Gulfport Energy Corporation
Supplemental Financial and Operating Statistics
Y
e a r
E
n d
Financial Highlights
Revenues
Income from Operations
Net Income
Earnings per Diluted Share
Production
Oil (M Bbls)
Natural Gas (MMCF)
Total Oil Equivalent (M BOE)
Realized Price
Oil (per M Bbls)
Natural Gas (MMCF)
Total Oil Equivalent (M BOE)
Drilling Activity
Wells Drilled
Recompletions Performed
2007
$105,838,000
$40,464,000
$37,775,000
$1.01
2006
$60,390,000
$25,855,000
$27,808,000
$0.82
1,500.8
816.5
1,636.9
$66.71
$ 7.40
$64.86
869.7
676.8
982.5
$64.43
$ 6.20
$61.30
Improvement
75%
57%
36%
23%
73%
21%
67%
4%
19%
6%
38
62
28
19
36%
226%
S
h a r e h o l d e r
L
e t t e r
Dear Shareholders,
In 2007, Gulfport reported revenue of $106 million and net income of $38 million. Earnings per diluted share were $1.01
for 2007, an increase of $0.19 per diluted share compared to 2006. Proved reserves, as reported at year-end 2007, were
29.2 million barrels of oil equivalent (“BOE”), an increase of 6.0 million BOE compared to 2006.
In Southern Louisiana, we continued our active development drilling program at
our fl agship fi eld located in West Cote Blanche Bay and executed an exploratory
program at the Hackberry fi eld. These programs led to the successful growth
of our Southern Louisiana production from 960,000 BOE in 2006 to 1.6 million
BOE in 2007.
At our West Cote fi eld, we drilled 26 wells and performed 60 recompletions
in 2007. Of the 26 wells drilled, 22 were productive and four were non-
productive.
At our Hackberry fi eld, we embarked on our fi rst exploratory program late in 2006. We completed a 12-well exploratory
program in 2007 with mixed results. On the eastern portion of our acreage, which is in Calcasieu Lake, a majority of
the nine wells drilled in the water were productive, but will not prove to be economic. However, two wells drilled on the
western portion of the acreage on land had initial production rates of 400 to 600 BOE per day. We are optimistic that we
have discovered a productive trend in this area to the west that we can exploit in 2008.
We remain 100% committed to our West Cote and Hackberry fi elds in Southern Louisiana, but we have carefully examined
our 2007 results and have adjusted our program in 2008. We will spend our capital in the locations generating the
greatest return. We plan to resume drilling in Southern Louisiana in both fi elds by mid-year 2008. Overall, we plan to
drill eight to twelve development wells at West Cote and drill four to six wells on the western portion of the acreage at the
Hackberry fi eld in 2008.
Operationally, we are adding Supervisory Control and Data Acquisition (“SCADA”) equipment at the West Cote fi eld. These
enhancements are expected to maximize equipment runtime and increase the overall effi ciency of our operations.
In Canada, to-date 115 core hole wells have been drilled during the last two drilling seasons on our acreage in the
Athabasca Oil Sands play. A third-party engineering assessment estimated original barrels in place, net to our interest, of
3.0 billion barrels with bitumen thickness greater than 10 meters. It is expected that an application will be submitted to
the Alberta government for a pilot Steam Assisted Gravity Drainage (SAGD) facility at Algar Lake (typically 10,000 barrel
a day projects) in the third quarter of 2008. The application process will take approximately one year. When approved,
construction of the SAGD facility can begin with fi rst production expected as soon as 2011. Facility capital expenditures net
to Gulfport are currently estimated at approximately $80 million for the fi rst SAGD facility with the majority of this spending
expected in late 2009 through 2011. Over time, Gulfport’s projects in Canada are expected to will be a source of substantial
growth and value creation.
In the Bakken play in North Dakota, we doubled our acreage position to 14,000 net acres. In 2007, we participated in 17
non-operated wells in this play. In 2008, we plan to substantially ramp up our involvement and have allocated $10 million
towards new well activity. By year-end 2008, we anticipate having a working interest in 30+ wells in this very hot play. We
see this play of having material potential for Gulfport in the near future.
Finally, we concluded 2007 with the biggest acquisition in our 11-year history by acquiring 4,100 net acres in the Permian
Basin in West Texas. The acquisition included 16 net producing wells, 46 net proved undeveloped locations and 43 net
unbooked locations which are based on 40-acre well spacing. This fi eld produces predominately from the Wolfcamp
formation, with additional contribution from the Spraberry formation. Net production from this fi eld averaged approximately
585 BOE per day in the fi rst quarter of 2008. We plan to drill 17 to 22 net wells in the Permian in 2008. This acquisition
provides near-term low-risk, organic production growth from one of the most prolifi c basins in the Southwest. We expect
to actively develop this fi eld over the next several years and possibly add to our
acreage position.
Overall, we continue to be oil focused and will continue to grow through the drill
bit in 2008. We believe each of our fi elds has signifi cant oil in place with the
opportunity for attractive returns and we plan to allocate our capital accordingly.
We expect both technical and operational effi ciencies to be improved this year
translating into better results and higher earnings based on the numerous low
risk opportunities available to us.
Thank you for your continued support.
Respectfully,
Mike Liddell
Chairman of the Board
James D. Palm
Chief Executive Officer
Operational Areas
Southern Louisiana
A majority of Gulfport’s existing production is based in Southern Louisiana. In 2007, production grew to 1.6 million BOE, an
increase of 68% compared to 2006.
2008 Activity Targets
West Cote & Hackberry
Production:
1.6 to 1.7 MM BOE
Drilling Activity:
12 to 18 wells
Recompletions Activity: 45 to 50 wells
Capital Expenditures:
$40 MM
Canadian Oil Sands
Gulfport owns approximately 128,000 net acres in the
Athabasca Oil Sands play in Canada. Gulfport, through a
joint-venture with Grizzly Oil Sands, has drilled 115 gross
core hole evaluation wells. Gulfport and Grizzly expect to
submit an application permit for a stream assisted gravity
drainage (SAGD) facility for the Algar Lake project in the
third quarter of 2008.
2008 Activity Targets
Canadian Oil Sands
Permit Application Submitted: 3Q 2008
Capital Expenditures:
$10 MM
Operational Areas
Permian Basin
Gulfport acquired 4,100 net acres and 16 producing wells in the Permian Basin in West Texas in December 2007. The
acquisition included 6.6 million proved producing reserves as of year-end 2007, 46 proved undeveloped locations and 43
unbooked locations based on 40-acre well spacing.
2008 Activity Targets
Permian Basin
Production:
300 to 400 M BOE
Drilling Activity:
17 to 22 net wells
Capital Expenditures: $35 MM
Bakken
Gulfport owns approximately 14,000 net acres in the
Bakken play in the Williston Basin in North Dakota.
Gulfport had an average interest of 1.6% in 17 wells
at year-end 2007. Gulfport plans to greatly increase
activity and capital in 2008 in this area.
2008 Activity Targets
Bakken
Production:
< 30,000 BOE
Total Well Involvement: 30+ non-op wells
Capital Expenditures:
$10 MM
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
È ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007
OR
‘ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from
to
Commission File Number: 000-19514
Gulfport Energy Corporation
(Exact Name of Registrant as Specified in Its Charter)
Delaware
(State or Other Jurisdiction of Incorporation or Organization)
73-1521290
(I.R.S. Employer Identification No.)
14313 North May Avenue, Suite 100
Oklahoma City, Oklahoma
(Address of Principal Executive Offices)
73134
(Zip code)
(405) 848-8807
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share
The NASDAQ Stock Market LLC
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes ‘ No È
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act. Yes ‘ No È
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes È No ‘
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of
this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ‘
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer,
or a smaller reporting company. See definitions of “accelerated filer and large accelerated filer” and “smaller reporting
company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated filer ‘ Accelerated filer È Non-accelerated filer ‘ Smaller reporting company ‘
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ‘ No È
The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant
computed as of June 30, 2007, based on the closing price of the common stock on the NASDAQ Global Select Market on
June 29, 2007, the last business day of the registrant’s most recently completed second fiscal quarter ($19.98 per share)
was $405,264,130.
As of March 3, 2008, 42,550,031 shares of the registrant’s common stock were outstanding.
Portions of Gulfport Energy Corporation’s Proxy Statement for the 2008 Annual Meeting of Stockholders are
incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.
DOCUMENTS INCORPORATED BY REFERENCE
TABLE OF CONTENTS
FORWARD-LOOKING STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 1.
DESCRIPTION OF BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 1A. RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 1B. UNRESOLVED STAFF COMMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 2.
PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 3.
LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS . . . . . . . . . . . . . . . .
PART II
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES . . . . . . . . . . . . . . . . .
ITEM 6.
SELECTED FINANCIAL DATA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . . . . . .
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . . . . . . . . . . . . . . . . . . . .
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 9A. CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 9B. OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART III
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE . . . . . .
ITEM 11. EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART IV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES [UPDATE] . . . . . . . . . . . . . .
Signatures
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Index to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
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S-1
F-1
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E-1
i
FORWARD-LOOKING STATEMENTS
Our disclosure and analysis in this Form 10-K may include forward-looking statements within the meaning
of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities
Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities Litigation Reform Act of
1995, that are subject to risks and uncertainties. These statements involve known and unknown risks,
uncertainties and other factors that may cause our actual results, performance or achievements to be materially
different from any future results, performance or achievements expressed or implied by the forward-looking
statements. In some cases, you can identify forward-looking statements by terms such as “may,” “will,”
“should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,”
“predicts,” “potential” and similar expressions intended to identify forward-looking statements. All statements,
other than statements of historical facts, included in this Form 10-K that address activities, events or
developments that we expect or anticipate will or may occur in the future, including such things as estimated
future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including
the amount and nature thereof), business strategy and measures to implement strategy, competitive strength,
goals, expansion and growth of our business and operations, plans, references to future success, reference to
intentions as to future matters and other such matters are forward-looking statements.
These forward-looking statements are largely based on our expectations and beliefs concerning future
events, which reflect estimates and assumptions made by our management. These estimates and assumptions
reflect our best judgment based on currently known market conditions and other factors relating to our operations
and business environment, all of which are difficult to predict and many of which are beyond our control.
Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and
involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions
about future events may prove to be inaccurate. Management cautions all readers that the forward-looking
statements contained in this Form 10-K are not guarantees of future performance, and we cannot assure any
reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual
results may differ materially from those anticipated or implied in the forward-looking statements due to the
factors listed in the “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and
Results of Operations” sections and elsewhere in this Form 10-K. All forward-looking statements speak only as
of the date of this Form 10-K. We do not intend to publicly update or revise any forward-looking statements as a
result of new information, future events or otherwise, except as required by law. These cautionary statements
qualify all forward-looking statements attributable to us or persons acting on our behalf.
1
ITEM 1. DESCRIPTION OF BUSINESS
General
PART I
We are an independent oil and natural gas exploration and production company with our principal producing
properties located along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry
fields. We have also recently acquired strategic assets in West Texas in the Permian Basin. We also hold a
significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC and
have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to
achieve reserve growth and increase our cash flow through our annual drilling programs.
In 2007, at our WCBB field, we drilled 26 wells and recompleted 60 existing wells for a total cost of $57.9
million as of December 31, 2007. Of our 26 new wells drilled at WCBB in 2007, 22 were completed as
producing wells and four were non-productive. As of March 1, 2008, we had drilled two new wells at WCBB,
both of which are producing and had recompleted 14 wells during 2008. During 2008, we intend to drill a total of
eight to ten wells, recomplete 44 wells and conduct other activities at our WCBB field for an estimated aggregate
cost of $21 to $23 million. In December 2007, production at WCBB was 105,922 net barrels of oil equivalent, or
BOE, or an average of 3,417 BOE per day, 93% of which was from oil and 7% of which was from natural gas. In
February 2008, our average net daily production at WCBB was 3,622 BOE, 95% of which was from oil and 5%
of which was from natural gas.
In 2007, at our East Hackberry field, we drilled nine wells in Lake Calcasieu and three wells on land and
recompleted two existing wells for a total cost of $62.4 million as of December 31, 2007. Of the 12 wells drilled
during 2007, ten were completed as producing wells and two were non-productive. As of March 1, 2008 at East
Hackberry, we had drilled one additional well in Lake Calcasieu, which is now producing, and had recompleted
three existing wells. We intend to drill three to five additional land wells, recomplete one additional well and
conduct other activities in 2008 for an aggregate estimated cost of $17 to $19 million. In December 2007, net
production at East Hackberry was 26,850 BOE, or an average of 867 BOE per day, 70% of which was from oil
and 30% of which was from natural gas. In February 2008, our average net daily production at East Hackberry
was 735 BOE, 80% of which was from oil and 20% of which was from natural gas.
On December 20, 2007, we completed the acquisition of strategic assets in West Texas in the Permian Basin
for approximately $85 million, with an effective date of November 1, 2007. Through this transaction, Gulfport
acquired 4,100 net acres with production at the time of acquisition of approximately 800 net BOE a day from 32
gross wells, predominately from the Wolfcamp formation. Existing production is approximately 64% oil, 23%
natural gas liquids and 13% natural gas. At December 31, 2007, Pinnacle Energy Services LLC, an independent
petroleum engineering firm, estimated that proved reserves net to our interest in these assets were approximately
6.6 million BOE, of which 19.5% were classified as proved developed producing, or PDP. Proved undeveloped,
or PUD, reserves included in this estimate were from 92 gross well locations on 40-acre units. The proved
reserves are located in the Wolfcamp and Spraberry formations, which are generally characterized as long-lived,
with predictable production profiles. We expect that approximately 17 to 22 net wells will be drilled on this
acreage in 2008. The wells are expected to be drilled to approximately 10,200 feet at an estimated average gross
completed well cost of $1.7 million.
During the third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings Inc., purchased
a 24.9999% interest in Grizzly Oils Sands ULC, or Grizzly, a Canadian unlimited liability company. The
remaining interests in Grizzly are owned by entities controlled by Wexford Capital LLC, or Wexford, an affiliate
of ours. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province
near Fort McMurray near other oil sands development projects. As of March 1, 2008, Grizzly had approximately
511,000 acres under lease. Grizzly drilled 62 core holes during the 2006/2007 winter delineation drilling season
and tested three separate lease blocks. Future plans currently include acquiring additional leases, drilling
approximately 55 to 60 additional core holes and a seismic program during the 2007/2008 winter drilling
2
season and initial planning for the construction of a 10,000 barrel per day steam assisted gravity drainage facility,
or SAGD, that could lead to initial production in 2011. Permitting for this initial SAGD facility is expected to
commence later in 2008.
