adjusted for splits, combinations and
the like) for 20 of any 30 consecutive trading days during the period commencing on the grant date
and ending on May 22, 2012. (e) 625,000 Shares shall vest subject to and upon the Companys
satisfaction in full of the performance condition set forth in Section 2(d) of the Option Agreement
on or before May 22, 2011. The Restricted Stock also shall become vested at such earlier times, if
any, as shall be provided in the restricted stock agreement or as shall otherwise be determined by
the Compensation Committee in its sole and absolute discretion. Restricted stocks that contain both
service and performance conditions were valued using the share price at grant date determined to be
$0.35 per share for a total fair value of $962,500. Restricted stocks that contain both service and
market conditions were valued using the Lattice model which made use of the following primary
assumptions:
|
|
|
Expected volatility |
|
189% to 337% |
Expected dividend yield |
|
0 |
Risk free rate |
|
0.49% to 2.23% |
The fair value of these restricted shares was determined to be $287,045.
On June 12, 2009 we granted a total of 172,000 stock options to certain employees. These
stock options have an exercise price of $0.69 per share of which 43,000 vested immediately. The
remaining 129,000 stock options will vest annually on June 12, 2010, 2011 and 2012. The
stock options have a five year term expiring on June 12, 2014. The stock options were valued using
the Black-Sholes model with the following assumption: $0.69 quoted stock price; $0.69 exercise
price; 123.5% volatility; 3.25 year estimated life; zero dividends and a 1.91% discount rate. The
fair value of these options was determined to be $88,122.
On June 12, 2009 we also granted 100,000 shares of restricted common stock to an employee of the
Company, of which 25,000 vested immediately. In connection with this issuance, we recorded $19,365
as compensation expense based on the closing price of our common stock on June 12, 2009. We also
agreed to issue 25,000 additional restricted common shares on June 1, 2010, 2011 and 2012, which
vest immediately upon each respective issuance, for an aggregate of 75,000 shares. Compensation
expense related to these shares is accrued monthly.
F-17
On June 26, 2009, we granted 100,000 stock options each to three board members and 130,000 stock
options each to two board members. The stock options have an exercise price of $0.51 per share. The
stock options fully vested on June 26, 2009, and have a 10 year term expiring June 26, 2019. The
stock options were valued using the Black-Sholes model with the following assumption: $0.51 quoted
stock price; $0.51 exercise price; 124.76% volatility; 5 year estimated life; zero dividends; 2.53%
discount rate. The fair value of these options was determined to be $241,895.
On July 13, 2009, we granted 350,000 shares of stock options to a new officer of the company. The
options were issued at an exercise price of $.57 per share with an estimated fair value of $.24
per share and have a life of 5 years. The options vest as follows: a) 70,000 shall vest on July 13,
2010 provided that the Optionee is employed by the Corporation as of the close of business on July
13, 2010. b) 70,000 options shall vest at any time prior to January 13, 2011 provided that the
Optionee is employed by the Corporation and that the Common Stock of the Corporation has traded at
a daily volume-weighted average price (VWAP) of $1.00 or more for 20 of 30 consecutive trading
days. c) 70,000 options shall vest at any time prior to July 13, 2011 provided that the Optionee is
employed by the Corporation and that at least five (5) new equity research analysts have initiated
research coverage on the Corporation on or after July 13, 2009. d) 70,000 options shall vest at any
such time prior to July 13, 2012 provided that the Optionee is employed by the Corporation and that
the Common Stock of the Corporation has traded at a daily VWAP of $2.00 or more for 20 of 30
consecutive trading days. e) 70,000 options shall vest at any time prior to July 13, 2012 provided
that the Optionee is employed by the Corporation and that the total institutional ownership of the
Corporations Common Stock has increased by an amount equal to or greater than 50% of the fully
diluted outstanding shares on the vesting date in excess of the number of shares held by
institutional owners as of the Corporations June 3, 2009 Proxy Statement. Notwithstanding the
foregoing, in the event of a Change in Control of the Company on or after January 13, 2010, then
all Options shall vest and become immediately exercisable in full and will remain exercisable in
accordance with their terms. These options were valued using the Black Scholes for the service and
performance based options, and Lattice Model for the market based options, which made use of the
following primary assumptions:
|
|
|
|
|
|
|
|
Black-Sholes |
|
|
Lattice |
Expected volatility |
|
110 |
% |
|
48.2% to 434.4% |
Expected dividend yield |
|
0 |
|
|
0 |
Risk free rate |
|
1.41 |
|
|
0.17% to 4.30% |
On August 5, 2009, we granted 68,181 shares of restricted common stock to board members. These
common shares vested immediately and were valued at $0.66 per share, based on the quoted market
value on the date of grant. The expense was recorded in 2009.
On August 17, 2009, we granted 100,000 stock options to a new board member. The stock options have
an exercise price of $1.04 per share. The stock options fully vested on August 17, 2009, and have a
10 year term expiring August 17, 2019. The stock options were valued using the Black-Sholes model
with the following assumption: $1.04 quoted stock price; $1.04 exercise price; 125.49% volatility;
5 year estimated life; zero dividends; 2.43% discount rate. The fair value of these options was
determined to be $88,285.
On September 30, 2009, we granted 600,000 stock options to employees of the company. The options
have an exercise price of $1.17 per share. The options have a life of 5 years of which 150,000
vested immediately and the remaining 450,000 vest in equal amounts over 3 years. The stock options
were valued using the Black-Sholes model with the following assumption: $1.17 quoted stock price;
$1.17 exercise price; 127.48% volatility; 3.25 year estimated life; zero dividends; 1.45% discount
rate. The fair value of these options was determined to be $530,229.
F-18
On October 23, 2009, we granted 250,000 stock options to employees of the Company. The options
have an exercise price of $1.69 per share and have an estimated fair market value of $1.36 per
share. The options have a life of 10 years of which 50,000 vest immediately and the remaining
200,000 options vest upon performance conditions being met, which management estimates to vest on
various dates through 1/1/2011. These options were valued using the Lattice model which made use of
the following primary assumptions:
|
|
|
Expected volatility |
|
112% to 250.44% |
Expected dividend yield |
|
0 |
Risk free rate |
|
2.38% |
On November 15, 2009, we granted 75,000 stock options to employees of the company. The options
have an exercise price of $1.63 per share. The options have a life of 10 years of which 18,750
vested immediately and the remaining 56,250 vest in equal amounts over 3 years. The stock options
were valued using the Black-Sholes model with the following assumption: $1.63 quoted stock price;
$1.63 exercise price; 112.27% volatility; 5 year estimated life; zero dividends; 2.38% discount
rate. The fair value of these options was determined to be $77,205.
We recognized stock compensation expense of $3,091,334 and $1,589,675 for the year ended December
31, 2009 and 2008 respectively.
A summary of option activity for the years ended December 31, 2009 and 2008 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
Weighted Average |
|
|
|
Shares |
|
|
Exercise Price |
|
|
Shares |
|
|
Exercise Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of year |
|
|
1,035,000 |
|
|
$ |
3.11 |
|
|
|
1,125,000 |
|
|
$ |
3.68 |
|
Granted |
|
|
6,107,000 |
|
|
$ |
0.56 |
|
|
|
310,000 |
|
|
$ |
1.90 |
|
Exercised, forfeited, or expired |
|
|
(25,000 |
) |
|
$ |
2.50 |
|
|
|
(400,000 |
) |
|
$ |
3.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of year |
|
|
7,117,000 |
|
|
$ |
0.93 |
|
|
|
1,035,000 |
|
|
$ |
3.11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of year |
|
|
4,776,750 |
|
|
$ |
0.98 |
|
|
|
902,500 |
|
|
$ |
3.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A summary of our non-vested options as of December 31, 2009 and 2008 is presented below.
|
|
|
|
|
|
|
|
|
Non-vested Options |
|
2009 |
|
|
2008 |
|
Non-vested at beginning of year |
|
|
432,500 |
|
|
|
575,000 |
|
Granted |
|
|
6,107,000 |
|
|
|
310,000 |
|
Vested |
|
|
(4,174,250 |
) |
|
|
(352,500 |
) |
Forfeited |
|
|
(25,000 |
) |
|
|
(100,000 |
) |
|
|
|
|
|
|
|
Non-vested at end of year |
|
|
2,340,250 |
|
|
|
432,500 |
|
|
|
|
|
|
|
|
Total unrecognized compensation cost related to non-vested options granted under the Plan was
$815,784 and $309,700 as of December 31, 2009 and 2008, respectively. The unrecognized cost at
December 31, 2009 is expected to be recognized over a weighted-average period of 1.86 years. At
December 31, 2009, the aggregate intrinsic value for options was $0; and the weighted average
remaining contract life was 4.8 years.