During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining
interests in Tatex are owned by entities controlled by Wexford. Tatex, a privately held entity, holds 85,122 of the
1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company.
APICO has a reserve base located in Southeast Asia through its ownership of concessions covering three million
acres which includes the Phu Horm Field.
As of December 31, 2007, we had 29.2 million barrels of oil equivalent, or MMBOE, of proved reserves
with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately
$821million and associated standardized measure of discounted future net cash flows of approximately $668.3
million. See Item 2. “Properties—Proved Oil and Natural Gas Reserves” for our definition of PV-10, a
non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash
flows to PV-10.
Principal Oil and Natural Gas Properties
The following table presents certain information as of December 31, 2007 reflecting our net interest in our
principal producing oil and natural gas properties along the Louisiana Gulf Coast and in the Permian Basin in
West Texas.
NRI/WI (1)
Producing
Wells (2)
Non-Producing
Wells
Developed
Acreage (3)
Gas
Oil
Total
Field
Percentages Gross Net Gross
Net
Gross
Net
Mboe Mboe Mboe
Proved Reserves
West Cote Blanche Bay (4) . . . 78.665/100 111
12
E. Hackberry (5) . . . . . . . . . . . 79.424/100
3
87.5/100
W. Hackberry . . . . . . . . . . . . .
Permian . . . . . . . . . . . . . . . . . .
32
37.5/50
Overrides/Royalty
111 166
12
82
24
3
16 —
166
5,668
82
3,265
592
24
— 2,560
2,776
5,668 15,891 15,135 17,783
4,582
3,265
158
6,630
592 —
5,587
4,119
158
5,699
1,280
Non-operated . . . . . . . . . . . .
Various
18
0.8
16
0.7
4,956
586
5
4
5
Total . . . . . . . . . . . . . . . . . . . . .
176 142.8 288 272.7 17,041 11,391 24,259 25,115 29,158
(1) Net Revenue Interest (NRI)/Working Interest (WI).
(2)
(3) Developed acres are acres spaced or assigned to productive wells. Approximately 87% of our acreage is
Includes 30 gross and net wells at WCBB that are producing intermittently.
developed acreage and has been perpetuated by production. We have 1,100 and 2,820 net undeveloped acres
in the East Hackberry field and the Permian Basin, respectively.
(4) We have a 100% working interest (78.665% average NRI) from the surface to the base of the 13900 Sand
which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working
interest (29.95% NRI).
(5) Does not include an additional 3,233 acres under an option we exercised which will increase our acreage
position significantly to approximately 7,598 acres. State approval was obtained on February 27, 2008, and
we are working with the state to finalize the leases.
3
West Cote Blanche Bay Field
Location and Land
The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water
depths averaging eight to ten feet. We own a 100% working interest (78.665% net revenue interest, or NRI), and
are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own
a 40.40% non-operated working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is
operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres.
Area History and Production
Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and
gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the
remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300
wells were drilled in the field. Of the 900 wells drilled as of December 31, 2007, 809 were completed as
producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. From the date of our
acquisition of WCBB in 1997 through December 31, 2007, we drilled 120 new wells, 14 of which were
non-productive, for an 88% success rate. As of December 31, 2007, estimated field cumulative gross production
was 187.4 MMBOE and 235.5 billion cubic feet, or Bcf, of gas. Of the 900 wells drilled in WCBB as of
December 31, 2007, 81 were producing, 166 were shut-in, 30 were producing intermittently and five were being
used as salt water disposal wells. The other 618 wells have been plugged and abandoned.
In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that
processed out 100 fold. In 1993, an undershoot survey around the crest and production facilities was completed.
We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and
our technical staff developed prospects from the data. The reprocessed data has enabled us to identify prospects
in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again
reprocessed the seismic data using advanced seismic data processing.
Geology
WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a
piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative
movements affected deposition and created a complex system of fault traps. The compensating fault sets
generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage
movement caused extension over the dome and a large graben system (a downthrown area bounded by normal
faults) was formed.
There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200
major and minor discrete intervals have been tested. Within the 900 wellbores that had been drilled in the field as
of December 31, 2007, over 4,000 potential zones have been penetrated. These sands are highly porous and
permeable reservoirs primarily with a strong water drive.
WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD,
locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to
penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault
seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will
be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault
is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of
interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in
lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk associated
with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an
4
effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells
that produced from a sub-optimal position within a particular zone. Our inventory of prospects includes 111 PUD
wells. The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2019.
Facilities
We own and operate a production facility at WCBB that includes four production tank batteries, six natural
gas compressors, a dehydration unit and a salt water disposal system.
Recent and Future Activity
In 2007, we drilled 26 wells and recompleted 60 existing wells at WCBB. Of these 26 new wells, 22 were
completed as producers, and four were non-productive. As of March 1, 2008, we had drilled two new wells, both
of which are producing, and had recompleted 14 wells during 2008. Of the 22 wells completed in 2007, ten were
considered deep wells. The 22 productive wells, with total depths ranging from 6,107 to 10,464 feet, have
approximately 2,716 feet of aggregate apparent net pay. The other four wells were non-productive, including one
exploratory well that was drilled to satisfy our drilling commitment with the State of Louisiana to hold the
non-productive portions of WCBB. We anticipate drilling a total of eight to ten wells and recompleting 44 wells
at WCBB during 2008.
Production Status
In December 2007, production at WCBB was 105,922 net BOE, or an average of 3,417 BOE per day, 93%
of which was from oil and 7% of which was from natural gas. In February 2008, our average net daily production
at WCBB was 3,622 BOE, 95% of which was from oil and 5% of which was from natural gas.
East Hackberry Field
Location and Land
The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake
Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 79.424%
average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. We hold
beneficial interests in approximately 4,365 acres, including the Erwin Heirs Block, which is located on land, and
the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. In
addition, we exercised our option to acquire an additional 3,233 acres at the Hackberry field. The option will
increase our acreage position significantly to approximately 7,598 acres. State approval was obtained on
February 27, 2008, and we are working with the state to finalize the leases.
Area History and Production
The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a
gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly
indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated
cumulative oil and condensate production through 2007 was over 263,000 barrels of oil and 330 Bcf of
casinghead gas production. There have been a total of 182 wells drilled on our portion of the field. As of
December 31, 2007, 12 wells had daily production, 82 were shut-in and two had been converted to salt water
disposal wells. The remaining 86 wells had been plugged and abandoned.
5
Geology
The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,”
divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the
eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a
series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks.
These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations
found between 5,100 and 12,200 feet.
Facilities
We have a field office that serves both the East and West Hackberry fields. In addition, we completed
installation of a new production barge at the East Hackberry field in the second quarter of 2007. The barge is
designed to have the ability to process on a per day basis approximately 5,000 barrels of liquid, 30 Mmcf of high
pressure natural gas, 6.5 Mmcf of low pressure natural gas and 10,000 barrels of salt water.
Recent and Future Activity
During 2005, we completed a proprietary 42 square mile 3-D seismic survey at East Hackberry. Given that
drilling activities at the East Hackberry field prior to our acquisition of the field in 1997 were undertaken without
the benefit of modern seismic information, we believe that this 3-D seismic data will enhance our probability of
drilling success. We continue to evaluate the 3-D seismic data to identify additional drilling locations. During
2007 at East Hackberry, we drilled nine wells in Lake Calcasieu and three wells on land and recompleted two
existing wells. Of the 12 wells drilling during 2007, ten were completed as producing wells and two were
non-productive. As of March 1, 2008 at East Hackberry, we had drilled one additional well in Lake Calcasieu,
which is now producing, and had recompleted three existing wells. We intend to drill three to five additional land
wells and recomplete one additional well at East Hackberry during 2008. Drilling activity in this field during
2008 will target measured depths of up to 13,000 feet using directional drilling techniques.
Production Status
In December 2007, net production at East Hackberry was 26,850 BOE, or an average of 867 BOE per day,
70% of which was from oil and 30% of which was from natural gas. In February 2008, our average net daily
production at East Hackberry was 735 BOE, 80% of which was from oil and 20% of which was from natural gas.
West Hackberry Field
Location and Land
The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish,
Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a
100% working interest (approximately 87.5% NRI) in 592 acres within the West Hackberry field. Our leases at
West Hackberry are located within two miles of one of the United States Department of Energy’s Strategic
Petroleum Reserves.
Area History
The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil
Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate
production through 2007 was 227 MBOE and 140 Bcf of natural gas. There have been 36 wells drilled to date on
our portion of West Hackberry. Currently, three are producing, 24 are shut-in and one has been converted to a
saltwater disposal well. The remaining eight wells have been plugged and abandoned.
6
Geology
Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There
are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in the
Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these
thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE.
Production Status
In December 2007, net production at West Hackberry was 641 BOE, or 21 BOE per day. In February 2008,
our average net daily production at West Hackberry was 21 BOE.
Facilities
We have land-based production and processing facilities located at the West Hackberry field and maintain a
field office that serves both the East and West Hackberry fields.
Permian Basin (West Texas)
Location and Land
We acquired approximately 4,100 net acres in West Texas (near Midland) in the Permian Basin on
December 20, 2007, effective date as of November 1, 2007, from ExL Petroleum, LP and certain other sellers.
The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered
one of the major producing basins in the United States. The terrain in the Permian Bain is semi-arid mesquite-
mixed grassland steppe.
Area History
The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of
the Ouachita Foldbelt. The Wolfcamp play was a long-established reservoir in West Texas, first found in the
1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir
properties. Exploration with 2-D seismic located additional fields, but it was not until the use of 3-D seismic in
the 1990s that the greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a
drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 feet to pick
up the upper part of the Wolfcamp formation. Henry Petroleum, a private firm, owned interest in the Pegusas
field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry decided to drill
completely through the Wolfcamp section as Devonian wells. Henry mapped the trend and began acquiring
acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former
members of Henry’s Wolfcamp team formed their own private company, ExL Petroleum, and began replicating
Henry’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they
decided to monetize approximately 15% of their acreage position which enabled us to participate in this play.
Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration
and production companies. Currently, we hold interests in thirty-two gross producing wells.
Geology
The Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where
the historically productive Spraberry trend geographically overlaps the productive area of the emerging
Wolfcamp carbonate play. The Wolfcamp is characterized by an approximately 2,000 feet section of organic rich
basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is
generally found in close proximity to the Central Basin Platform.
7
Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20% from the
Spraberry section, consisting of approximately 64% oil, 23% natural gas liquids, and 13% natural gas. Pinnacle
Energy Services, LLC, an independent petroleum engineering firm, has estimated that at December 31, 2007,
proved reserves net to our interest in these assets were approximately 6.6 million BOE, of which 19.5% were
classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this
estimate were from 92 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp
and Spraberry formations, which are generally characterized as long-lived, with predictable production profiles.
Wells to be drilled will be approximately 10,200 feet at an estimated average gross completed well cost of $1.7
million. The gross estimated ultimate recovery, or EUR, as estimated by Pinnacle Energy Services, LLC, is
expected to average gross 146,000 BOE per well with an average net revenue interest in the field of
approximately 75%. We have a 50% working interest and approximately 37.5% net revenue interest in the field.
Production Status
At the date of acquisition, there was production of approximately 800 net BOE a day from 32 gross,
producing wells. During February 2008, average net production to Gulfport was 531 BOE a day.
Facilities
There are typical land oil and gas processing facilities in the Permian Basin. Our facilities located at well
locations include storage tank batteries, oil/gas/water separation equipment and pumping units.
Recent and Future Activity
We have identified 178 gross future development drilling locations. We expect approximately 17 to 22 net
wells to be drilled in 2008. The wells are expected to be drilled to approximately 10,200 feet at an estimated
average gross completed well cost of $1.7 million.
Additional Properties
Louisiana. In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also
own working interests and overriding royalty interest in various fields in Louisiana as described in the following
table:
Field
Parish
Acreage Working
Interest
Overriding Royalty
Interests
Producing
Wells
Non-Producing
Wells
Iberia
. . . . . . Terrebonne
Bayou Long . . . . . . . . . .
Bayou Penchant
Bayou Pigeon . . . . . . . .
Deer Island . . . . . . . . . . Terrebonne
Golden Meadow . . . . . . Lafourche
Napoleonville . . . . . . . . Assumption
Iberia
3.125%
3.125%
6.250%
6.250%
3.125%
0%
0%
0%
0%
0%
0%
2.5%
0
2
5
0
0
3
0
5
5
6
1
0
Thailand. During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex, at a
cost of $2,400,000. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, a
privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an
international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its
ownership of concessions covering three million acres which includes the Phu Horm Field. During the year
ended December 31, 2007, we paid $88,000 in cash calls, bringing our total investment in Tatex (including
previous investments) to $3,553,000. Our investment is accounted for on the equity method. Tatex accounts for
its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm
field located in northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet
per day. Current net production is approximately 100 Mcf per day. Hess Corporation operates the field with a
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35% interest. Other interest owners include APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10%
interest). Our gross working interest (through Tatex as a member of APICO) in the Phu Horm field is 0.7%.
Proved reserves from the Phu Horm field, net to our interest, are 3.5 BCF of gas and 10,000 barrels of oil. Due to
the fact that our ownership in the Phu Horm field is indirect and Tatex’s investment in APICO is accounted for
by the cost method, these reserves are not included in our year-end reserve information.
Williston Basin. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken.
The remaining interests in Bakken are owned by entities controlled by Wexford. In 2005 and 2006, Bakken
acquired leases on undeveloped acreage in the Williston Basin areas of western North Dakota and eastern
Montana. At December 31, 2007, our net investment in Bakken was $2,468,000. We are currently participating
in the drilling of nine wells and have interests in eight producing wells with an average working interest of
1.55%.
Marquiss Field. In February 2005, but effective as of December 1, 2004, we acquired our interest in the
Marquiss field, an approximately 9,500 net acre coalbed methane play in Campbell County, Wyoming, for
$375,000. As of December 31, 2006, the Marquiss field included a total of 162 wells, all of which were shut-in as
a result of the economic status of the field as a result of a decline in natural gas prices for this field. The wells
(when on line) produced from multiple horizons with additional upside potential from deeper coals and
operational efficiencies. Our interest in the Marquiss field was sold in February 2007 for $500,000.
Grizzly Oil Sands. During the third quarter of 2006, we, through our wholly owned subsidiary Grizzly
Holdings Inc., purchased a 24.9999% interest in Grizzly. The remaining interests in Grizzly are owned by entities
controlled by Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the
Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately
511,000 acres under lease and our total net investment in Grizzly was $27,801,000 at December 31, 2007.
Grizzly drilled 62 core holes during the 2006/2007 winter delineation drilling season and tested three separate
lease blocks using up to four different rigs. Future plans currently include acquiring additional leases, drilling
approximately 55 to 60 additional core holes and a seismic program during the 2007/2008 winter drilling season
and initial planning for the construction of a 10,000 barrel per day SAGD facility that could lead to initial
production in 2011. Gross capital expenditures for such a production facility are currently estimated to be
approximately $325 million.
Competition and Markets
The oil and natural gas industry is intensely competitive, and we compete with other companies that have
greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry
on midstream and refining operations and market petroleum and other products on a regional, national or
worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to
withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the
availability of alternative energy sources and the application of government regulation.
The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors
beyond the control of our management, including but not limited to the extent of domestic production and
imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and
equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of
gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who
service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell.
Shell takes custody of the oil at the outlet from our oil storage barge. Our production is being sold in accordance
with the posted price for West Texas/New Mexico Intermediate crude plus Platt’s trade month average P+ value,
plus or minus the Platt’s WII/LLS differential less $3.70 per barrel for transportation. During 2007, we sold 99%
of our oil production to Shell and 69% of our natural gas production to Chevron and 23% of our natural gas
production to Hilcorp Energy Company and during 2006, we sold 100% of our oil production to Shell and 96%
9
of our natural gas production to Chevron. During 2005, we sold 99% of our oil production to Shell and 88% of
our natural gas production to Chevron. There can be no assurance, however, that we will continue to have ready
access to suitable markets for our future oil and natural gas production.
Oil and natural gas prices can be extremely volatile and are subject to substantial seasonal, political and
other fluctuations. The prices at which the oil and natural gas we produce may be sold is uncertain and it is
possible that under some market conditions the production and sale of oil and natural gas from some or all of our
properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is
impossible to accurately predict future prices.
To mitigate the effects of commodity price fluctuations, during 2007, we entered into forward sales
contracts for the sale of 3,000 barrels of production per day for the month of June 2007 at a weighted average
daily price of $70.15 per barrel before transportation costs. For the period of July 2007 through December 2007,
we entered into forward sales contracts for the sale of 3,500 barrels of production per day at a weighted average
daily price of $70.29 per barrel before transportation costs. In addition, we have entered into agreements to sell
3,500 barrels of production per day for the months of January through May 2008 at a weighted average daily
price of $70.29 per barrel before transportation costs. For the month of June 2008, we have agreements to sell
3,500 barrels of production per day at a weighted average daily price of $71.69 per barrel before transportation
costs. For the month of July 2008, we have agreements to sell 3,000 barrels of production per day at a weighted
average daily price of $81.37 per barrel before transportation costs. For August 2008, we have agreements to sell
3,000 barrels of production per day at a weighted average daily price of $82.44 per barrel before transportation
costs. For the periods of September 2008 through December 2008, we have entered into forward sales contracts
for the sale of 3,000 barrels of production per day in each such period at weighted average daily prices of $82.20
per barrel before transportation costs. Under these agreements we have committed to deliver approximately 60%
of our estimated production for January through December 2008. For the period of January through December
2009, we entered into agreements to sell 2,500 barrels of production per day at a weighted average daily price of
$84.62 per barrel before transportation costs. Such arrangements may expose us to risk of financial loss in certain
circumstances, including instances where production is less than expected or oil prices increase. These contracts
require physical delivery of production quantities and are exempted from the provisions of SFAS 133 as normal
sales of production. In addition, these arrangements may limit the benefit to us of increases in the price of oil.
Regulation
Regulation of Gas and Oil Production
Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other
legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and
natural gas industry is under constant review for amendment or expansion. Some of these requirements carry
substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our
cost of doing business and, consequently, affects our profitability.
We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf
Coast and West Texas. These states regulate the production and sale of oil and natural gas, including
requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation
of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural
gas resources could affect the rate of production and may include maximum daily production allowables for
wells on a market demand or conservation basis.
Environmental Regulation
Our oil and natural gas exploration, development and production operations are subject to stringent federal,
state and local laws and regulations governing the discharge of materials into the environment or otherwise
relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental
Protection Agency, or EPA, issue regulations to implement and enforce such laws, which often require difficult
10
and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result
in injunctive obligations for failure to comply. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities and concentrations of various substances that can be
released into the environment in connection with drilling and production activities, limit or prohibit construction
or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected
areas, require action to prevent or remediate pollution from current or former operations, such as plugging
abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations. The
strict liability nature of such laws and regulations could impose liability upon us regardless of fault. Changes in
environmental laws and regulations occur frequently, and any changes that result in more stringent and costly
waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our
operations and financial position, as well as the oil and natural gas industry in general. Our management believes
that we are in substantial compliance with current applicable environmental laws and regulations and we have
not experienced any material adverse effect from compliance with these environmental requirements; this trend,
however, may not continue in the future.
Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes
and regulations promulgated thereunder, affect oil and natural gas exploration, development and production
activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and
cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or
all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although
most wastes associated with the exploration, development and production of crude oil and natural gas are exempt
from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to
the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the
EPA or the state or local governments will not adopt more stringent requirements for the handling of
non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed,
legislation has been proposed from time to time to re-categorize certain oil and natural gas exploration,
development and production wastes as “hazardous wastes.”
Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling
requirements. We believe that we are in substantial compliance with the requirements of RCRA and related state
and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other
authorizations to the extent that our operations require them under such laws and regulations. Although we do not
believe that the current costs of managing our wastes as they are presently classified to be significant, any
legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase
our costs to manage and dispose of such wastes.
Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive
Environmental Response, Compensation and Liability Act, also known as CERCLA or the “Superfund” law,
generally imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons
who are considered to be responsible for the release of a “hazardous substance” into the environment. These
persons include the current owner or operator of a contaminated facility, a former owner or operator of the
facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous
substance. Under CERCLA and comparable state statutes, such persons may be subject to strict joint and several
liability for the costs of cleaning up the hazardous substances that have been released into the environment, for
damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for
neighboring landowners and other third parties to file claims for personal injury and property damage allegedly
caused by the hazardous substances released into the environment. In the course of our operations, we use
materials, that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental
agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or
part of the costs to clean up sites at which such “hazardous substances” have been deposited.
11
Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean
Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose
restrictions and strict controls regarding the discharge of pollutants, including produced waters and other gas and
oil wastes, into state waters or waters of the United States. The discharge of pollutants into regulated waters is
prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These proscriptions
also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of
Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production
facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater
or developing and implementing storm water pollution prevention plans. We believe that we have obtained or
applied for and are in substantial compliance with all permits required under the Clean Water Act. Sanctions for
failure to comply with Clean Water Act requirement include administrative, civil and criminal penalties, as well
as injunctive obligations.
Air Emissions. The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of
various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has
developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified
sources. Some of our new facilities will be required to obtain permits before work can begin, permits may be
required for our facilities’ operations, and existing facilities may be required to incur capital costs to remain in
compliance. These laws and regulations may increase the costs of compliance for some facilities we own or
operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for
non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and
regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and
that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing
permits has the potential to delay the development of oil and natural gas projects.
Operational Hazards and Insurance
Our operations are subject to all of the risks normally incident to the production of oil and natural gas,
including blowouts, cratering, pipe failure, casing collapse, oil spills and fires, each of which could result in
severe damage to or destruction of oil and natural gas wells, production facilities or other property, or injury to
persons. The energy business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures
and discharge of toxic substances or gases that could expose us to substantial liability due to pollution and other
environmental damage and consequences thereof, including personal injuries and property damage. We currently
maintain insurance covering some, but not all of these risks. The occurrence of a significant event that is not fully
insured against could have a material adverse effect on our financial position.
Headquarters and Other Facilities
We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as
our corporate headquarters. We lease a portion of this office space to certain of our affiliates. We also own an
approximately 12,500 square foot building in Lafayette, Louisiana that is leased to an unrelated third party. This
building contains approximately 6,200 square feet of finished office area and 6,300 square feet of clear span
warehouse area. We also lease 3,722 square feet in a building in Lafayette that we use as our Louisiana
headquarters. Each of these properties is suitable and adequate for its use.
Employees
At December 31, 2007, we had 70 employees. Certain of our employees perform management and
administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and
benefits of these individuals based on the estimated time they spent working for those affiliates. In addition, in
the past, we have also received 100% of the COPAS overhead charges billed to these affiliated companies. For
the years ended December 31, 2007 and 2006, expenses reimbursed to us under these arrangements were
12
$11,153,000 and $12,738,000, respectively, and are reflected as a reduction in our general and administrative
expenses. A Louisiana well servicing company provides all necessary field personnel needed to operate the
WCBB and the Hackberry fields.
Available Information
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 filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made
available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as
reasonably practicable after such material is electronically filed with, or furnished to, the Securities and
Exchange Commission, or SEC. Information contained on our website, or on other websites that may be linked to
our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered
part of this report or any other filing that we make with the SEC.
ITEM 1A. RISK FACTORS
Risks Related to Our Business and Industry
The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability.
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and
natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and
natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand,
market uncertainty and a variety of additional factors that are beyond our control, including:
• worldwide and domestic supplies of oil and natural gas;
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the level of prices, and expectations about future prices, of oil and natural gas;
the cost of exploring for, developing, producing and delivering oil and natural gas;
the expected rates of declining current production;
• weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area;
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the level of consumer demand;
the price and availability of alternative fuels;
technical advances affecting energy consumption;
risks associated with operating drilling rigs;
the availability of pipeline capacity;
the price and level of foreign imports;
domestic and foreign governmental regulations and taxes;
the ability of the members of the Organization of Petroleum Exporting Countries to agree to and
maintain oil price and production controls;
political instability or armed conflict in oil and natural gas producing regions; and
the overall economic environment.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and
natural gas price movements with any certainty. For example, the West Texas Intermediate posted price for crude
oil has ranged from a low of $30.83 per barrel, or bbl, in January 2004 to a high of $102.20 per bbl on March 6,
2008. The Henry Hub spot market price of natural gas has ranged from a low of $4.20 per million British thermal
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units, or MMBtu, in October 2006 to a high of $13.93 per MMBtu in October 2005. On December 31, 2007, the
West Texas Intermediate posted price for crude oil was $92.50 per bbl and the Henry Hub spot market price of
natural gas was $6.80 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a
material adverse effect on our operations, financial condition and level of expenditures for the development of
our oil and natural gas reserves, and may result in write downs of oil and natural gas properties due to ceiling test
limitations.
Our success depends on finding, developing or acquiring additional reserves.
Our future success depends upon our ability to find, develop or acquire additional oil and natural gas
reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted,
except to the extent that we conduct successful exploration or development activities or acquire properties
containing proved reserves, or both. To increase reserves and production, we undertake development, exploration
and other replacement activities or use third parties to accomplish these activities. We make and expect to
continue to make substantial capital expenditures in our business and operations for the development, production,
exploration and acquisition of oil and natural gas reserves. To date, we have financed capital expenditures
primarily with cash flow from operations, the issuance of equity securities and borrowings under our bank and
other credit facilities. Our cash flow from operations and access to capital are subject to a number of variables,
including:
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our proved reserves;
the level of oil and natural gas we are able to produce from existing wells;
the prices at which oil and natural gas are sold; and
our ability to acquire, locate and produce new reserves.
We cannot assure you that we will have sufficient resources to undertake our exploration and development
activity, production and acquisition of oil and natural gas reserves, that our exploratory projects or other
replacement activities will result in significant additional reserves or that we will have success drilling productive
wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil
and natural gas prices increase significantly, our finding costs for additional reserves could also increase.
Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could
reduce our earnings and slow our growth.
There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may
increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is
dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases,
regulatory approvals. Completed acquisitions could require us to invest further in operational, financial and
management information systems and to attract, retain, motivate and effectively manage additional employees.
The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent
acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our
financial position and results of operations may fluctuate significantly from period to period, based on whether or
not significant acquisitions are completed in particular periods.
Our Canadian oil sands project is a complex undertaking and may not be completed on schedule or at budgeted
cost or at all.
During the third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings Inc., purchased
a 24.9999% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford.
During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort
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McMurray near other oil sands development projects. Grizzly has approximately 511,000 acres under lease and
as of December 31, 2007, our total net investment in Grizzly was approximately $27.8 million. Grizzly drilled 62
core holes during the 2006/2007 winter delineation drilling season and tested three separate lease blocks using up
to four different rigs. Future plans currently include acquiring additional leases, drilling approximately 55 to 60
additional core holes and a seismic program during the 2007/2008 winter drilling season and initial planning for
the construction of a 10,000 barrel per day SAGD facility that could lead to initial production in 2011. Gross
capital expenditures for such a production facility are currently estimated to be approximately $325 million. This
is a complex project and financing has not yet been secured. There can be no assurance that this project can be
completed on schedule, at our estimated cost or at all.
Shortage of rigs, equipment, supplies or personnel may restrict our operations.
The oil and natural gas industry is cyclical, and at the present time there is a shortage of drilling rigs,
equipment, supplies and personnel. The costs and delivery times of rigs, equipment and supplies has increased as
drilling activities have increased. In addition, demand for, and wage rates of, qualified drilling rig crews have
risen with increases in the number of active rigs in service. In accordance with customary industry practice, we
rely on independent third party service providers to provide most of the services necessary to drill new wells.
Shortages of drilling rigs, equipment, supplies, personnel, trucking services, tubulars, fracing and completion
services and production equipment could delay or restrict our exploration and development operations, which in
turn could impair our financial condition and results of operations.