F-19
The assumptions used in the fair value method calculation for the year ended December 31, 2009 and
2008 are disclosed in the following table:
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2009 (1) |
|
2008 (1) |
Weighted average value per option granted during the period (2) |
|
0.37 |
|
1.36 |
Assumptions (3): |
|
|
|
|
Stock price volatility |
|
108 263% |
|
104 105% |
Risk free rate of return |
|
1.36 2.53% |
|
1.87 2.69% |
Weighted average expected term |
|
4.23 years |
|
3.25 years |
|
|
|
(1) |
|
Our estimated future forfeiture rate is zero. |
|
(2) |
|
Calculated using the Black-Scholes fair value based method for service
based options and Lattice Model fair value based method for
performance and market based options. |
|
(3) |
|
The Company does not pay dividends on our common stock. |
A summary of the Companys non-vested shares as of December 31, 2009 and 2008 is presented
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Non-vested Shares |
|
Shares |
|
|
Price Per Share |
|
|
Shares |
|
|
Price Per Share |
|
Non-vested at beginning of year |
|
|
215,000 |
|
|
$ |
2.04 |
|
|
|
75,000 |
|
|
$ |
2.50 |
|
Granted |
|
|
4,168,181 |
|
|
$ |
0.33 |
|
|
|
240,000 |
|
|
$ |
1.90 |
|
Vested |
|
|
(2,048,181 |
) |
|
$ |
0.43 |
|
|
|
(100,000 |
) |
|
$ |
2.04 |
|
Forfeited |
|
|
(25,000 |
) |
|
$ |
2.50 |
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested at end of year |
|
|
2,310,000 |
|
|
$ |
0.44 |
|
|
|
215,000 |
|
|
$ |
2.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrecognized compensation cost related to the above non-vested shares amounted to $196,561
and $237,432 as of December 30, 2009 and 2008 respectively. The unrecognized cost at December 30,
2009 is expected to be recognized over a weighted-average period of 1.08 years.
NOTE 9 SHAREHOLDERS EQUITY
Common Stock
During the years ended December 31, 2009 and 2008, the Company issued 1,886,200 and 100,000 shares,
respectively, of the Companys common stock in correlation with noncash stock compensation which
had fully vested.
On September 30, 2009, Magnum Hunter Resources Corporation issued 2,294,474 shares of the Companys
common stock valued at approximately $2.68 million based on the closing stock price of $1.17 as
consideration for the acquisition of 100% of the outstanding common stock of Sharon Resources, Inc.
On November 5, 2009, the Company sold, for gross proceeds of approximately $3.8 million, an
aggregate of 2.3 million shares of the Companys common stock, together with one fifth of a warrant
to purchase one share of the Companys common stock for each share of common stock purchased. Each
warrant issued to a purchaser will (i) be exercisable for one share of the Companys common stock
at any time after the shares of common stock underlying the warrant are registered with the SEC for
resale pursuant to an effective registration statement, (ii) have a cash exercise price of $2.50
per share of the Companys common stock, and (iii) upon notice to the holder of the warrant, be
redeemable by the Company for $0.01 per share of the Companys common stock underlying the warrant
if (a) the Registration Statement as filed with the SEC is effective and (b) the average trading
price of the Companys common stock as traded and quoted on the NYSE Amex equals or exceeds $3.75
per share for at least 20 days in any period of 30 consecutive days. The Companys common stock
purchased in this transaction was issued pursuant to a prospectus supplement filed with the SEC in
connection with a takedown from the Companys existing $100 million universal shelf registration
statement on Form S-3, which became effective on October 15, 2009. Purchasers of this issuance of
common shares by the Company included, amongst others, the Companys Chairman, Vice Chairman,
Executive Vice President and Chief Financial Officer, and three other members of the Companys
Board of Directors.
F-20
On November 6, 2009, the Company issued 601,652 shares of common stock valued at $1.1 million as a
deposit on the Triad acquisition. The terms of the purchase agreement requires Magnum to add
additional shares to the deposit as required to maintain the fair market value of the common stock
placed on deposit at a minimum value of $1.1 million. On November 20, 2009 and December 22, 2009,
the Company issued 60,000 and 100,000 shares, respectively, to maintain the deposit balance as
required. All shares on deposit were returned to the Company on February 23, 2010 and are now
treasury shares. See Note 14 Subsequent events for additional information.
On November 16, 2009, the Company sold 6,403,720 units, with each unit consisting of one of the
Companys common shares and a one fifth of a warrant to purchase one common share, for gross
proceeds of approximately $11.08 million, before deducting placement agent fees and estimated
offering expenses, in a registered direct offering. The investors purchased the units at a
purchase price of $1.73 per unit. The warrants, which represent the right to acquire an aggregate
of up to 1,280,744 common shares, will be exercisable at any time on or after May 17, 2010 and
prior to the 3-year anniversary of the closing of the transaction at an exercise price of $2.50 per
share, which was 132% of the closing price of the Companys common shares on the NYSE AMEX on
November 10, 2009. The new equity capital raised in this offering satisfies the Companys minimum
equity commitment required under the terms of the Asset Purchase Agreement in connection with the
acquisition of Triad Energy Corporation which closed February 12, 2010. See Note 14 Subsequent
events for additional information.
The Company issued 187,482 shares of common stock in November 2009 at an average price of $1.76 per
share pursuant to the At the Market sales agreement we have with Wm Smith & Co., our exclusive
sales manager. Sales of shares of our common stock, by Wm. Smith & Co. will be made in privately
negotiated transactions or in any method permitted by law deemed to be an at the market offering
as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, at negotiated
prices, at prices prevailing at the time of sale or at prices related to such prevailing market
prices, including sales made directly on the American Stock Exchange or sales made through a market
maker other than on an exchange. Wm. Smith & Co. will make all sales using commercially reasonable
efforts consistent with its normal sales and trading practices on mutually agreed upon terms
between Wm. Smith & Co. and us.
Series A Convertible Preferred Stock
On September 26, 2008, the Company redeemed 2,563,712 shares of the Companys outstanding Series A
Preferred Stock at an aggregate redemption price of $7,966,735. The shares were held by investment
funds managed by Touradji Capital Management. Pursuant to the terms of the Preferred Stock Purchase
Agreement, the Company was required to redeem all Series A Preferred Stock no later than October 2,
2008. After giving effect to the redemption, there are no shares of Series A Preferred Stock
outstanding at December 31, 2008.
Series C Preferred Stock
On December 13, 2009 the Company sold 214,950 shares of our 10.25% Series C Cumulative Perpetual
Preferred Stock, par value $0.01 per share and liquidation preference $25.00 per share (the
Series C Preferred Stock ) for net proceeds of $5.1 million. The Series C Preferred Stock cannot
be converted into common stock of the Company, but may be redeemed by the Company, at the Companys
option, on or after December 14, 2011 for $25.00 per share. In the event of a change of control of
the Company, the Series C Preferred Stock will be redeemable by the holders at $26.00 per share
during the first twelve months after December 14, 2009, $25.50 during the second twelve months
after December 14, 2009, and $25.00 thereafter, except in certain circumstances when the acquirer
is considered a qualifying public company. The Company will pay cumulative dividends on the Series
C Preferred Stock at a fixed rate of 10.25% per annum of the $25.00 per share liquidation
preference. For the years ended December 31, 2009 and 2008 we have accrued dividends of $25,654
and $0, respectively. Because redemption is potentially outside the control of the Company, the
Series C Preferred Stock is recorded outside of permanent shareholders equity.