We rely on a few key employees whose absence or loss could disrupt our operations resulting in a loss of
revenues.
Many key responsibilities within our business have been assigned to a small number of employees. The loss
of their services, particularly the loss of Mike Liddell, our Chairman of the Board, James D. Palm, our Chief
Executive Officer, Michael G. Moore, our Chief Financial Officer, or our two geophysicists, Stuart Maier and
Randy Wilson, could disrupt our operations resulting in a loss of revenues. We do not have an employment
contract with any of our executives, with the exception of Mr. Liddell, and our executives are not restricted from
competing with us if they cease to be employed by us. Additionally, as a practical matter, any employment
agreement we may enter into will not assure the retention of our employees. In addition, we do not maintain “key
person” life insurance policies on any of our employees. As a result, we are not insured against any losses
resulting from the death of our key employees.
Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual production.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future
rates of production and timing of expenditures, including many factors beyond our control. The reserve information
incorporated by reference in this prospectus represents only estimates based on reports prepared by Netherland,
Sewell & Associates, Inc. as of December 31, 2007 with respect to our WCBB field, by Pinnacle Energy Services,
LLC with respect to our assets in the Permian Basin in West Texas and by our personnel with respect to our
Hackberry fields and our overrides and non-operated interests. Petroleum engineering is not an exact science.
Information relating to our proved oil and natural gas reserves is based upon engineering estimates. Estimates of
economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a
number of variable factors and assumptions, such as historical production from the area compared with production
from other producing areas, future site restoration and abandonment costs, the assumed effects of regulations by
governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs,
severance and excise taxes, capital expenditures and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and
natural gas attributable to any particular group of properties, classifications of such reserves based on risk of
recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the
same engineers at different times may vary substantially. Actual production, revenues and expenditures with respect
to our reserves will likely vary from estimates, and such variances may be material.
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The present value of future net revenues 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 revenue
from our proved reserves on prices and costs in effect on the day of estimate. However, actual future net revenues
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;
the amount and timing of actual production;
supply of and demand for oil and natural gas; and
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of costs in connection with the development and
production of oil and natural gas properties will affect the timing of actual future net revenues 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.
There are numerous uncertainties inherent in estimating quantities of bitumen reserves and resources and no
assurance can be given that indicated level of reserves or recovery of bitumen will be realized.
There are numerous uncertainties inherent in estimating quantities of bitumen reserves and resources,
including many factors beyond our or Grizzly’s control, and no assurance can be given that the indicated level of
reserves or recovery of bitumen will be realized. In general, estimates of economically recoverable bitumen
reserves and the future net cash flow from such reserves are based upon a number of factors and assumptions
made as of the date on which the reserve and resource estimates were determined, such as geological and
engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental
agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from
actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts
to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable
bitumen, the classification of such reserves based on risk of recovery and estimates of future net revenues
expected therefrom, prepared by different engineers or by the same engineers at different times, may vary
substantially.
Estimates with respect to reserves and resources that may be developed and produced in the future are often
based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual
production history. Estimates based on these methods generally are less reliable than those based on actual
production history. Subsequent evaluation of the same reserves based upon production history may result in
variations in the estimated reserves. Reserve and resource estimates may require revision based on actual
production experience. Reserve and resources estimates are determined with reference to assumed oil prices and
operating costs. Market price fluctuations of oil prices may render uneconomic the recovery of certain grades of
bitumen. No assurance can be provided as to the gravity or quality of bitumen to be produced from Grizzly’s
lands.
The marketability of our production is dependent upon compressors, gathering lines, transportation barges and
other facilities, certain of which we do not control. When these facilities are unavailable, our operations can be
interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and
capacity of natural gas lines and transportation barges owned by third parties. In general, we do not control these
transportation facilities and our access to them may be limited or denied due to circumstances beyond our
control. A significant disruption in the availability of these transportation facilities or our compression and other
production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and
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thereby cause a significant interruption in our operations. We are at particular risk with respect to oil and natural
gas produced at our WCBB field, which is our largest field. In October 2006, for example, a natural gas line in
this field operated by our natural gas purchaser was ruptured by a third party contractor, requiring the field to be
shut in for approximately seven weeks until the line could be repaired. Further, we are dependent on our oil
purchaser to provide the barges necessary to transport our oil production from the WCBB field. The increasing
demand for transportation barges in the Louisiana Gulf Coast region has adversely impacted our ability to
transport our oil production from the tank batteries in our field to shore for delivery. This has required us to shut
in or curtail production from time to time as we have only limited storage capacity in the field. If, in the future,
we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or
encounter compression or other production related difficulties, we will be required to again shut in or curtail
production from the field. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery
of the oil and natural gas produced from the field, would adversely affect our financial condition and results of
operations.
Substantially all of our producing properties are located in Louisiana, making us vulnerable to risks associated
with operating in this region.
Our operations are concentrated in Louisiana and our largest field, WCBB, is located approximately five
miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. As a result, we
may be disproportionately exposed to the impact of delays or interruptions of production from this region caused
by weather conditions such as fog or rain, hurricanes or other natural disasters, or lack of field infrastructure.
Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We cannot
assure you that we will be able to obtain and maintain adequate insurance at rates we consider reasonable or that
any particular types of coverage will be available.
Our identified drilling locations comprise an estimation of part of our future drilling plans over several years,
making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
We have identified over 200 drilling locations on our Louisiana properties. These drilling locations
represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a
number of uncertainties, including the availability of capital, oil and natural gas prices, inclement weather, costs
and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations
we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other
potential drilling locations. As such, our actual drilling activities may materially differ from those presently
identified, which could adversely affect our business.
Operating hazards and uninsured risks may result in substantial losses.
Our operations are subject to all of the hazards and operating risks inherent in drilling for and production of
oil and natural gas, including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations
and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. The occurrence of
any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or
destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up
responsibilities, regulatory investigation and penalties and suspension of operations. For example, in October
2006, an accident occurred north of our production facilities in the WCBB field in southern Louisiana involving
two contracted vessels that were performing work on our behalf in the field. A tugboat and two barges laden with
construction materials ruptured an underwater natural gas pipeline and a subsequent fire damaged the vessels. Six
fatalities resulted from the accident. Several lawsuits relating to this incident have been filed against us, among
other parties. Information with respect to this litigation is incorporated by reference in this Form 10-K. Litigation
is inherently uncertain and its outcome cannot be predicted at this time; however, if this litigation is not resolved
in a manner that is favorable to us, our financial condition and results of operations may be negatively impacted.
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In accordance with customary industry practice, we historically have maintained insurance against some,
but not all, of our business risks. We cannot assure you that our insurance will be adequate to cover any losses or
liabilities we may suffer. We also cannot predict the continued availability of insurance, or its availability at
premium levels that justify its purchase. In addition, we understand that insurance carriers are modifying or
otherwise restricting insurance coverage or ceasing to provide certain types of insurance coverage in the Gulf
Coast region. We may also be liable for environmental damage caused by previous owners of properties
purchased by us, which liabilities may not be covered by insurance.
Our operations are subject to various governmental regulations which require compliance that can be
burdensome and expensive.
Our oil and natural gas operations are subject to various federal, state and local governmental regulations
that may be changed from time to time in response to economic and political conditions. Matters subject to
regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the
spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have
imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells
below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling,
storage, transportation, emission and disposal of oil and gas, by-products thereof and other substances and
materials produced or used in connection with oil and natural gas operations are subject to regulation under
federal, state and local laws and regulations relating to protection of human health and the environment. These
laws and regulations have continually imposed increasingly strict requirements for water and air pollution control
and waste management. Significant expenditures may be required to comply with governmental laws and
regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and
regulations will continue.
We face extensive competition in our industry.
The oil and natural gas industry is intensely competitive, and we compete with other companies that have
greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry
on midstream and refining operations and market petroleum and other products on a regional, national or
worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to
withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the
availability of alternative energy sources and the application of government regulation.
We depend upon two customers for the sale of most of our oil and natural gas production.
The availability of a ready market for any oil and natural gas we produce depends on numerous factors
beyond the control of our management, including but not limited to the extent of domestic production and
imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and
equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of
gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who
service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell.
Shell takes custody of the oil at the outlet from our oil storage barge. At December 31, 2007, our WCBB
production was being sold in accordance with the posted price for West Texas/New Mexico Intermediate crude
plus Platt’s trade month average P+ value, plus or minus the Platt’s WII/LLS differential less $3.70 per Bbl for
transportation. For the year ended December 31, 2007 and the year ended December 31, 2006, we sold
approximately 99% and 100%, respectively, of our oil production to Shell and 69% and 96%, respectively, of our
natural gas production to Chevron. During 2007, we sold approximately 23% of our natural gas production to
Hilcorp Energy Company. During 2005, we sold 99% of our oil production to Shell and 88% of our natural gas
production to Chevron. There can be no assurance that we will continue to have ready access to suitable markets
for our future oil and natural gas production.
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Our method of accounting for oil and natural gas properties may result in impairment of asset value.
We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs,
including nonproductive costs and certain general and administrative costs associated with acquisition,
exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to
the estimated future net revenues, after income taxes, discounted at 10% per year, from proven oil and natural
gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the
estimated future development costs and site remediation costs, if any, are depleted by an equivalent
units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil.
Companies that use the full cost method of accounting for oil and gas properties are required to perform a
ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties.
Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center
ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per
annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for any contract
provisions or financial derivatives, if any, that hedge oil and natural gas revenue, and excluding the estimated
abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of
properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included
in the cost being amortized, less income tax effects related to differences between the book and tax basis of the
oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability
exceeds the ceiling, an impairment or noncash writedown is required. A ceiling test impairment can give us a
significant loss for a particular period. Once incurred, a write down of oil and natural gas properties is not
reversible at a later date, even if oil or gas prices increase.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of
oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only
tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not
enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use
of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling
strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not
be successful or economical.
We have entered into forward sales contracts and may in the future enter into additional contracts for a portion
of our production, which may result in our making cash payments or prevent us from receiving the full benefit of
increases in prices for oil and gas.
To reduce our exposure to short-term fluctuations in the price of oil and natural gas, we periodically enter
into hedging arrangements. Currently, we have entered into agreements to sell 3,500 barrels of production per
day for the months of January through May 2008 at a weighted average daily price of $70.29 per barrel before
transportation costs. For the month of June 2008, we have agreements to sell 3,500 barrels of production per day
at a weighted average daily price of $71.69 per barrel before transportation costs. For the month of July 2008, we
have agreements to sell 3,000 barrels of production per day at a weighted average daily price of $81.37 per barrel
before transportation costs. For August 2008, we have agreements to sell 3,000 barrels of production per day at a
weighted average daily price of $82.44 per barrel before transportation costs. For the periods of September 2008
through December 2008, we have entered into forward sales contracts for the sale of 3,000 barrels of production
per day in each such period at weighted average daily prices of $82.20 per barrel before transportation costs.
Under these agreements we have committed to deliver approximately 60% of our estimated production for
January through December 2008. For the period of January through December 2009, we entered into agreements
to sell 2,500 barrels of production per day at a weighted average daily price of $84.62 per barrel before
transportation costs. Such arrangements may expose us to risk of financial loss in certain circumstances,
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including instances where production is less than expected or oil prices increase. These contracts require physical
delivery of production quantities and are exempted from the provisions of SFAS 133 as normal sales of
production. In addition, these arrangements may limit the benefit to us of increases in the price of oil.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other
countries may adversely affect the United States and global economies and could prevent us from meeting our
financial and other obligations. If any of these events occur, the resulting political instability and societal
disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand
for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct
targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our
customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of
these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to
oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand
for oil and natural gas. Management cannot predict the impact of the changing demand for oil and gas services
and products, and any major changes may have a material adverse effect on our business, financial condition,
results of operations and cash flows.
We are subject to the requirements of Section 404 of the Sarbanes-Oxley Act. If the costs related to such
compliance are significant, our profitability, stock price and results of operations and financial condition could
be materially adversely affected.
Commencing with our fiscal year ended December 31, 2007, we became subject to Section 404 of the
Sarbanes-Oxley Act of 2002, or Section 404, which requires that we document and test our internal control over
financial reporting and issue management’s assessment of our internal control over financial reporting. This
section also requires that our independent registered public accounting firm audit our internal control over
financial reporting. We are required to evaluate our existing controls against the criteria established in Internal
Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission, or COSO. The out-of-pocket costs, the diversion of management’s attention from running the
day-to-day operations and operational changes caused by the need to comply with the requirements of
Section 404 have been significant. If the future time and costs associated with such compliance exceed our
current expectations, our results of operations could be adversely affected. If we fail to fully comply with the
requirements of Section 404 or if we determine that we have a material weakness or significant deficiencies, or if
our auditors disagree with our assessment in connection with the presentation of our financial statements, the
accuracy and timeliness of the filing of our periodic reports may be materially adversely affected and could cause
investors to lose confidence in our reported financial information, which could have a negative effect on the
trading price of our common stock. In addition, a material weakness or significant deficiency in our internal
control over financial reporting could result in an increased chance of fraud, reduce our ability to obtain
financing and require additional expenditures to comply with these requirements, each of which could have a
material adverse effect on our business, results of operations and financial condition.
Due to inherent limitations, there can be no assurance that our system of disclosure and internal controls and
procedures will be successful in preventing all errors and fraud, or in making all material information known in
a timely manner to management.
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that
our disclosure controls and internal controls will prevent all errors and fraud. A control system, no matter how
well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the
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control system are met. Further, the design of a control system must reflect the fact that there are resource
constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent
limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues
and instances of fraud, if any, within our company have been detected. These inherent limitations include the
realities that judgments in decision making can be faulty, and that breakdowns can occur because of simple error
or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of
two or more people, or by management override of the control.
The design of any system of controls also is based in part upon certain assumptions about the likelihood of
future events, and there can be no assurance that any design will succeed in achieving its stated goals under all
potential future conditions. Over time, a control may become inadequate because of changes in conditions, or the
degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a
cost effective control system, misstatements due to error or fraud may occur and not be detected that could have a
material adverse effect on our business, results of operations and financial condition.
Risks Related to Our Common Stock
If our quarterly revenues and operating results fluctuate significantly, the price of our common stock may be
volatile.