F-21
Noncontrolling Interests
In connection with the Williston Basin acquisition in 2008, the Company entered into equity
participation agreements with the lenders pursuant to which the Company agreed to pay to the
lenders an aggregate of 12.5% of all distributions paid to the owners of PRC Williston, which at
this time is majority owned by Magnum Hunter Resources. The equity participation agreements were
valued at $3,401,655 and accounted for as a noncontrolling interest in PRC Williston.
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Noncontrolling interest at beginning of period |
|
$ |
1,384,909 |
|
|
$ |
3,025,375 |
|
Loss to noncontrolling interest |
|
$ |
(63,156 |
) |
|
$ |
(1,640,466 |
) |
|
|
|
|
|
|
|
Noncontrolling interest at end of period |
|
$ |
1,321,753 |
|
|
$ |
1,384,909 |
|
|
|
|
|
|
|
|
Common Stock Warrants
In association with common stock sales on November 5, 2009, the Company issued 457,982 common stock
warrants. Each warrant issued to a purchaser has a term of 3 years and (i) is exercisable for one
share of the Companys common stock at any time after the shares of common stock underlying the
warrant are registered with the SEC for resale pursuant to an effective registration statement,
which will be June 12, 2010, (ii) has a cash exercise price of $2.50 per share of the Companys
common stock, and (iii) upon notice to the holder of the warrant, is redeemable by the Company for
$0.01 per share of the Companys common stock underlying the warrant if (a) the Registration
Statement as filed with the SEC is effective and (b) the average trading price of the Companys
common stock as traded and quoted on the NYSE Amex equals or exceeds $3.75 per share for at least
20 days in any period of 30 consecutive days.
On November 16, 2009, the Company issued 1,280,744 common stock warrants. The warrants, which
represent the right to acquire an aggregate of up to 1,280,744 common shares, will be exercisable
at any time on or after May 17, 2010 and have a term of 3 years, at an exercise price of $2.50 per
share, which was 145% of the closing price of the Companys common shares on the NYSE AMEX on
November 11, 2009.
A summary of warrant activity for the years ended December 31, 2009 and 2008 is presented
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
Weighted-Average |
|
|
|
|
|
|
Weighted-Average |
|
|
|
Shares |
|
|
Exercise Price |
|
|
Shares |
|
|
Exercise Price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at beginning of year |
|
|
6,838,962 |
|
|
$ |
2.15 |
|
|
|
6,838,962 |
|
|
$ |
2.15 |
|
Granted |
|
|
1,738,726 |
|
|
$ |
2.50 |
|
|
|
|
|
|
$ |
|
|
Exercised, forfeited, or expired |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of year |
|
|
8,577,688 |
|
|
$ |
2.22 |
|
|
|
6,838,962 |
|
|
$ |
2.15 |
|
Exercisable at end of year |
|
|
6,838,962 |
|
|
$ |
2.15 |
|
|
|
6,838,962 |
|
|
$ |
2.15 |
|
At December 31, 2009, the aggregate intrinsic value for warrants was $0; and the weighted average
remaining contract life was 1.58 years.
NOTE 10 INCOME TAXES
At December 31, 2009, we had available for U.S. federal income tax reporting purposes, a net
operating loss (NOL) carry forward for regular tax purposes of approximately $45 million which
expires in varying amounts during the tax years 2025 through 2029. We also have approximately $1
million of depletion carryover which has no expiration. Approximately $5 million of our NOL
relates to the 2009 acquisition of Sharon Resources Inc. and the utilization of that portion of the
NOL is limited on an annual basis. No provision for federal income tax expense or benefit is
reflected on the statement of operations for the years ended December 31, 2009 and 2008 because we
are uncertain as to our ability to utilize our NOL in the future.
The following is a reconciliation of the reported amount of income tax expense (benefit) for the
years ended December 31, 2009 and 2008 to the amount of income tax expense that would result from
applying domestic federal statutory tax rates to pretax income:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
(in thousands) |
|
Statutory tax expense (benefit) |
|
$ |
(5,142 |
) |
|
$ |
(2,341 |
) |
Effect of permanent differences |
|
|
6 |
|
|
|
544 |
|
Change in valuation allowance |
|
|
5,136 |
|
|
|
1,797 |
|
|
|
|
|
|
|
|
Total Tax Expense |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
F-22
The components of our deferred income taxes were as follows for the years ended December 31, 2009
and 2008:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
(in thousands) |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Net operating loss carryforwards |
|
$ |
15,302 |
|
|
$ |
10,551 |
|
Asset retirement obligations |
|
|
691 |
|
|
|
540 |
|
Share based compensation |
|
|
2,412 |
|
|
|
1,397 |
|
Depletion carry forwards |
|
|
455 |
|
|
|
|
|
Deferred tax liability: |
|
|
|
|
|
|
|
|
Property and equipment |
|
|
(2,593 |
) |
|
|
(4,992 |
) |
|
|
|
|
|
|
|
Net deferred tax assets |
|
|
16,267 |
|
|
|
7,496 |
|
Valuation allowances |
|
|
(16,267 |
) |
|
|
(7,496 |
) |
|
|
|
|
|
|
|
Net deferred tax |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
The tax years 2006-2009 remain open to examination for federal income tax purposes and by the other
major taxing jurisdictions to which we are subject. The tax years 2005-2009 remain open for the
Texas Franchise tax.
NOTE 11 OTHER INFORMATION
Quarterly Data (Unaudited)
The following tables set forth unaudited summary financial results on a quarterly basis for the two
most recent years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended |
|
|
Total |
|
|
|
March 31 |
|
|
June 30 |
|
|
September 30 |
|
|
December 31 |
|
|
Year |
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue |
|
$ |
1,917,036 |
|
|
$ |
2,528,891 |
|
|
$ |
2,320,514 |
|
|
$ |
3,505,260 |
|
|
$ |
10,271,701 |
|
Loss from operations |
|
|
(1,476,141 |
) |
|
|
(1,007,912 |
) |
|
|
(2,569,806 |
) |
|
|
(4,472,868 |
) |
|
|
(9,526,727 |
) |
Net loss attributable to common shareholders |
|
|
(1,371,283 |
) |
|
|
(3,393,576 |
) |
|
|
(3,052,222 |
) |
|
|
(7,332,782 |
) |
|
|
(15,149,863 |
) |
Basic and diluted loss per common share |
|
$ |
(0.04 |
) |
|
$ |
(0.09 |
) |
|
$ |
(0.08 |
) |
|
$ |
(0.18 |
) |
|
$ |
(0.39 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue |
|
$ |
3,158,001 |
|
|
$ |
4,368,442 |
|
|
$ |
5,964,896 |
|
|
$ |
2,392,102 |
|
|
$ |
15,883,441 |
|
Income (loss) from operations |
|
|
(455,522 |
) |
|
|
1,477,730 |
|
|
|
757,021 |
|
|
|
(12,243,529 |
) |
|
|
(10,464,300 |
) |
Net loss attributable to common shareholders |
|
|
(1,634,205 |
) |
|
|
(1,882,826 |
) |
|
|
(535,538 |
) |
|
|
(3,568,171 |
) |
|
|
(7,620,740 |
) |
Basic and diluted loss per common share |
|
$ |
(0.04 |
) |
|
$ |
(0.05 |
) |
|
$ |
(0.01 |
) |
|
$ |
(0.10 |
) |
|
$ |
(0.21 |
) |
Supplemental Oil and Gas Disclosures (Unaudited)
The following table sets forth the capitalized costs and associated accumulated depreciation,
depletion and amortization, including impairments, related to Magnum Hunters oil and gas
production, exploration and development activities:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Unproved oil and gas properties |
|
$ |
12,490,362 |
|
|
$ |
18,562,932 |
|
Proved oil and gas properties |
|
|
59,896,627 |
|
|
|
39,414,361 |
|
|
|
|
|
|
|
|
|
|
|
72,386,989 |
|
|
|
57,977,293 |
|
Accumulated depletion, depreciation and impairment |
|
|
(16,503,939 |
) |
|
|
(12,149,571 |
) |
|
|
|
|
|
|
|
|
|
$ |
55,883,050 |
|
|
$ |
45,827,722 |
|
|
|
|
|
|
|
|
F-23
The following table sets forth the costs incurred in oil and gas property acquisition, exploration,
and development activities.
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Purchase of non-producing leases |
|
$ |
2,602,387 |
|
|
$ |
1,410,023 |
|
Purchase of producing properties |
|
|
3,288,174 |
|
|
|
|
|
Exploration costs |
|
|
3,794,254 |
|
|
|
5,796,608 |
|
Development costs |
|
|
6,798,142 |
|
|
|
11,607,005 |
|
Asset retirement obligation |
|
|
278,119 |
|
|
|
93,153 |
|
|
|
|
|
|
|
|
|
|
$ |
16,716,076 |
|
|
$ |
18,906,789 |
|
|
|
|
|
|
|
|
Oil and Gas Reserve Information
Proved oil and gas reserve quantities are based on estimates prepared by Cawley, Gillespie &
Associates, Inc. and DeGolyer & MacNaughton, Magnum Hunters third party reservoir engineering
firms. There are numerous uncertainties inherent in estimating quantities of proved reserves and
projecting future rates of production and timing of development expenditures. The following reserve
data only represent estimates and should not be construed as being exact.
Total Proved Reserves
|
|
|
|
|
|
|
|
|
|
|
Crude oil and Condensate |
|
|
Natural Gas |
|
|
|
(Mbbl) |
|
|
(Mcf) |
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007 |
|
|
2,369.7 |
|
|
|
2,082.0 |
|
Extensions, discoveries and other additions |
|
|
698.0 |
|
|
|
2,655.9 |
|
Revisions of previous estimates |
|
|
(506.6 |
) |
|
|
(143.8 |
) |
Production |
|
|
(151.8 |
) |
|
|
(341.1 |
) |
Balance December 31, 2008 |
|
|
2,409.3 |
|
|
|
4,253.0 |
|
Extensions, discoveries and other additions |
|
|
982.3 |
|
|
|
2,087.3 |
|
Revisions of previous estimates |
|
|
1,330.2 |
|
|
|
34.2 |
|
Purchases of reserves in place |
|
|
83.4 |
|
|
|
3,468.0 |
|
Sales of reserves in place |
|
|
(16.4 |
) |
|
|
(20.5 |
) |
Production |
|
|
(180.3 |
) |
|
|
(457.7 |
) |
|
|
|
|
|
|
|
Balance December 31, 2009 |
|
|
4,608.5 |
|
|
|
9,364.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed reserves, included above |
|
|
|
|
|
|
|
|
December 31, 2008 |
|
|
1,394.3 |
|
|
|
2,549.5 |
|
December 31, 2009 |
|
|
2,055.3 |
|
|
|
4,952.5 |
|
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
The standardized measure of discounted future net cash flows relating to proved oil and natural gas
reserves and the changes in standardized measure of discounted future net cash flows relating to
proved oil and natural gas reserves were prepared in accordance with then current provisions of ASC
932 and SFAS 69. Future cash inflows at December 31, 2009 were computed by applying the unweighted,
arithmetic average on the closing price on the first day of each month for the 12-month period
prior to December 31, 2009, to estimated future production. Future cash inflows at December 31, 2008 were
computed using prices in existence at that date. Future production and development costs are
computed by estimating the expenditures to be incurred in developing and producing the proved oil
and natural gas reserves at year-end, based on year-end costs and assuming continuation of existing
economic conditions.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future
pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of
properties involved.
Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards
relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate
of 10% annually to derive the standardized measure of
discounted future net cash flows. This calculation procedure does not necessarily result in an
estimate of the fair market value of our oil and natural gas properties.
F-24
The standardized measure of discounted future net cash flows relating to proved oil and natural gas
reserves are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
Future cash flows |
|
$ |
262,758 |
|
|
$ |
109,100 |
|
Future production costs |
|
|
(93,078 |
) |
|
|
(48,972 |
) |
Future development costs |
|
|
(33,245 |
) |
|
|
(15,342 |
) |
Future income tax expense |
|
|
(30,858 |
) |
|
|
(11,541 |
) |
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
|
105,577 |
|
|
|
33,245 |
|
10% annual discount for estimated timing of cash flows |
|
|
(58,189 |
) |
|
|
(17,624 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
47,388 |
|
|
$ |
15,621 |
|
|
|
|
|
|
|
|
Future cash flows as shown above were reported without consideration for the effects of commodity
derivative transactions outstanding at each period end.
Changes in Standardized Measure of Discounted Future Net Cash Flows
The changes in the standardized measure of discounted future net cash flows relating to proved oil
and natural gas reserves are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Years Ended |
|
|
|
2009 |
|
|
2008 |
|
|
Balance, beginning of period |
|
$ |
15,621 |
|
|
$ |
40,112 |
|
Net change in sales and transfer prices and in production
(lifting) costs related to future production |
|
|
12,387 |
|
|
|
(35,731 |
) |
Changes in estimated future development costs |
|
|
(18,755 |
) |
|
|
(9,458 |
) |
Sales and transfers of oil and gas produced during the period |
|
|
(4,757 |
) |
|
|
(9,107 |
) |
Net change due to extensions, discoveries and improved recovery |
|
|
17,578 |
|
|
|
10,334 |
|
Net change due to revisions in quantity estimates |
|
|
17,654 |
|
|
|
(4,807 |
) |
Previously estimated development costs incurred during the period |
|
|
6,798 |
|
|
|
8,738 |
|
Accretion of discount |
|
|
2,614 |
|
|
|
4,011 |
|
Purchase of minerals in place |
|
|
8,739 |
|
|
|
|
|
Sale of minerals in place |
|
|
(262 |
) |
|
|
|
|
Other |
|
|
(3,609 |
) |
|
|
|
|
Net change in income taxes |
|
|
(6,623 |
) |
|
|
11,529 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
47,385 |
|
|
$ |
15,621 |
|
|
|
|
|
|
|
|
F-25
The commodity prices in effect at December 31, 2009 and 2008 inclusive of adjustments for quality
and location used in determining future net revenues related to the standardized measure
calculation are as follows. The commodity prices used for December 31, 2009 were computed by
applying the unweighted, arithmetic average on the closing price on the first day of each month for
the 12-month period prior to December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
Oil (per Bbl) |
|
$ |
54.96 |
|
|
$ |
40.33 |
|
Natural gas liquids (per Bbl) |
|
$ |
27.20 |
|
|
$ |
23.00 |
|
Gas (per Mcf) |
|
$ |
3.35 |
|
|
$ |
5.04 |
|
NOTE 12 RELATED PARTY TRANSACTIONS
During 2009, we rented an airplane for business use at various times from Pilatus Hunter, LLC, an
entity 100% owned by Mr. Evans. Airplane rental expenses totaled $161 thousand and $0 for the year
ended December 31, 2009 and 2008, respectively.
During 2009, we obtained accounting services from GreenHunter Energy, Inc., an entity for which Mr.
Evans is an officer and major shareholder. Professional services expenses totaled $30 thousand and
$0 for the year ended December 31, 2009 and 2008, respectively.
NOTE 13 COMMITMENTS AND CONTINGENCIES
Accumulated Production Floor Payments
On February 16, 2007, the Company acquired from Eagle Operating, Inc. an interest in 15 producing
oil fields located in the Williston Basin of North Dakota. For a period of thirty-six months
following the acquisition date, Eagle Operating has guaranteed that PRC Willistons share of gross
monthly production revenue from the properties will not be less than the financial equivalent
of 300 barrels of oil per day multiplied by the number of days in a given month (the product
referred to as the production floor). In the event that our net share of gross production for any
month is less than the production floor, Eagle Operating is obligated to pay to Magnum Hunter
Resources, in cash, an amount equal to the difference between the production floor and the actual
net barrels to our interest multiplied by the average price of crude oil paid for the oil
production from the properties for that month (the production floor payment). During the
thirty-six month period, for any month in which our net share of oil production exceeds the
production floor, Eagle Operating shall be entitled to recover a portion of the production floor
payments previously made to us, also in the form of a cash payment, not to exceed the amount by
which our net share of oil production exceeds the production floor for such month (a production
floor reimbursement). At the end of the thirty-six month period, the Company is obligated to repay
to Eagle Operating, in cash, the amount of cumulative production floor payments, net of any
production floor reimbursements. At December 31, 2009 and 2008, there were no amounts due related
to the production floor payments.