Our revenues and operating results may in the future vary significantly from quarter to quarter. If our
quarterly results fluctuate, it may cause our stock price to be volatile. We believe that a number of factors could
cause these fluctuations, including:
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changes in oil and natural gas prices;
changes in production levels;
changes in governmental regulations and taxes;
geopolitical developments;
the level of foreign imports of oil and natural gas; and
conditions in the oil and natural gas industry and the overall economic environment.
Because of the factors listed above, among others, we believe that our quarterly revenues, expenses and
operating results may vary significantly in the future and that period-to-period comparisons of our operating
results are not necessarily meaningful. You should not rely on the results of one quarter as an indication of our
future performance. It is also possible that in some future quarters, our operating results will fall below our
expectations or the expectations of market analysts and investors. If we do not meet these expectations, the price
of our common stock may decline significantly.
Our officers and directors together with our largest stockholder control a significant percentage of our common
stock, and their interests may conflict with those of our other stockholders.
As of December 31, 2007, our executive officers and directors, in the aggregate, beneficially owned
approximately 4% of our outstanding common stock and Charles E. Davidson, one of our major stockholders,
beneficially owned approximately 36% of our outstanding common stock. As a result, these stockholders acting
together are able to exercise significant influence over most matters requiring approval by our stockholders,
including the election of directors and the approval of significant corporate transactions. Such a concentration of
ownership may have the effect of delaying or preventing a change in control of us, including transactions in
which stockholders might otherwise receive a premium for their shares over then current market prices.
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We can give no assurances as to the market for our common stock.
Since July 14, 2006, our common stock has been listed on The NASDAQ Global Select Market under the
symbol “GPOR.” From February 28, 2006 until that date, our common stock was listed on the NASDAQ
National Market. Prior to that date, our common stock was traded on the NASD OTC Bulletin Board under the
symbol “GPOR.OB.” There is a limited market for our shares. We cannot assure you that an active trading
market will develop, or if it does, that it will be sustained.
We do not currently pay dividends on our common stock and do not anticipate doing so in the future.
We have paid no cash dividends on our common stock, and there can be no assurance that we will achieve
sufficient earnings to pay cash dividends on our common stock in the future. We intend to retain any earnings to
fund our operations. Therefore, we do not anticipate paying any cash dividends on our common stock in the
foreseeable future. In addition, the terms of our credit agreement prohibit the payment of any dividends to the
holders of our common stock.
A change of control could limit our use of net operating losses.
As of December 31, 2007, we had a net operating loss, or NOL, carry forward of approximately $93 million
for federal income tax purposes. Transfers of our stock in the future could result in an ownership change. In such
a case, our ability to use the NOLs generated through the ownership change date could be limited. In general, the
amount of NOLs we could use for any tax year after the date of the ownership change would be limited to the
value of our stock (as of the ownership change date) multiplied by the long-term tax-exempt rate.
Future sales of our common stock may depress our stock price.
We and certain of our stockholders have registered a substantial number of shares of our common stock
under a registration statement filed with the SEC. Sales of these shares of our common stock in the public
market, or the perception that these sales may occur, could cause the market price of our common stock to
decline. In addition, sales by certain of our stockholders of their shares could impair our ability to raise capital
through the sale of common or preferred stock. As of March 3, 2008, there were 42,550,031 shares of our
common stock issued and outstanding, excluding 77,210 shares of restricted stock awarded under our 2005 Stock
Incentive Plan.
We could issue preferred stock which could be entitled to dividend, liquidation and other special rights and
preferences not shared by holders of our common stock or which could have anti-takeover effects.
We are authorized to issue up to 5,000,000 shares of preferred stock, par value $0.01 per share. Shares of
preferred stock may be issued from time to time in one or more series as our board of directors, by resolution or
resolutions, may from time to time determine each such series to be distinctively designated. The voting powers,
preferences and relative, participating, optional and other special rights, and the qualifications, limitations or
restrictions, if any, of each such series of preferred stock may differ from those of any and all other series of
preferred stock at any time outstanding, and, subject to certain limitations of our certificate of incorporation and
the Delaware General Corporation Law, or DGCL, our board of directors may fix or alter, by resolution or
resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other
special rights, and qualifications, limitations and restrictions thereof, of each such series preferred stock. The
issuance of any such preferred stock could materially adversely affect the rights of holders of our common stock
and, therefore, could reduce the value of our common stock.
In addition, specific rights granted to future holders of preferred stock could be used to restrict our ability to
merge with, or sell our assets to, a third party. The ability of our board of directors to issue preferred stock could
discourage, delay or prevent a takeover of us, thereby preserving control of the company by the current
stockholders.
22
The existence of some provisions in our organizational documents could delay or prevent a change in
control of our company, even if that change would be beneficial to our stockholders. Our certificate of
incorporation and bylaws contain provisions that may make acquiring control of our company difficult.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
Proved Oil and Natural Gas Reserves
The oil and natural gas reserve information set forth below represents estimates of our proved oil and
natural gas reserves as prepared by the independent engineering firm of Netherland, Sewell & Associates, Inc., or
NSAI, with respect to WCBB, our primary field, as prepared by Pinnacle Energy Services, LLC with respect to
our assets in the Permian Basin in West Texas and by our personnel with respect to our other interests. Reserve
engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that
cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation. As a result, the estimates of different engineers
often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates.
Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately
recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a
number of variables and assumptions, all of which may vary from actual results, including geologic
interpretation, prices, and future production rates and costs. See “Risk Factors” contained elsewhere in this Form
10-K. We have not filed any estimates of total, proved net oil or gas reserves with any federal authority or agency
other than the SEC since the beginning of our last fiscal year.
The following table sets forth estimates of our proved oil and natural gas reserves at December 31, 2007,
2006 and 2005. Reserve estimates at December 31, 2007 were prepared by NSAI with respect to our WCBB field
(61% of proved reserves PV-10 value at December 31, 2007), by Pinnacle Energy Services, LLC with respect to
our assets in the Permian Basin in West Texas (18% of proved reserves PV-10 value at December 31, 2007) and
by our personnel with respect to our Hackberry fields and our overrides and non-operated interests (21% of
proved reserves PV-10 value at December 31, 2007). The reserve estimates at December 31, 2006 were prepared
by NSAI with respect to our WCBB field (82% of proved reserves PV-10 value at December 31, 2006) and by
our personnel with respect to our Hackberry fields and our overrides and non-operated interests (18% of proved
reserves PV-10 value at December 31, 2006). Hackberry reserve estimates at December 31, 2005 were prepared
by NSAI.
December 31, 2007
December 31, 2006
December 31, 2005
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
7,116
6,746
8,240
17,999
17,513
20,918
25,115
24,259
29,158
4,876
4,077
5,556
14,816
16,724
17,603
19,692
20,801
23,159
4,308
3,758
4,934
15,234
18,023
18,238
19,542
21,781
23,172
Oil (MBbls) . . . . . . . . . .
Gas (MMcf) . . . . . . . . . .
Mboe . . . . . . . . . . . . . . .
PV-10
(in millions) (1) . . . . . $294.7
$ 526.5 $ 821.2 $120.0
$ 279.4 $ 399.4 $135.9
$ 321.0 $ 456.9
Standardized measure
(in millions) (2) . . . . .
$ 668.3 —
— $ 352.6 —
— $ 369.8
(1) Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax
of our estimated proven reserves. The estimated future net revenues 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 economic conditions prevailing at December 31, 2007. The estimated future production
in our WCBB and Hackberry fields is priced at December 31, 2007, 2006 and 2005, without escalation
23
using $92.50 per barrel and $6.80 per MMBtu, $57.75 per barrel and $5.64 per MMBtu and $57.75 per
barrel and $10.08 per MMBtu, respectively, adjusted by lease for transportation fees and regional price
differentials.
PV-10 is a non-GAAP measure because it excludes income tax effects. 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 gas companies.
PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered
as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of
PV-10 to the most directly comparable GAAP measure—standardized measure of discounted future net cash
flows. The following table reconciles the standardized measure of future net cash flows to the PV-10 value:
December 31,
2007
2006
2005
Standardized measure of discounted future net
cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $668,295,000 $352,648,000 $369,824,000
Add: Present value of future income tax discounted
at 10% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152,949,000
46,804,000
87,086,000
PV-10 value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $821,244,000 $399,452,000 $456,910,000
(2) The standardized measure represents 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.
The above table does not include proved reserves net to our interest in Tatex, or 3.5 Bcf of gas and 10,000
barrels of oil at December 31, 2007. For further discussion of our interest in Tatex, see Item 1. “Description of
Business—Additional Properties.”
Proved developed reserves are proved reserves that are expected to be recovered from existing wells with
existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to
be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and
recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a
relatively major expenditure is required to establish production.
Total proved reserves increased to 29,158 Mboe at December 31, 2007 from 23,159 Mboe at December 31,
2006. Total proved reserves decreased slightly to 23,159 Mboe at December 31, 2006 from 23,172 Mboe at
December 31, 2005. The change in 2007 reserves, as compared to 2006 reserves, is mainly attributable to the
acquisition of the Permian assets in December 2007. The decrease in 2006 reserves, as compared to 2005
reserves, is attributable to reserve revisions and reductions related to our 2006 production, mostly offset by
reserve additions from our 2006 drilling activity.
24
Production, Prices, and Production Costs
The following table presents our production volumes, average prices received and average production costs
during the periods indicated:
2007
2006
2005
Production Volumes:
Oil (MBbls)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil Equivalents (Mboe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,501
816
1,637
870
677
983
517
575
613
Average Prices:
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil Equivalents (per Mboe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$66.71(1) $64.43(1) $46.39(1)
$ 6.20
$ 7.40
$61.30
$64.86
$ 5.98
$44.75
Production Costs:
Average Production Costs (per Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average Production Taxes (per Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$10.18(2) $10.86(2) $12.49(2)
$ 7.50
$ 7.74
$ 5.91
Total Production Costs (per Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$17.92
$18.36
$18.40
(1)
Includes fixed contract prices of:
January – June 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
July – December 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
January – December 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June – December 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$33.10
$39.70
$64.05
$66.10
Excluding the net effect of the fixed price contracts, the average oil price for 2007 would have been $72.25
per barrel and $69.93 per barrel of oil equivalent. The total volume hedged for 2007 represents
approximately 43% of our total oil sales volumes for the year. Excluding the effect of the fixed price
contracts, the average oil price for 2006 would have been $65.56 per barrel and $62.30 per barrel of oil
equivalent. The total volume hedged for 2006 represents approximately 62% of our total oil sales volumes
for the year. Excluding the effect of the fixed price contracts, the average oil price for 2005 would have been
$56.17 per barrel and $52.99 per barrel of oil equivalent. Also includes financial hedge contracts with an
average mark-to-market value of approximately $50,000 per month for the months of July-December 2005
and approximately $82,000 per month for the months of January-December 2006.
(2) Does not include production taxes.
Productive Wells and Acreage
The following table presents our total gross and net productive wells, expressed separately for oil and gas,
and the total gross and net developed acres as of December 31, 2007:
Field
Percentages Gross
Net
Gross
Net
Gross
Net
NRI/WI (1)
Producing
Wells (2)
Non-Producing
Wells
Developed
Acreage (3)
West Cote Blanche Bay (4) . . . . . . . . . . . . . . . . . .
E. Hackberry (5) . . . . . . . . . . . . . . . . . . . . . . . . . .
W. Hackberry . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Permian . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Overrides/Royalty Non-operated . . . . . . . . . . . . .
78.665/100
79.424/100
87.5/100
37.5/50
Various
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
111
12
3
32
18
176
166
111
82
12
3
24
16 —
16
0.8
166
82
24
—
0.7
5,668
3,265
592
2,560
4,956
5,668
3,265
592
1,280
586
142.8
288
272.7
17,041
11,391
25
(1) Net Revenue Interest (NRI)/Working Interest (WI).
(2)
(3) Developed acres are acres spaced or assigned to productive wells. Approximately 87% of our acreage is
Includes 30 gross and net wells at WCBB that are producing intermittently.
developed acreage and has been perpetuated by production. We have 1,100 and 2,820 net undeveloped acres
in the East Hackberry field and the Permian Basin, respectively.
(4) We have a 100% working interest (78.665% average NRI) from the surface to the base of the 13900 Sand
which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working
interest (29.95% NRI).
(5) Does not include an additional 3,233 acres under an option we exercised which will increase our acreage
position significantly to approximately 7,598 acres. State approval was obtained on February 27, 2008, and
we are working with the state to finalize the leases.
Completed and Present Drilling and Recompletion Activities
The following table sets forth information with respect to wells completed during the periods indicated. The
information should not be considered indicative of future performance, nor should it be assumed that there is
necessarily any correlation between the number of productive wells drilled, quantities of reserves found or
economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not
they produce a reasonable rate of return.
2007
2006
2005 (1)
Gross Net Gross Net Gross Net
Recompletions:
62
Productive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — —
62
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
62
62
Development:
Productive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploratory:
Productive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
23
3
26
9
3
12
23
3
26
9
3
12
18
1
19
24
2
26
1
1
2
11
11
18
1 — —
19
11
11
24
16
16
2 — —
26
16
16
1 — —
1
1
2
1
1
1
(1)
Includes seven gross and net wells that were drilled during 2005 but not completed due to the damage
caused by Hurricane Rita. For further discussion of the impact of Hurricane Rita, see Item 6.
“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Impact of
Hurricane Rita.”
Title to Oil and Natural Gas Properties
It is customary in the oil and natural gas industry to make only a cursory review of title to undeveloped oil
and natural gas leases at the time they are acquired and to obtain more extensive title examinations when
acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of
such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas
properties may be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of
which, in management’s opinion, will in the aggregate materially restrict our operations.
26
ITEM 3. LEGAL PROCEEDINGS
The Louisiana State Mineral Board, or LSMB, is disputing our royalty payments to the State of Louisiana
resulting from the sale of oil under fixed price contracts. The LSMB maintains that we paid approximately
$1,400,000 less in royalties under the fixed price contracts than the royalties we would have had to pay had we
sold the oil at prevailing market rates. We denied any liability to the LSMB for underpayment of royalties and
have maintained that we were entitled to enter into the fixed price contracts with unrelated third parties and pay
royalties based upon the sales proceeds from those contracts. We have met with the Attorney General on several
occasions and recently reached a mutual settlement. The settlement requires us to pay $250,000, which has been
accrued in accounts payable and accrued liabilities in the accompanying consolidated balance sheet and all future
royalties will be paid at market price, regardless of the presence of fixed price contracts. The settlement was
approved during the LSMB’s February 2008 session, and we are currently awaiting the settlement and release
documentation from the LSMB to close this matter.
Litigation
In November 2006, Cudd Pressure Control, Inc., or Cudd, filed a lawsuit against us and Great White
Pressure Control LLC, an affiliate of ours, among others, in the 129th Judicial District Harris County, Texas. The
lawsuit was subsequently removed to the United States District Court for the Southern District of Texas (Houston
Division). The lawsuit alleges RICO violations and several other causes of action relating to an affiliate
company’s employment of several former Cudd employees and seeks unspecified monetary damages and
injunctive relief. The defendants in the suit are Ronnie Roles, Rocky Roles, Steve Winters, Bert Ballard, Nelson
Britton, Michael Fields, Steve Bickle, Great White Pressure Control LLC, and us. On stipulation by the parties,
the plaintiff’s RICO claim was dismissed without prejudice by order of the court on February 14, 2007.
Co-defendant, Steve Bickle, was dismissed from the case on July 18, 2007. The case against us was stayed by
order of the court on July 31, 2007. The court further ordered co-defendant, Great White Pressure Control, to
move for summary judgment by August 24, 2007. Cudd was ordered to respond by September 14, 2007. We filed
a motion for summary judgment on October 5, 2007. Plaintiff filed a response on November 15, 2007, and we
filed a reply on November 21, 2007. We are currently awaiting the ruling from the Court.
On July 27, 2007, Robotti & Company, LLC filed a putative class action lawsuit in the Court of Chancery
for the State of Delaware in and for Kent County, Delaware. The lawsuit alleges a breach of fiduciary duty by us
and our directors in connection with the pricing of the 2004 rights offering. We received service of this matter on
August 10, 2007. By mutual agreement of the parties, we were not required to respond until notified by the
plaintiff, which was received on January 16, 2008. Plaintiff filed an amended complaint on January 15, 2008, and
we filed a motion to dismiss in early February 2008.
In July 2007, Michael Tripkovich filed suit in the 16th Judicial District Court of the Parish of St. Martin,
Louisiana, against 113 entities, including us, alleging his contraction of chronic myeloid leukemia (CML) was
caused by exposure to various substances while maintaining natural gas compressors over a nineteen year period.
We were served on July 23, 2007 and filed a response accordingly. The suit is currently in the early phases of
discovery. We have no record that Mr. Tripkovich was ever employed by our company. No other deadlines have
been set at this time.
In October 2006, an accident occurred north of the our production facilities in the WCBB field in southern
Louisiana involving two contracted vessels that were performing work on behalf of us in the field. A tugboat, the
M/V Miss Megan, and two barges laden with construction materials ruptured an underwater natural gas pipeline
and a subsequent fire damaged the vessels. Six fatalities resulted from the accident. The following lawsuits
relating to this incident are currently pending before the courts:
• On October 13, 2006, Athena Construction LLC, or Athena, filed a limitation action in the United States
District Court for the Eastern District of Louisiana, alleging that all losses and damages as a result of the
pipeline incident were incurred without fault on its part. Furthermore, Athena claims the benefit of the
limitation of liability provided for in 42 U.S.C. § 183 and seeks an injunction restraining filing
27
commencement and further prosecution in any court of any lawsuit against Athena related to the
pipeline incident. The limitation of liability action was subsequently transferred to the United States
District Court for the Western District of Louisiana, which is where the case remains pending. On
December 20, 2006, 4-K Marine LLC, as owner of the M/V Miss Megan, and Central Boat Rentals,
Inc., as operator of the M/V Miss Megan also filed a limitation action in the Western District. On
January 10, 2007, the Athena and the 4-K/Central Boat limitation proceedings were consolidated by
order of the court. On May 5, 2007, Diamondback Energy, an affiliate of ours, filed an intervener with
the Court to become a party to the suit. The remaining parties filed claims on July 9, 2007, which
included claims by Nicholas Aucoin, one of the initial responders to the scene of the accident. A record
hearing was held on August 13, 2007, to discuss the status of the consolidated matters and a subsequent
work plan was filed on October 3, 2007. No other deadlines have been set.
• On October 16, 2006, a lawsuit was filed in the 16th Judicial District Court for the Parish of St. Mary,
Louisiana against us, Athena, and Central Boat seeking compensatory and punitive damages for claims
related to the death of the plaintiff’s husband, a crewmember on the Athena barge. The suit alleges that
the husband’s death was caused by the defendants’ negligence and the unseaworthiness of the barge to
which he was assigned. Pursuant to the Blanket Time Charter between us and Central Boat, Central Boat
tendered the defense and indemnification of the lawsuit to us. On November 2, 2006, all proceedings
were stayed as a result of the limitation of liability action discussed above. Settlement was reached
during mediations held in December 2007. We are currently working to obtain settlement approvals and
releases within the next 30 to 45 days.
• On October 22, 2006, a lawsuit was filed in United States District Court for the Southern District of
Texas, Galveston Division against us, Central Boat, Diamondback Energy Services LLC, an affiliate of
ours, Chevron Pipeline Company, Chevron USA, Inc., and ChevronTexaco Pipeline Holdings, Inc. This
lawsuit is a result of the death of three individuals. These individuals were employed by Athena and
were on the Athena barge at the time of the accident. The plaintiffs seek compensatory and punitive
damages as a result of the alleged negligence of defendants. Central Boat has tendered the defense and
indemnification of this lawsuit to us. On April 30, 2007, an order was filed transferring the case to the
Western District of Louisiana. A successful settlement was reached during mediations held in December
2007. We are currently working to obtain settlement approvals and releases within the next 30 to 45
days.
• On February 2, 2007, a lawsuit was filed in the United States District Court for the Western District of
Louisiana, Lafayette Division against Chevron Pipeline Company, Chevron USA Inc., Chevron Texaco
Pipeline Holdings, Inc., Chevron Natural Gas Services Inc., Diamondback Energy Services LLC, an
affiliate of ours, and us. The suit was filed on behalf of April Hummel, individually and as the
representative of the minor, Aleya Hummel, the surviving child of Terry Abraham who died in the
accident. On March 27, 2007, we filed our answer. On September 2, 2007, the case was stayed by order
of the Court. A successful settlement was reached in mediations held in November 2007. We are
currently working to obtain settlement approvals and releases.
• On October 15, 2007, Brian Dumesnil filed suit in the 16th Judicial District Court for the Parish of St.
Mary, Louisiana, against us, Chevron USA, Chevron Texaco Pipeline Holdings, Chevron Natural Gas,
Diamondback Energy Services and the Estate of Timothy Tauzin. Mr. Dumesnil was employed by
Athena and was on the Athena barge at the time of the accident. He is seeking unspecified sums as a
result of the alleged negligence of defendants and injuries incurred following the October 12, 2006
accident. By mutual agreement of the parties on October 19, 2007, we are not required to respond until
receipt of further notification from the plaintiff.
Due to the early stages of certain of the above litigation, the outcome is uncertain and management cannot
determine the amount of loss, if any, that may result. Litigation is inherently uncertain. Adverse decisions in one
or more of the above matters could have a material adverse affect on our financial condition or results of
operations.
28
In addition to the above, we have been named as a defendant in various other lawsuits related to our
business. The ultimate resolution of such other matters is not expected to have a material adverse effect on our
financial condition or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
29
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Through February 27, 2006, our common stock was traded on the NASD OTC Bulletin Board under the
symbol “GPOR.OB.” Since February 28, 2006, our common stock has been quoted on The NASDAQ National
Market and since July 14, 2006, our common stock has been quoted on The NASDAQ Global Select Market, in
each instance under the symbol “GPOR.” The following table sets forth the high and low sale prices of our
common stock for the periods presented:
2006
First Quarter
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Price Range of
Common Stock
High
Low
$16.00
15.89
13.64
14.11
$10.00
9.90
9.82
9.95
2007
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
First Quarter
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13.89
21.34
23.70
25.62
10.82
12.86
15.36
16.60
2008
First Quarter (through February 29, 2008) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
19.41
13.49
On March 3, 2008, the last reported sale price of our common stock on The NASDAQ Global Select Market
was $14.11. The above quotations for the periods prior to February 28, 2006 reflect inter-dealer prices, without
retail mark-up, markdown or commissions and may not represent actual transactions.
Unregistered Sales of Equity Securities and Use of Proceeds
None.
Holders of Record
At the close of business on March 3, 2008, there were 361 stockholders of record holding 42,550,031 shares
of our outstanding common stock. There were approximately 8,091 beneficial owners of our common stock as of
March 3, 2008.
Dividend Policy
We have never paid dividends on our common stock. We currently intend to retain all earnings to fund our
operations. Therefore, we do not intend to pay any cash dividends on the common stock in the foreseeable future.
In addition, the terms of our credit facility prohibits the payment of any dividends to the holders of our common
stock.
30
ITEM 6. SELECTED FINANCIAL DATA
You should read the following selected consolidated financial data in conjunction with “Management’s
Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial
statements and the related notes appearing elsewhere in this report. The selected consolidated statements of
operations data for the fiscal years ended December 31, 2007, December 31, 2006 and December 31, 2005 and
the selected consolidated balance sheet data at December 31, 2007 and December 31, 2006 are derived from our
audited consolidated financial statements appearing elsewhere in this report. The selected consolidated
statements of operations data for the fiscal years ended December 31, 2004 and December 31, 2003 and the
selected consolidated balance sheet data at December 31, 2005, December 31, 2004 and December 31, 2003 are
derived from our audited consolidated financial statements that are not included in this report. The historical data
presented below is not indicative of future results. We did not pay any cash dividends on our common stock
during any of the periods set forth in the following table.
Selected Consolidated Statements of Operations
Data:
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $105,838,000 $60,390,000 $27,559,000 $23,190,000 $15,947,000
Costs and expenses:
Fiscal Year Ended December 31,
2007
2006
2005
2004
2003
Lease operating expenses . . . . . . . . . . . . . . . . . . .
Production taxes . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation, depletion and amortization . . . . . .
General and administrative . . . . . . . . . . . . . . . . . .
Accretion expense . . . . . . . . . . . . . . . . . . . . . . . .
Income from Operations . . . . . . . . . . . . . . . . . . . . . . . .
Other (Income) Expense:
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense—preferred stock . . . . . . . . . . . .
Business interruption insurance recoveries . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income before Income Taxes and Effect of Change in
Accounting Principle . . . . . . . . . . . . . . . . . . . . . . . .
Income Tax Expense . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Income before Effect of Change in Accounting
Principle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cumulative effect of change in accounting
principal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Preferred stock dividends . . . . . . . . . . . . . . . . . .
Net Income (Loss) Available to Common
16,670,000
12,667,000
29,681,000
5,802,000
554,000
65,374,000
40,464,000
10,670,000
7,366,000
12,652,000
3,251,000
596,000
34,535,000
25,855,000
7,654,000
3,622,000
4,789,000
1,561,000
516,000
18,142,000
9,417,000
6,586,000
2,629,000
4,952,000
2,107,000
490,000
16,764,000
6,426,000
5,886,000
1,882,000
4,637,000
1,843,000
393,000
14,641,000
1,306,000
1,956,000
—
3,091,000
—
— (3,601,000)
(308,000)
(1,953,000)
(523,000)
2,568,000
250,000
272,000
(1,710,000)
(290,000)
(1,478,000)
246,000
1,949,000
—
(73,000)
2,122,000
112,000
875,000
—
(30,000)
957,000
37,896,000
121,000
27,808,000
—
10,895,000
—
4,304,000
—
349,000
—
37,775,000
27,808,000
10,895,000
4,304,000
349,000
—
37,775,000
—
—
27,808,000
—
—
10,895,000
—
—
4,304,000
—
270,000
619,000
(838,000)
Stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 37,775,000 $27,808,000 $10,895,000 $ 4,304,000 $ (219,000)
Net Income (Loss) Per Common Share—Basic:
Per common share before effect of change in
accounting principle . . . . . . . . . . . . . . . . . . . . . $
1.03 $
0.85 $
0.36 $
0.31 $
(0.05)
Effect per common share of change in
accounting principle . . . . . . . . . . . . . . . . . . . . .
Net Income (Loss) Per Common Share—Diluted:
Per common share before effect of change in
—
1.03 $
—
0.85 $
—
0.36 $
—
0.31 $
0.03
(0.02)
$
accounting principle . . . . . . . . . . . . . . . . . . . . . $
1.01 $
0.82 $
0.34 $
0.28 $
(0.05)
Effect per common share of change in
accounting principle . . . . . . . . . . . . . . . . . . . . .
—
1.01 $
—
0.82 $
—
0.34 $
—
0.28 $
0.03
(0.02)
$
31
2007
2006
2005
2004
2003
At Ended December 31,
Selected Consolidated Balance Sheet
Data:
Total assets . . . . . . . . . . . . . . . . . . . . . . $419,137,000 $195,151,000 $111,820,000 $78,150,000 $58,980,000
Total debt, including current
maturity . . . . . . . . . . . . . . . . . . . . . . . $ 66,533,000 $ 37,691,000 $ 10,200,000 $ 3,404,000 $ 2,318,000
Total liabilities . . . . . . . . . . . . . . . . . . . $115,015,000 $ 71,342,000 $ 27,493,000 $29,053,000 $25,832,000
Stockholders’ equity . . . . . . . . . . . . . . . $304,122,000 $123,809,000 $ 84,327,000 $49,097,000 $33,148,000
32
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with the consolidated financial
statements and related notes included elsewhere in this annual report on Form 10-K. This discussion contains
forward-looking statements reflecting our current expectations, estimates and assumptions concerning events
and financial trends that may affect our future operating results or financial position. Actual results and the
timing of events may differ materially from those contained in these forward-looking statements due to a number
of factors, including those discussed in the sections entitled “Risk Factors” and “Cautionary Note Regarding
Forward-Looking Statements” appearing elsewhere in this annual report on Form 10-K.
Overview
We are an independent oil and natural gas exploration and production company with our principal producing
properties located along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry
fields. We have also recently acquired strategic assets in West Texas in the Permian Basin. We also hold a
significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC and
have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to
achieve reserve growth and increase our cash flow through our annual drilling programs.