Payable on Sale of Partnership
On September 26, 2008, the Company sold its 5.33% limited partner interest in Hall-Houston
Exploration II, L. P. pursuant to a Partnership Interest Purchase Agreement dated September 26,
2008, as amended on September 29, 2008. The interest was purchased by a non-affiliated partnership
for a cash consideration of $8.0 million and the purchasers assumption of the first $1,353,000 of
capital calls subsequent to September 26, 2008. The Company agreed to reimburse the purchaser for
up to $754,255 of capital calls in excess of the first $1,353,000. The Companys net gain on the
sale of the asset is subject to future upward adjustment to the extent that some or all of the
$754,255 is not called. The liability as of December 31, 2009 and 2008 was $640,695 and $754,255,
respectively.
Operational Contingencies
The exploration, development and production of oil and gas assets are subject to various, federal
and state laws and regulations designed to protect the environment. Compliance with these
regulations is part of our day-to-day operating procedures. Infrequently, accidental discharge of
such materials as oil, natural gas or drilling fluids can occur and such accidents can require
material expenditures to correct. We maintain levels of insurance we believe to be customary in the
industry to limit its financial exposure. We are unaware of any material capital expenditures
required for environmental control during this fiscal year.
In February 2007, we signed a five-year lease for approximately 2,900 square feet of office space
in Houston, Texas. In February 2009, we expanded our office space by signing a three-year lease
for approximately 3,200 square feet of additional office space. On September 30, 2009 we acquired
Sharon Resources along with its 29 month commitment to rent 6,000 square feet of office space in
Houston, Texas. In November, we expanded our office space under an amendment to the lease by
approximately 1,600 square feet. Our rent payments are approximately $23,600 per month, including
common area expenses.
F-26
We have outstanding employment agreements with six of our senior and executive officers for terms
ranging from one to three years. Our maximum commitment under the employment agreements, which
would apply if the employees covered by these agreements were all terminated without cause, was
approximately $1.1 million at December 31, 2009.
NOTE 14 SUBSEQUENT EVENTS
We have sold an additional 5,771,929 shares of common stock for net proceeds of $13.1 million,
pursuant to the At the Market sales agreement we have with Wm Smith & Co., our exclusive sales
manager, subsequent to December 31, 2009 through the date of this report.
On January 6, 2010 we filed a prospectus supplement under our existing shelf registration statement
relating to the issuance and sale of an additional $9,626,250 of our Series C Preferred Stock from
time-to-time through Wm. Smith & Co., as our exclusive sales manager. Sales of shares of our
Series C Preferred Stock, if any, by Wm. Smith & Co. will be made in privately negotiated
transactions or in any method permitted by law deemed to be an At The Market offering as defined
in Rule 415 promulgated under the Securities Act of 1933, as amended, at negotiated prices, at
prices prevailing at the time of sale or at prices related to such prevailing market prices,
including sales made directly on the NYSE Amex or sales made through a market maker other than on
an exchange. Wm. Smith & Co. will make all sales using commercially reasonable efforts consistent
with its normal sales and trading practices on mutually agreed upon terms between Wm. Smith & Co.
and us. Under the terms of the sales agreement, Wm. Smith & Co. will be compensated as follows:
(i) in an amount up to 2% of the gross proceeds from the sales of shares of Series C Preferred
Stock if the sales price is less than $25.00 per share, and (ii) in an amount up to 3% of the gross
proceeds from the sales of shares of Series C Preferred Stock if the sales price is equal to or
greater than $25.00 per share. Our Series C Preferred Stock is listed on the NYSE Amex under the
symbol MHR.PR.C. To date, we have used net proceeds received from this offering to reduce
indebtedness, to fund the Triad acquisition and to fund our lease acquisition efforts and fund our
drilling programs. We will use the remaining proceeds and additional proceeds for the repayment of
indebtedness under the Restated Credit Facility described below, and to the extent permitted
thereunder, for general corporate purposes. We have sold 145,292 shares of Series C Preferred
Stock for net proceeds of $3.5 million subsequent to December 31, 2009 through the date of this
report.
On February 3, 2010, the Company granted 30,869 shares of restricted stock to Board Members for
payment of services rendered.
During February 2010, the Company granted 1.3 million shares of common stock options to existing
employees and 412,500 to new employees.
On February 12, 2010, the Company closed the acquisition of privately-held Triad Energy Corporation
and affiliates (collectively, Triad), an Appalachian Basin focused energy company, through a
bankruptcy proceeding. We acquired substantially all of the assets of Triad and certain of its
affiliated entities which primarily consisted of oil and gas property interests in approximately
2,000 operated wells and include over 88,000 net mineral acres located in the states of Kentucky,
Ohio, and West Virginia, a natural gas pipeline (Eureka Hunter Pipeline), two salt water disposal
facilities, three drilling rigs, workover rigs, and other oilfield equipment. Triad, headquartered
in Reno, Ohio, was an oil and natural gas exploration and production company focused exclusively in
the Appalachian Basin with operations in Ohio, West Virginia and Kentucky. Triad had additional
business units including oilfield services, commercial salt water disposal facilities and midstream
resources. These assets are now held by the Companys wholly-owned subsidiaries, Triad Hunter, LLC,
Alpha Hunter Drilling, LLC, Disposal Hunter, LLC, and Eureka Hunter Pipeline, LLC.
As consideration for the acquisition of the oil and gas assets, we paid a total of approximately
$81 million consisting of:
|
|
$8 million in cash ($4 million net of cash on hand at Triad); |
|
|
|
$15 million of our Series B Redeemable Convertible Preferred Stock, issued to Allied Irish
Banks, P.L.C., Capital One, N.A., and Citibank N.A., who were secured creditors of Triad in
its Chapter 11 proceedings; |
|
|
|
$55 million repayment of Triad senior debt via drawing under the new Revolving Credit
Facility discussed below; and |
|
|
|
Assumption of approximately $3 million of equipment indebtedness |
|
|
|
The fair value of the consideration approximated its $81 million face value |
F-27
The fair value of the net assets acquired approximated the $81 million in consideration paid.
We are in the process of determining the purchase price allocation to the assets acquired and the
liabilities assumed. We have not disclosed the proforma results of revenue and earnings of the
combined company for 2009 and 2008 as if the acquisition had occurred on January 1, 2008 because
the amounts have not yet been determined.
Because Triad and certain of its affiliated entities had been operating under Chapter 11 of the
Federal Bankruptcy Code since December 2008, the acquisition agreement did not include customary
indemnification provisions, but did contain closing conditions and representations and warranties
that are typical for a transaction of this nature.