2007 Highlights
• Oil and natural gas revenues increased $45.9 million to $106.1 million for the year ended December 31,
2007 from $60.2 million for 2006.
• Net income increased 36% to $37.8 million for the year ended December 31, 2007 from $27.8 million
for 2006.
•
Production increased 67% to 1,637,000 BOE for the year ended December 31, 2007 from 983,000 BOE
for 2006.
• We received net proceeds of approximately $138.3 million from sales of our common stock in
underwritten public offerings completed in February 2007, May 2007, July 2007 and December 2007,
after deducting the underwriting discount and offering expenses. These net proceeds were used to pay
down existing debt under our credit facility and fund substantially all of the purchase price for the
acquisition of certain strategic assets in West Texas in the Permian Basin discussed in more detail
below.
• On December 20, 2007, we completed an acquisition of strategic assets in West Texas in the Permian
Basin for approximately $85 million, effective as of November 1, 2007. In this transaction we acquired
4,100 net acres with production of approximately 800 net BOE a day from 32 gross wells,
predominately from the Wolfcamp formation. Existing production is approximately 64% oil, 23%
natural gas liquids and 13% natural gas. We have identified 178 gross future development drilling
locations. We expect 17 to 22 net wells to be drilled on this acreage in 2008. The wells are expected to
be drilled to approximately 10,200 feet at an estimated average gross completed well cost of $1.7
million. We funded this transaction predominately through a 4.5 million common share offering, which
closed on December 12, 2007. Operations from these properties were included in our results of
operations for 2007 only from the closing date of December 21, 2007 through December 31, 2007.
• During the third quarter of 2006, we purchased a 24.9999% interest in Grizzly Oil Sands ULC, a
Canadian unlimited liability company holding leases in the Athabasca region located in northern Alberta
Province, Canada near Fort McMurray near other oil sands development projects. As of December 31,
2007, our net investment in Grizzly was approximately $27.8 million. As of December 31, 2007,
Grizzly had approximately 511,000 acres under lease. Grizzly drilled 62 core holes during the
2006/2007 winter delineation drilling season and tested three separate lease blocks with four
33
drilling rigs. Core hole samples have been collected and sent to a lab to assess the quantity and thickness
of the bitumen in place on our acreage. Future plans currently include acquiring additional leases,
drilling approximately 55 to 60 additional core holes and a seismic program during the 2007/2008
winter drilling season, and initial planning for construction of a 10,000 barrel per day SAGD facility as
soon as 2008, which could lead to initial production in 2011. Estimated gross capital expenditures for a
comparable production facility are approximately $325 million.
• During 2007, we drilled 38 wells and recompleted 62 wells. Of our 38 new wells drilled, 32 were
completed as producing wells and six were non-productive.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon consolidated
financial statements, which have been prepared in accordance with accounting principles generally accepted in
the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to
make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We
have identified certain of these policies as being of particular importance to the portrayal of our financial position
and results of operations and which require the application of significant judgment by our management. We
analyze our estimates including those related to oil and natural gas properties, revenue recognition, income taxes
and commitments and contingencies, and base our estimates on historical experience and various other
assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these
estimates under different assumptions or conditions. We believe the following critical accounting policies affect
our more significant judgments and estimates used in the preparation of our consolidated financial statements:
Oil and Natural Gas Properties. We use the full cost method of accounting for oil and natural gas
operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs
directly associated with acquisition, exploration and development of oil and natural gas properties, are
capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted
at 10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to
amortization. Such capitalized costs, including the estimated future development costs and site remediation costs,
if any, are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf
of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless
such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas
reserves. Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds
and totaled $37,278,000 at December 31, 2007 and $1,459,000 at December 31, 2006. These costs are reviewed
periodically by management for impairment, with the impairment provision included in the cost of oil and natural
gas properties subject to amortization. Factors considered by management in its impairment assessment include
our drilling results and those of other operators, the terms of oil and natural gas leases not held by production and
available funds for exploration and development.
Ceiling Test. Companies that use the full cost method of accounting for oil and gas properties are required to
perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas
properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the
cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted
at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for any
contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the
estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet,
(b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved
properties included in the cost being amortized, less income tax effects related to differences between the book
and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred
income tax liability exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test
impairment can give us a significant loss for a particular period; however, future depletion expense would be
reduced. A future decline in oil and gas prices may result in an impairment of oil and gas properties.
34
Asset Retirement Obligations. We have obligations to remove equipment and restore land at the end of oil
and gas production operations. Our removal and restoration obligations are primarily associated with plugging
and abandoning wells and associated production facilities.
We account for abandonment and restoration liabilities under Statement of Financial Accounting Standards
No. 143, “Accounting for Asset Retirement Obligations,” SFAS No. 143, which requires us to record a liability
equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the
period in which the obligation meets the definition of a liability, which is generally when the asset is placed into
service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by
an amount equal to the original liability. The liability is accreted to its present value each period, and the
capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability
or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset
lives, estimated costs of abandonment or legal or statutory remediation requirements.
The fair value of the liability associated with these retirement obligations is determined using significant
assumptions, including current estimates of the plugging and abandonment or retirement, annual inflations of
these costs, the productive life of the asset and our risk adjusted cost to settle such obligations discounted using
our credit adjustment risk free interest rate. Changes in any of these assumptions can result in significant
revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded
with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes
to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of
assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire
these assets may vary significantly from previous estimates.
Oil and Gas Reserve Quantities. Our estimate of proved reserves is based on the quantities of oil and natural
gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from
established reservoirs in the future under current operating and economic parameters. Netherland, Sewell &
Associates, Inc., Pinnacle Energy Services, LLC and to a lesser extent our personnel have prepared reserve
reports of our reserve estimates on a well-by-well basis for our properties.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment
calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve
estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been
prepared in accordance with SEC guidelines. The accuracy of our reserve estimates is a function of many factors
including the following:
•
•
•
•
the quality and quantity of available data;
the interpretation of that data;
the accuracy of various mandated economic assumptions; and
the judgments of the individuals preparing the estimates.
Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly
from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural
gas eventually recovered.
Income Taxes. We use the asset and liability method of accounting for income taxes, under which deferred
tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the
financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and
tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to
the future period when those temporary differences are expected to be recovered or settled. The effect of a
change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change
is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable.
35
Periodically, management performs a forecast of its taxable income to determine whether it is more likely than
not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for
our deferred tax assets is established, if in management’s opinion, it is more likely than not that some portion will
not be realized. At December 31, 2007, a valuation allowance of $9,750,000 had been provided for deferred tax
assets based on the uncertainty of future taxable income.
Revenue Recognition. We derive almost all of our revenue from the sale of crude oil and natural gas
produced from our oil and gas properties. Revenue is recorded in the month the product is delivered to the
purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the
end of each month, we estimate the amount of production delivered to purchasers that month and the price we
will receive. Variances between our estimated revenue and actual payment received for all prior months are
recorded at the end of the quarter after payment is received. Historically, our actual payments have not
significantly deviated from our accruals.
Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments,
litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can
be reasonably estimated. We are involved in certain litigation for which the outcome is uncertain. Changes in the
certainty and the ability to reasonably estimate a loss amount, if any, may result in the recognition and
subsequent payment of legal liabilities.
Derivative Instruments and Hedging Activities. We seek to reduce our exposure to unfavorable changes in
oil prices by utilizing energy swaps and collars, or fixed-price contracts. We follow the provisions of SFAS 133,
“Accounting for Derivative Instruments and Hedging Activities,” as amended. It requires that all derivative
instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair
value of all derivative instruments using established index prices and other sources. These values are based upon,
among other things, futures prices, correlation between index prices and our realized prices, time to maturity and
credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual
results, changes in market conditions or other factors.
The accounting for changes in the fair value of a derivative depends on the intended use of the derivative
and the resulting designation. Designation is established at the inception of a derivative, but re-designation is
permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133,
changes in fair value are recognized in accumulated other comprehensive income until the hedged item is
recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair
value between the derivative contract and the hedged item over time. We recognize any change in fair value
resulting from ineffectiveness immediately in earnings.
To mitigate the effects of commodity price fluctuations, during 2007, we entered into forward sales
contracts for the sale of 3,000 barrels of production per day for the month of June 2007 at a weighted average
daily price of $70.15 per barrel before transportation costs. For the period of July 2007 through December 2007,
we entered into forward sales contracts for the sale of 3,500 barrels of production per day at a weighted average
daily price of $70.29 per barrel before transportation costs. In addition, we have entered into agreements to sell
3,500 barrels of production per day for the month of January through May 2008 at a weighted average daily price
of $70.29 per barrel before transportation costs. For the month of June 2008, we have agreements to sell 3,500
barrels of production per day at a weighted average daily price of $71.69 per barrel before transportation costs.
For the month of July 2008, we have agreements to sell 3,000 barrels of production per day at a weighted average
daily price of $81.37 per barrel before transportation costs. For August 2008, we have agreements to sell 3,000
barrels of production per day at a weighted average daily price of $82.44 per barrel before transportation costs.
For the periods of September 2008 through December 2008, we have entered into forward sales contracts for the
sale of 3,000 barrels of production per day in each such period at weighted average daily prices of $82.20 per
barrel before transportation costs. Under these agreements we have committed to deliver approximately 60% of
our estimated production for January through December 2008. For the period of January through December
2009, we entered into agreements to sell 2,500 barrels of production per day at a weighted average daily price of
36
$84.62 per barrel before transportation costs. Such arrangements may expose us to risk of financial loss in certain
circumstances, including instances where production is less than expected or oil prices increase. These contracts
require physical delivery of production quantities and are exempted from the provisions of SFAS 133 as normal
sales of production.
RESULTS OF OPERATIONS
Results of Operations
The markets for oil and natural gas have historically been, and will continue to be, volatile. Prices for oil
and natural gas may fluctuate in response to relatively minor changes in supply and demand, market uncertainty
and a variety of factors beyond our control.
The following table presents our production volumes, average prices received and average production costs
during the periods indicated:
Production Volumes:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil (MBbls)
Gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil Equivalents (Mboe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007
2006
2005
1,501
816
1,637
870
677
983
517
575
613
Average Prices:
Oil (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil Equivalents (per Mboe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$66.71(1) $64.43(1) $46.39(1)
$ 6.20
$ 7.40
$61.30
$64.86
$ 5.98
$44.75
Production Costs:
Average Production Costs (per Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average Production Taxes (per Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$10.18(2) $10.86(2) $12.49(2)
$ 7.50
$ 7.74
$ 5.91
Total Production Costs (per Boe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$17.92
$18.36
$18.40
(1)
Includes fixed contract prices of:
January – June 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
July – December 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
January – December 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June – December 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$33.10
$39.70
$64.05
$66.10
Excluding the effect of the fixed price contracts, the average oil price for 2007 would have been $72.25 per
barrel and $69.93 per barrel of oil equivalent. The total volume hedged for 2007 represents approximately
43% of our total oil sales volumes for the year. Excluding the effect of the fixed price contracts, the average
oil price for 2006 would have been $65.56 per barrel and $62.30 per barrel of oil equivalent. The total
volume hedged for 2006 represents approximately 62% of our total oil sales volumes for the year. Excluding
the effect of the fixed price contracts, the average oil price for 2005 would have been $56.17 per barrel and
$52.99 per barrel of oil equivalent. Also includes financial hedge contracts with an average mark-to-market
value of approximately $50,000 per month for the months of July-December 2005 and approximately
$82,000 per month for the months of January-December 2006.
(2) Does not include production taxes.
From 2006 to 2007, our net oil production increased 73% from 869,728 barrels to 1,500,818 barrels due to
our continued drilling activity. From 2005 to 2006, our oil production increased 68% to 869,728 barrels due to
our continued drilling activity and also to a loss of production during the fourth quarter 2005 as a result of the
damage caused to our facilities from Hurricane Rita in September 2005. We currently estimate that our 2008
production will be between 1,900,000 and 2,100,000 BOE with production increasing during the year.
37
Comparison of the Years Ended December 31, 2007 and December 31, 2006
We reported net income of $37,775,000 for the year ended December 31, 2007, compared to $27,808,000
for the year ended December 31, 2006. This 36% increase in net income was due primarily to (1) a 67% increase
in net production to 1,636,902 BOE for the year ended December 31, 2007 from 982,531 BOE for 2006 as a
result of our continued drilling activity and (2) a 6% increase in the average BOE oil price received to $64.86 per
barrel for the year ended December 31, 2007 from $61.30 per barrel for 2006. Although we closed the acquisition
of the assets in the Permian Basin in West Texas on December 20, 2007, effective as of November 1, 2007, under
GAAP only the oil and gas activities for the days subsequent to the closing date, which in this case were from
December 21 through December 31, 2007, can be included in our 2007 oil and gas activities. As a result,
activities related to these new assets had little impact on our results of operations for the year ended
December 31, 2007.
Oil and Gas Revenues. For the year ended December 31, 2007, we reported oil and gas revenues of
$106,163,000, compared to oil and gas revenues of $60,232,000 during 2006. This $45,931,000, or 76%, increase
in revenues is primarily attributable to a 67% increase in net production to 1,636,902 BOE for the year ended
December 31, 2007 from 982,531 BOE for the year ended December 31, 2006. Production in the first half of
2006 was negatively impacted by the damage caused by Hurricane Rita, as production from our wells at WCBB
was not fully restored until later in 2006.
The following table summarizes our oil and natural gas production and related pricing for the years ended
December 31, 2007 and 2006:
Year Ended
December 31,
2007
2006
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil production volumes (MBbls)
Gas production volumes (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil equivalents (Mboe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average oil price (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average gas price (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil equivalents (per Boe)
1,501
816
1,637
$66.71
$ 7.40
$64.86
870
677
983
$64.43
$ 6.20
$61.30
Lease Operating Expenses. Lease operating expenses not including production taxes increased to
$16,670,000 for the year ended December 31, 2007 from $10,670,000 for 2006. Since our WCBB facilities
continued to be shut in until late in the first quarter of 2006 due to the impact of Hurricane Rita some of the costs
that would have normally been associated with our lease operating expenses were instead spent on ongoing
restoration and repair activities during the year ended December 31, 2006. In addition, lease operating expenses
for the year ended December 31, 2007 increased due to increased labor requirements associated with a ramp up
in overall activity in both fields, increases in rates paid for labor and other services, increases in the cost of
oil-based supplies, non-recurring repairs including repairs to compressors, and increases in property taxes in both
fields as a result of the on-going capital programs. These increases were partially offset by a reduction in lease
operating expenses attributable to our interest in the Marquiss field which we sold during February 2007.