In connection with the Triad Acquisition and pursuant to the Bankruptcy Order on February 12, 2010,
we issued in the aggregate 4,000,000 shares of our Series B Preferred Stock, with an aggregate
liquidation preference of $15 million to the secured creditors of the bankrupt Triad entities as
partial consideration for the Triad Acquisition. These holders of Series B Preferred were secured
creditors of Triad in its Chapter 11 bankruptcy proceeding and the Series B Preferred was issued to
them in partial satisfaction of their secured claims against Triad. The Series B Preferred Stock
is senior to the Companys common stock and to the Companys 10.25% Series C Cumulative Perpetual
Preferred Stock. Pursuant to the Certificate of Designation for the Preferred Stock (the
Certificate of Designation), the Preferred Stock is entitled to dividends at a rate of 2.75% per
annum payable quarterly (i) in shares of Series B Preferred Stock or (ii) subject to the receipt of
any required consent under the Companys senior credit facility, in cash. In addition, the Series B
Preferred Stock has a liquidation preference equal to the greater of (i) $3.75 per share, plus
accrued and unpaid dividends, or (ii) the amount payable per share of common stock which the holder
of Series B Preferred Stock would have received if such Series B Preferred Shares had been
converted to common shares immediately prior to the liquidation event, plus accrued and unpaid
dividends. At any time prior to the twentieth anniversary of the original issuance of Series B
Preferred Stock, the holders of shares of Series B Preferred Stock may convert any or all of their
Series B Preferred Stock into shares of the Companys common stock at a conversion ratio of one
share of Series B Preferred Stock to one share of common stock, subject to certain adjustments. At
any time following the second anniversary of the original issuance of Series B Preferred and prior
to the twentieth anniversary of such original issuance, the holders of shares of Series B Preferred
stock may tender their shares for redemption to the Company for a redemption price of $3.75 per
Series B share, as adjusted. In addition, the Company may redeem the Series B Preferred Stock at a
price of $3.75 per share, plus accrued and unpaid dividends, (a) at any time following February 12,
2012, or (b) if the average trading price of the Common Stock equals or exceeds $4.74 per common
share, as adjusted, for five consecutive trading days.
On February 12, 2010 we entered into an amended and restated credit agreement with Bank of Montreal
and Capital One, N.A. This restated credit agreement amended and restated in its entirety the
credit facility dated November 23, 2009. The restated credit agreement provides for an asset-based,
senior secured revolving credit facility (the Revolving Facility) maturing November 23, 2010,
with an initial borrowing base of $70 million. The revolving facility is governed by a semi-annual
borrowing base redetermination (on April 1 and November 1 of each year) derived from the Companys
proved crude oil and natural gas reserves, and based on such redetermination, the borrowing base
may be decreased or increased up to a maximum commitment level of $150 million. The initial $70
million borrowing base consists of a $60 million A tranche and a $10 million B tranche.
Borrowings under the $10 million tranche must be reduced to an amount less than or equal to $9
million, $7 million, and $4 million on the three, six and nine month anniversaries, respectively,
of the execution of the restated credit agreement. Such $10 million tranche will terminate entirely
on the first anniversary of the restated credit agreement. Subject to certain exceptions, any
equity raised by the Company through a fully marketed offering must be used to repay this $10
million tranche. As of March 1, 2010, we have reduced our borrowings under the B Tranche to $9
million. The restated credit agreement has a commitment fee which ranges between 0.50% and 0.75%,
based upon the unused portion of the borrowing base. Borrowings under the revolving facility will,
at the Companys election bear interest at either (i) an alternate base rate (ABR) equal to the
higher of (A) Bank of Montreals base rate, (B) the Federal Funds Effective Rate, plus 0.5% per
annum and the (C) the LIBO Rate for a one month interest period on such day, plus 1.0% or (ii) the
adjusted LIBO rate, which is the rate stated on Reuters BBA Libor Rates C2BORO1 market for one,
two, three, six or twelve months, as adjusted for statutory reserve requirements for Eurocurrency
liabilities, plus, in each of the cases described in (i) or (ii) above, an applicable margin
ranging from 3.50% to 6.50% for ABR loans and from 4.50% to 7.50% for adjusted LIBO Rate loans
until the earlier of the repayment of the $10 million tranche or the first anniversary and
thereafter an applicable margin ranging from 1.50% to 2.50% for ABR loans and from 2.50% to 3.50%
for adjusted LIBO Rate loans. In the event a default occurs and is continuing under the restated
credit agreement, the lenders may increase the interest rate then in effect by an additional 2% per
annum plus the rate then applicable to ABR loans. Subject to certain permitted liens, the Companys
obligations under the restated credit agreement are secured by a grant of a first priority lien on
no less than 80% of the value of the proved oil and gas properties of the Company and its
subsidiaries, including 90% of the total value of the oil and gas properties of the
Company and its subsidiaries that are categorized as Proved Reserves that are both Developed
and Producing as such terms are defined in the Definitions for Oil and Gas Reserves as
promulgated by the Society of Petroleum Engineers. The Company used the initial advance under the
revolving facility to finance the Triad acquisition.
On February 23, 2010, a total of 761,652 shares of common stock with a carrying value of
$1,310,357, which were previously issued as deposit on the Triad acquisition, were returned to the
Company and are now held as treasury shares.
F-28
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
On October 13, 2009, Magnum Hunter Resources Corporation (the Company) notified its independent
accountant, Malone & Bailey PC, of its dismissal as principal auditors of the Company after
completion of its SAS 100 review for the third quarter ended September 30, 2009.
Effective October 13, 2009, the Company has engaged Hein & Associates LLP to audit the Companys
consolidated financial statements for the year ending December 31, 2009. The change was the
result of a proposal and competitive bidding process involving several accounting firms. The
decision to dismiss Malone & Bailey PC and to retain Hein & Associates LLP was recommended by the
Audit Committee of the Companys Board of Directors and approved by the Board of Directors.
The audit reports of Malone & Bailey PC on the consolidated financial statements of the
Company as of and for the years ended December 31, 2008, and 2007, did not contain any
adverse opinion or disclaimer of opinion, nor were they qualified or modified as to
uncertainty, audit scope, or accounting principles.
During the Companys fiscal periods ended December 31, 2008 and 2007, and the subsequent interim
periods through October 13, 2009, there were no disagreements between the Company and Malone &
Bailey LP on any matter of accounting principles or practices, financial statement disclosure,
or auditing scope or procedure (within the meaning of Item 304(a)(1)(iv) of Regulation S-K)
and there were no reportable events (as defined by Item 304(a)(1)(v) of Regulation S-K).
During the Companys two most recent years ended December 31, 2008, and the subsequent interim
periods through October 13, 2009, neither the Company nor anyone on its behalf consulted with
Hein & Associates LLP regarding any of the matters or events set forth in Item 304(a)(2)(i)
and (ii) of Regulation S-K.
Item 9A(T). CONTROLS AND PROCEDURES
Our chief executive officer and chief financial officer have reviewed and continue to evaluate the
effectiveness of our controls and procedures over financial reporting and disclosure (as defined in
the Securities Exchange Act of 1934 (Exchange Act) Rules 13a-15(e) and 15d-15(e)) as of the end
of the period covered by this annual report. The term disclosure controls and procedures is
defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. This term refers to the controls and
procedures of our company that are designed to ensure that information required to be disclosed by
us in the reports that we file under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified by the Securities and Exchange Commissions rules and
forms, and that such information is accumulated and communicated to our management, including our
chief executive officer and chief financial officer, as appropriate, to allow timely decisions
regarding required disclosures. In designing and evaluating our controls and procedures over
financial reporting and disclosure, our management recognized that any controls and procedures, no
matter how well designed and operated, can provide only reasonable assurance of achieving the
desired control objectives and our management necessarily was required to apply its judgment in
evaluating the cost-benefit relationship of possible controls and procedures.
66
Evaluation of Disclosure Controls and Procedures. Based on managements evaluation, our chief
executive officer and chief financial officer concluded that, as of December 31, 2009, our
disclosure controls and procedures are designed at a reasonable assurance level and are effective
to provide reasonable assurance that information we are required to disclose in reports that we
file or submit under the Exchange Act is recorded, processed, summarized and reported within the
time periods specified in Securities and Exchange Commission rules and forms, and that such
information is accumulated and communicated to our management, including our chief executive
officer and chief financial officer, as appropriate, to allow timely decisions regarding required
disclosure.
Changes in Internal Control over Financial Reporting. There were no changes in our internal
control over financial reporting that occurred during the fourth quarter of 2009 that have
materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting.
Managements Report on Internal Control over Financial Reporting. Our management is responsible
for establishing and maintaining adequate internal control over financial reporting, as defined in
Exchange Act Rule 13a-15(f). Our management conducted an evaluation of the effectiveness of our
internal control over financial reporting based on the framework in Internal ControlIntegrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on
this evaluation, management concluded that our internal control over financial reporting was
effective as of December 31, 2009. This annual report does not include an attestation report of
our registered public accounting firm regarding internal control over financial reporting.
Managements report was not subject to attestation by the companys registered public accounting
firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to
provide only managements report in this annual report.
Item 9B. OTHER INFORMATION
None.
67
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item is incorporated by reference to the 2010 Proxy Statement,
which will be filed with the Securities and Exchange Commission not later than 120 days subsequent
to December 31, 2009.
Pursuant to Item 401(b) of Regulation S-K, the information required by this item with respect to
Magnum Hunters executive officers is set forth in Part I of this report.
Item 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by reference to the 2010 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2009.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
The information required by this item is incorporated herein by reference to the 2010 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2009. See Item 5. Market for Registrants Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities, which sets forth certain
information with respect to our equity compensation plans.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item is incorporated herein by reference to the 2010 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2009.
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item is incorporated herein by reference to the 2010 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2009.
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
|
(a) |
1. |
|
Consolidated Financial Statements: See Index to Financial Statements on page F-1. |
|
|
|
2. |
|
No schedules are required. |
|
|
|
3. |
|
Exhibits: |
The exhibits listed in the accompanying Index to Exhibits are filed or incorporated by
reference as part of the annual report.
68
|
|
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
|
|
|
3.1 |
(1) |
|
Certificate of Incorporation of the Registrant, as amended |
|
3.1.1 |
(6) |
|
Certificate of Amendment to Certificate of Incorporation of the Registrant dated May 10, 2007 |
|
3.1.2 |
(12) |
|
Certificate of Ownership and Merger of Magnum Hunter Resources Corporation into Petro Resources
Corporation, effective July 14, 2009. |
|
3.2 |
(1) |
|
Amended and Restated Bylaws of the Registrant dated April 14, 2006 |
|
3.2.1 |
(2) |
|
Amendment to Bylaws of the Registrant |
|
3.2.2 |
(7) |
|
Amendment to Bylaws of the Registrant dated October 12, 2006 |
|
4.1 |
(3) |
|
Certificate of Designations of Preferences and Rights of Series A Preferred Stock |
|
4.2 |
(21) |
|
Certificate of Designation for Series B Redeemable Convertible Preferred Stock |
|
4.3 |
(19) |
|
Certificate of Designation of Rights and Preferences of Series C Preferred Stock |
|
10.1 |
(1) |
|
Form of Registration Rights Agreement dated August 1, 2005 |
|
10.2 |
(1) |
|
Form of Warrant sold as part of August 2005 private placement |
|
10.3 |
(1) |
|
Lease Purchase Agreement dated January 10, 2006 between Petro Resource Corporation and The
Meridian Resource & Exploration, LLC |
|
10.4 |
(1) |
|
2006 Stock Incentive Plan* |
|
10.5 |
(1) |
|
Form of Registration Rights Agreement dated February 17, 2006 |
|
10.6 |
(1) |
|
Form of Warrant sold as part of February 2006 private placement |
|
10.7 |
(2) |
|
Subscription Agreement for Hall-Houston Exploration II, L.P. |
|
10.8 |
(2) |
|
Amended and Restated Agreement of Limited Partnership dated as of April 21, 2006 for Hall-Houston
Exploration II, L.P. |
|
10.9 |
(4) |
|
Purchase and Sale Agreement dated December 11, 2006 with Eagle Operating, Inc. |
|
10.10 |
(4) |
|
Credit Agreement dated February 16, 2007 between PRC Williston LLC and D.B. Zwirn Special
Opportunities Fund, L.P., as administrative agent |
|
10.11 |
(4) |
|
Security Agreement dated February 16, 2007 Between PRC Williston, LLC and D.B. Zwirn Special
Opportunities Fund, L.P., as administrative agent |
|
10.12 |
(4) |
|
Guaranty and Pledge Agreement dated February 16, 2007 between Petro Resource Corporation and
D.B. Zwirn Special Opportunities Fund, L.P., as administrative agent |
|
10.13 |
(4) |
|
Lease dated September 30, 2006 with Gateway Ridgecrest Inc. |
|
10.14 |
(3) |
|
Securities Purchase Agreement dated April 3, 2007 |
|
10.15 |
(3) |
|
Registration Rights Agreement dated April 3, 2007 |
|
10.16 |
(5) |
|
Letter Agreement dated May 25, 2007 between Petro Resource Corporation and Harry Lee Stout* |
|
10.17 |
(6) |
|
Letter Agreement dated August 14, 2007 between PRC Williston LLC and D.B. Zwirn Special
Opportunities Fund, L.P., as administrative agent |
|
10.18 |
(7) |
|
Letter Agreement dated September 19, 2007 between PRC Williston LLC and D.B. Zwirn Special
Opportunities Fund, L.P., as administrative agent |
|
10.19 |
(8) |
|
First Amendment dated May 13, 2008 to Credit Agreement dated February 16, 2007 between PRC
Williston LLC and D.B. Zwirn Special Opportunities Fund, L.P., as administrative agent |
|
10.20 |
(9) |
|
Credit Agreement dated as of September 9, 2008, among Petro Resources Corporation, CIT Capital
USA Inc., as administrative agent, and the lenders party thereto |
|
10.21 |
(20) |
|
First Amendment to Credit Agreement dated March 19, 2009 among Petro Resources Corporation, CIT
Capital USA Inc., as administrative agent, and the lenders party thereto |
|
10.22 |
(9) |
|
Second Lien Term Loan Agreement dated as of September 9, 2008, on March 19, 2009 among Petro
Resources Corporation, CIT Capital USA Inc., as administrative agent, and the lenders party
thereto |
|
10.23 |
(20) |
|
First Amendment to Second Lien Term Loan Agreement dated March 19, 2009 among Petro Resources
Corporation, CIT Capital USA Inc., as administrative agent, and the lenders party thereto |
|
10.24 |
(9) |
|
Guaranty and Collateral Agreement dated as of September 9, 2008 among Petro Resources
Corporation, PRC Williston LLC, and CIT Capital USA Inc., as administrative agent |
69
|
|
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
|
|
|
10.25 |
(9) |
|
Second Lien Guaranty and Collateral Agreement dated as of September 9, 2008 among Petro Resources
Corporation, PRC Williston LLC, and CIT Capital USA Inc., as administrative agent |
|
10.26 |
(10) |
|
Partnership Interest Purchase Agreement dated September 26, 2008, as amended on September 29,
2008, between Petro Resources Corporation and PRC HHEP II, LP |
|
10.27 |
(11) |
|
Employment Agreement dated May 22, 2009 between Gary C. Evans and Petro Resources Corporation* |
|
10.28 |
(11) |
|
Stock Option Agreement dated May 22, 2009 between Gary C. Evans and Petro Resources Corporation* |
|
10.29 |
(11) |
|
Restricted Stock Agreement dated May 22, 2009 between Gary C. Evans and Petro Resources
Corporation* |
|
10.30 |
(11) |
|
Employment Agreement dated May 22, 2009 between Ronald D. Ormand and Petro Resources Corporation* |
|
10.31 |
(11) |
|
Stock Option Agreement dated May 22, 2009 between Ronald D. Ormand and Petro Resources
Corporation * |
|
10.32 |
(11) |
|
Restricted Stock Agreement dated May 22, 2009 between Ronald D. Ormand and Petro Resources
Corporation * |
|
10.33 |
(13) |
|
Agreement and Plan of Merger, dated September 9, 2009, by and among Magnum Hunter Resources
Corporation, Sharon Hunter, Inc., Sharon Resources, Inc. and Sharon Energy Ltd. |
|
10.34 |
(13) |
|
Purchase and Sale Agreement, dated September 14, 2009, between Centurion Exploration Company,
LLC and Magnum Hunter Resources Corporation. |
|
10.35 |
(14) |
|
Asset Purchase Agreement dated as of October 28, 2009 among Magnum Hunter Resources Corporation
and Triad Energy Corporation. |
|
10.36 |
(15) |
|
Form of Warrant sold as part of November 2009 offering. |
|
10.37 |
(15) |
|
Form of Securities Purchase and Registration Rights Agreement as part of November 2009 offering. |
|
10.38 |
(16) |
|
Form of Warrant sold as part of November 2009 offering with Canaccord Adams, Inc. as the
Placement Agent. |
|
10.39 |
(16) |
|
Placement Agency Agreement, dated as of November 10, 2009, by and between Magnum Hunter Resources
Corporation and Canaccord Adams Inc. for the sale of up to an aggregate of 3,903,720 Units. |
|
10.40 |
(16) |
|
Placement Agency Agreement, dated as of November 11, 2009, by and between Magnum Hunter Resources
Corporation and Canaccord Adams Inc. for the sale of up to an aggregate of 2,500,000 Units. |
|
10.41 |
(17) |
|
Credit Agreement, dated as of November 23, 2009, as amended on November 30, 2009, by and among
the Company, Bank of Montreal, as administrative agent, BMO Capital Markets, as Lead Arranger and
Bookrunner, and the lenders party thereto. |
|
10.42 |
(18) |
|
Underwriting Agreement, dated December 9, 2009, between Magnum Hunter Resources Corporation and
Wunderlich Securities, Inc. |
|
10.44 |
(26) |
|
Employment Agreement dated May 27, 2008 between Petro Resources Corporation and Wayne P. Hall.* |
|
10.45 |
(26) |
|
Employment Agreement dated May 27, 2008 between Petro Resources Corporation and Donald L.
Kirkendall.* |
|
10.46 |
(26) |
|
Employment Agreement dated May 27, 2008 between Petro Resources Corporation and James W. Denny. * |
|
10.47 |
(26) |
|
First Amendment to Credit Agreement dated March 19, 2009 among Petro Resources Corporation, CIT
Capital USA Inc., as administrative agent, and the lenders party thereto |
|
10.48 |
(26) |
|
First Amendment to Second Lien Term Loan Agreement dated March 19, 2009 among Petro Resources
Corporation, CIT Capital USA Inc., as administrative agent, and the lenders party thereto |
|
10.49 |
(22) |
|
Second Amendment to Credit Agreement, dated as of January 25, 2010, by and among the Company,
Bank of Montreal, as administrative agent, and the guarantors and lenders party thereto |
|
10.50 |
(23) |
|
Amended
and Restated Credit Agreement, dated as of February 12, 2010, by and among the Company, Bank of Montreal, as
Administrative Agent, Capital One, N.A. as Syndication Agent, BMO Capital Markets and Capital
One, N.A., as Co-Arrangers and Joint Bookrunner, and the lenders party thereto |
70
|
|
|
|
|
Exhibit |
|
|
Number |
|
Description |
|
|
|
|
|
|
10.53 |
(24) |
|
At The Market Issuance Sales Agreement with Wm. Smith & Co. for Series C Preferred Stock |
|
10.54 |
(25) |
|
At Market Issuance Sales Agreement with Wm. Smith & Co. for Common Stock |
|
21.1 |
|
|
List of Subsidiaries |
|
23.1 |
|
|
Consent of Hein & Associates LLP |
|
23.2 |
|
|
Consent of Malone & Bailey, PC |
|
23.3 |
|
|
Consent of Cawley Gillespie & Associates, Inc |
|
23.4 |
|
|
Consent of DeGolyer & MacNaughton |
|
31.1 |
|
|
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
|
31.2 |
|
|
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
|
32.1 |
|
|
Certification of the Chief Executive Officer and Chief Financial Officer provided pursuant to 18
U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
|
* |
|
The referenced exhibit is a management contract, compensatory plan or arrangement. |
|
(1) |
|
Incorporated by reference from Petro Resource Corporations Registration Statement on Form SB-2
filed on March 21, 2006. |
|
(2) |
|
Incorporated by reference from Petro Resource Corporations Amendment No. 1 to Registration
Statement on Form SB-2 filed on June 9, 2006. |
|
(3) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Form 8-K
filed on April 4, 2007. |
|
(4) |
|
Incorporated by reference from Magnum Hunter Resources Corporations annual report on Form 10-KSB
for the year ended December 31, 2006, filed on April 2, 2007. |
|
(5) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Form 8-K
filed on June 1, 2007. |
|
(6) |
|
Incorporated by reference from Magnum Hunter Resources Corporations quarterly report on Form
10-QSB filed on August 14, 2007. |
|
(7) |
|
Incorporated by reference from Magnum Hunter Resources Corporations Amendment No. 1 to
Registration Statement on Form SB-2 filed on September 21, 2007. |
|
(8) |
|
Incorporated by reference from the Magnum Hunter Resources Corporations quarterly report on Form
10-Q filed on May 15, 2008. |
|
(9) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Forms 8-K
filed on September 11, 2008 and March 30, 2009. |
|
(10) |
|
Incorporated by reference from Magnum Hunter Resources Corporations quarterly report on Form
10-Q filed on November 13, 2008. |
|
(11) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Form 8-K
filed on May 28, 2009. |
|
(12) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Form 8-K
filed on July 14, 2009. |
|
(13) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Form 8-K
filed on September 15, 2009. |
|
(14) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Form 8-K
filed on October 29, 2009. |
|
(15) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Form 8-K
filed on November 6, 2009. |
|
(16) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Form 8-K
filed on November 13, 2009. |
|
(17) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Forms 8-K
filed on November 27, 2009 and November 30, 2009. |
|
(18) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Form 8-K
filed on December 11, 2009. |
71
|
|
|
(19) |
|
Incorporated by reference from Magnum Hunter Resources Corporations Registration Statement Form
8-A filed on December 10, 2009. |
|
(20) |
|
Incorporated by reference from Magnum Hunter Resources Corporations quarterly report on Form
10-Q filed on May 11, 2009. |
|
(21) |
|
Incorporated by reference from Magnum Hunter Resources Corporations Registration Statement Form
8-A filed on February 16, 2010. |
|
(22) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Form 8-K
filed on January 28, 2010. |
|
(23) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Form 8-K
filed on February 19, 2010. |
|
(24) |
|
Incorporated by reference from Magnum Hunter Resources Corporations current report on Form 8-K
filed on January 6, 2010. |
|
(25) |
|
Incorporated by reference from Magnum Hunter Resources Corporations Form S-3/A filed on October
14, 2010. |
(26) |
|
Incorporated by reference
from Magnum Hunter Resources Corporations annual report on
Form 10-K filed on March 31, 2009. |
72
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.
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PETRO RESOURCES CORPORATION
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Date: March 31, 2010 |
By: |
/s/ Gary C. Evans
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Gary C. Evans |
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Chairman of the Board
and Chief Executive Officer
(Authorized Signatory) |
|
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and the capacities and on the
dates indicated.
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Signature |
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Title |
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Date |
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/s/ Gary C. Evans
Gary C. Evans
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Chairman of the Board and
Chief Executive Officer
(Principal Executive Officer)
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March 31, 2010 |
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/s/ Ronald D. Ormand
Ronald D. Ormand
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Executive Vice President and Chief
Financial Officer
(Principal Financial Officer)
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March 31, 2010 |
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/s/ David S. Krueger
David S. Krueger
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Senior Vice President and Chief
Accounting Officer
(Principal Accounting Officer)
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March 31, 2010 |
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/s/ Wayne P. Hall
Wayne P. Hall
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Vice Chairman of the Board, Director
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March 31, 2010 |
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/s/ J. Raleigh Bailes, Sr.
J. Raleigh Bailes, Sr.
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Director
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March 31, 2010 |
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/s/ Brad Bynum
Brad Bynum
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Director
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March 31, 2010 |
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/s/ Gary L. Hall
Gary L. Hall
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Director
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March 31, 2010 |
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/s/ Joe L. McClaugherty
Joe L. McClaugherty
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Director
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March 31, 2010 |
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/s/ Steven A. Pfeifer
Steven A. Pfeifer
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Director
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March 31, 2010 |
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/s/ Jeff Swanson
Jeff Swanson
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Director
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March 31, 2010 |
73