Production Taxes. Production taxes increased to $12,667,000 for the year ended December 31, 2007 from
$7,366,000 for 2006. This increase was directly related to a 76% increase in oil and gas revenues as a result of
the increase in production.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased to
$29,681,000 for the year ended December 31, 2007, and consisted of $29,220,000 in depletion on oil and natural
gas properties and $461,000 in depreciation of other property and equipment. This compares to total
depreciation, depletion and amortization expense of $12,652,000 for the year ended December 31, 2006. This
increase was due primarily to an increase in our production, an increase in our oil and natural gas property costs
associated with our 2006 and 2007 drilling programs and an increase in our future development costs.
38
General and Administrative Expenses. Net general and administrative expenses increased to $5,802,000 for
2007 from $3,251,000 for 2006. This increase was due primarily to increases in payroll costs and related benefits
as a result of increases in the total number of employees. In addition, this increase also resulted from $310,000 of
costs associated with the implementation of Section 404 of the Sarbanes-Oxley Act, an increase of $300,000 in
franchise taxes, an increase of $220,000 for the services provided by our external reserve engineers, an increase
of $100,000 in our business and D&O insurance costs and an increase of $95,000 for expenses associated with
SFAS No. 123(R), “Share Based Payment.” These increases were partially offset by an increase in the amount of
capitalized general and administrative expenses and a decrease in legal expenses and corporate fees.
Accretion Expense. Accretion expense decreased to $554,000 for 2007 from $596,000 for 2006. Although
there was a larger obligation at the beginning of 2007 than there was at the beginning of 2006 resulting from the
addition of future abandonment obligations on new wells drilled during 2006, the effect of the increase on the
larger obligations was more than offset by the effect of the sale of the Marquiss properties in February 2007.
Interest Expense. Interest expense increased to $3,091,000 for 2007 from $1,956,000 for 2006 due to an
increase in average debt outstanding. Total weighted debt outstanding under our facilities with Bank of America
was $33.2 million for the year ended December 31, 2007, as compared to $18.8 million for 2006. In addition,
during July 2006 we entered into a new $5.0 million term loan agreement with Bank of America. As a result,
during the year ended December 31, 2007, we recognized a full year of interest related to the term loan in the
amount of $382,000 as compared to only $115,000 for 2006.
Income Taxes. As of December 31, 2007, we had a net operating loss carry forward of approximately $93
million, in addition to numerous temporary differences, which gave rise to a deferred tax asset. Periodically,
management performs a forecast of our taxable income to determine whether it is more likely than not that a
valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our
deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not
be realized. At December 31, 2007, a valuation allowance of $9.8 million had been provided for deferred tax
assets. We had only a slight income tax expense of $121,000 during the year ended December 31, 2007 related to
the payment of alternative minimum taxes due for 2006 and 2007. Although we have substantial net operating
loss carryforwards, these cannot be used to offset alternative minimum tax liabilities.
Comparison of the Years Ended December 31, 2006 and December 31, 2005
We reported net income of $27,808,000 for the year ended December 31, 2006, compared to $10,895,000
for the year ended December 31, 2005. This 155% increase in net income was due primarily to (1) a 60%
increase in net production to 982,531 BOE for the year ended December 31, 2006 from 612,840 BOE for 2005,
(2) a 39% increase in the average oil price received to $64.43 per barrel for the year ended December 31, 2006
from $46.39 per barrel for 2005 and (3) business interruption insurance recoveries of $3,601,000 due to
Hurricane Rita.
Oil and Gas Revenues. For the year ended December 31, 2006, we reported oil and gas revenues of
$60,232,000, compared to oil and gas revenues of $27,423,000 during 2005. This 120% increase in revenues is
mainly attributable to a 60% increase in net production to 982,531 BOE for the year ended December 31, 2006
from 612,840 BOE for 2005 and a 39% increase in the average oil price received to $64.43 per barrel for the year
ended December 31, 2006 from $46.39 per barrel for 2005. This increase in oil and natural gas production was
the result of production from our 2006 drilling program and restoration of fields and facilities for which
production was curtailed due to Hurricane Rita. Production in 2005 and 2006 was adversely affected by the
damage caused by Hurricane Rita. In addition, production in 2006 was adversely affected by the accident in our
field on October 12, 2006, which shut in our facilities from that date through early December 2006.
39
The following table summarizes our oil and natural gas production and related pricing for the years ended
December 31, 2006 and December 31, 2005:
Year Ended
December 31,
2006
2005
Oil production volumes (MBbls)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas production volumes (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil equivalents (Mboe) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average oil price (per Bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average gas price (per Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil equivalents (per Boe)
870
677
983
$64.43
$ 6.20
$61.30
517
575
613
$46.39
$ 5.98
$44.75
Lease Operating Expenses. Lease operating expenses not including production taxes increased to
$10,670,000 for 2006 from $7,654,000 for 2005. This increase was mainly due to increases in insurance costs,
$972,000 in one time non-recurring repairs to the WCBB gas sales pipeline related to the tug boat accident that
occurred in October 2006 and the increases in the general costs of labor and supplies in our operating area along
the Louisiana Gulf Coast.
Production Taxes. Production taxes increased to $7,366,000 for 2006 from $3,622,000 for 2005. This
increase was directly related to a 120% increase in oil and gas revenues as a result of the 37% improvement in
the price received per barrel oil equivalent and a 60% increase in production for 2006 compared to 2005.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased to
$12,652,000 for the year ended December 31, 2006, and consisted of $12,259,000 in depletion on oil and natural
gas properties and $393,000 in depreciation of other property and equipment. This compares to total
depreciation, depletion and amortization expense of $4,789,000 for the year ended December 31, 2005. This
increase was due primarily to an increase in our oil and natural gas property costs associated with our 2006
drilling program and an increase in our oil and gas production for the period.
General and Administrative Expenses. Net general and administrative expenses increased to $3,251,000 for
2006 from $1,561,000 for 2005. This increase was due primarily to the $1,063,000 effect of the implementation
of SFAS No. 123(R), “Share Based Payment” (less $276,000 capitalized for personnel directly related to our
exploration and development activities), a $250,000 increase in corporate fees relating to being a NASDAQ
listed company, and general increases in the payroll costs and related benefits as a result of the increased number
of employees. These increases were partially offset by increases in general administrative reimbursements from
our affiliates.
Accretion Expense. Accretion expense increased $80,000 to $596,000 for 2006 from $516,000 for 2005, due
to a larger obligation at the beginning of 2006 compared to the beginning of 2005, resulting from the addition of
future abandonment obligations on new wells drilled during 2005.
Interest Expense. Ordinary interest expense increased to $1,956,000 for 2006 from $250,000 for 2005 due to
an increase in average debt outstanding. At December 31, 2006, total debt outstanding under our facility with
Bank of America was $34,800,000. At December 31, 2005, $7,000,000 was outstanding under this facility.
Interest Expense—Preferred Stock. During the year ended December 31, 2005, we incurred interest expense
on preferred stock classified as a liability under SFAS No. 150, “Accounting for Certain Financial Instruments
with Characteristics of both Liabilities and Equity.” During 2005, we redeemed all of the remaining outstanding
shares of our Series A preferred stock. As a result, we incurred no interest expense relating to preferred stock
during 2006 as compared to $272,000 in interest expense incurred during 2005.
Income Taxes. As of December 31, 2006, we had a net operating loss carry forward of approximately $95.9
million, in addition to numerous temporary differences, which gave rise to a deferred tax asset. Periodically,
management performs a forecast of our future taxable income to determine whether it is more likely than not that
40
a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our
deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not
be realized. At December 31, 2006, a valuation allowance of $25.5 million had been provided for our entire net
deferred tax asset. We had no income tax expense due to a change in the valuation allowance for deferred income
taxes for the year ended December 31, 2006.
Liquidity and Capital Resources
Overview. Historically, our primary sources of funds have been cash flow from our producing oil and
natural gas properties, the issuance of equity securities and borrowings under our bank and other credit facilities.
Our ability to access any of these sources of funds can be significantly impacted by decreases in oil and natural
gas prices or oil and gas production. During the year ended December 31, 2006, recoveries under our insurance
coverages also provided a significant source of funds due to damage from Hurricane Rita in September 2005 and
the resulting interruption of our business during the fourth quarter of 2005 and the six months ended June 2006.
Net cash flow provided by operating activities was $68,902,000 for 2007, as compared to net cash flow
provided by operating activities of $39,523,000 for 2006. This increase was primarily the result of an increase in
cash receipts from our oil and gas purchasers due to a 67% increase in net production, partially offset by
increases in cash paid for lease operating expenses and production taxes.
Net cash flow provided by operating activities was $15,200,000 for 2005, as compared to $39,523,000 for
2006. The increase of $24,323,000 in 2006 was primarily the result of an increase in cash receipts from our oil
and gas purchasers due to higher prices received for oil production and a 60% increase in net production,
partially offset by increase in cash paid for lease operating expenses and production taxes.
Net cash used in investing activities for 2007 was $240,733,000, as compared to $73,876,000 for 2006.
During the year ended December 31, 2007, we spent $220,044,000 in additions to oil and natural gas properties,
of which $96,113,000 was spent on our 2007 drilling program, $85,230,000 was spent on our acquisition of
certain strategic assets in Upton County, Texas in the Permian Basin, $12,319,000 was spent on expenses
attributable to the wells drilled during 2006, $9,467,000 was spent on our new Hackberry barge facilities,
$2,834,000 was spent on additions to oil and natural gas properties due to Hurricane Rita, with the remainder
attributable mainly to facility enhancement and capitalized general and administrative expenses. During the year
ended December 31, 2007, we made investments of $17,316,000 in Grizzly. During the year ended December 31,
2007, we used cash from operations, proceeds from the sale of 8,547,500 shares of our common stock and
borrowings under our credit facility to fund our investing activities.
Net cash used in investing activities for 2005 was $36,703,000, as compared to $73,876,000 for 2006.
During the year ended December 31, 2006, we spent $62,403,000 in additions to oil and natural gas properties, of
which $40,040,000 was spent on our 2006 drilling program, $5,175,000 was attributable to the wells drilled
during 2005, $2,179,000 was spent on additions to oil and natural gas properties due to the hurricane net of
insurance proceeds, $5,517,000 was spent on new compressors for WCBB, with the remainder attributable
mainly to capitalized general and administrative expenses and recompletions. In addition, during the year ended
December 31, 2006, we made investments of $964,000 in Tatex Thailand II, $1,416,000 in Windsor Bakken
LLC, and $8,493,000 in Grizzly Oil Sands ULC. We used cash from operations, proceeds from the sale of
company common stock, insurance recoveries and borrowings under our credit facility to fund our investing
activities in 2006.
Net cash provided by financing activities for 2007 was $167,968,000, as compared to $38,861,000 for 2006.
The 2007 amount provided by financing activities is primarily attributable to borrowings of $76,000,000 under
our credit facility with Bank of America and aggregate proceeds of approximately $138,258,000 from the sale of
shares of our common stock in February 2007, May 2007, July 2007 and December 2007, after deducting the
underwriting discount and offering expenses, and $868,000 from the exercise of stock options. Net proceeds
were used to pay down $46,328,000 of outstanding existing debt under our credit facility with Bank of America,
41
fund substantially all of the purchase price for the acquisition of our interest in certain strategic assets in Upton
County, Texas in the Permian Basin and for other general corporate purposes. The 2006 amount provided by
financing activities is attributable to draws of $33,300,000 on our credit facility with Bank of America and
proceeds before offering costs of $10,451,000 from the issuance of common stock in our May 2006 underwritten
public offering and $1,276,000 from the exercise of stock options.
Net cash provided by financing activities for 2005 was $16,080,000, which amount is primarily attributable
to aggregate net cash proceeds of approximately $23,600,000 from (1) the issuance of common stock in two
private placements and (2) the exercise of the outstanding warrants and net borrowings of $6,796,000, partially
offset by the approximately $14,292,000 used to redeem all 14,202 outstanding shares of our Series A preferred
stock.
Issuance of Equity. In January 2007, we sold 1,150,000 shares of our common stock in an underwritten
offering at an offering price to the public of $11.92 per share. In connection with the offering, we granted the
underwriter an option to purchase up to an additional 172,500 shares of our common stock to cover any over-
allotments, which the underwriter exercised in full. We received the net proceeds of approximately $15.3 million
from the sale of these shares on February 5, 2007 after deducting the underwriting discount and before offering
expenses. These net proceeds were used to pay down outstanding debt under our credit facility.
In May 2007, we sold 1,500,000 shares of our common stock in an underwritten offering at an offering price
to the public of $16.00 per share. In connection with the offering, we granted the underwriter an option to
purchase up to an additional 225,000 shares of our common stock to cover any over-allotments, which the
underwriter exercised in full. We received the net proceeds of approximately $26.8 million from the sale of these
shares on May 22, 2007 after deducting the underwriting discount and before offering expenses. These net
proceeds were used to pay down outstanding debt under our credit facility.
In July 2007, we sold 1,000,000 shares of our common stock in an underwritten offering at an offering price
to the public of $22.00 per share. We received the net proceeds of approximately $21.2 million from our sale of
these shares on July 25, 2007 after deducting the underwriting discount and before offering expenses.
In December 2007, we sold 4,500,000 shares of our common stock in an underwritten offering at an offering
price to the public of $17.50 per share. We received the net proceeds of approximately $75.6 million from our
sale of these shares on December 12, 2007 after deducting underwriting discounts and commissions and before
offering expenses. We used the net proceeds from this offering to fund substantially all of the purchase price for
our interest in the acquisition of certain strategic assets in Upton County, Texas in the Permian Basin. In
connection with this offering, a selling stockholder granted the underwriters an option to purchase an additional
675,000 shares of our common stock at a price of $16.80 per share solely to cover any over-allotments, which
underwriters exercised in full. We did not receive any proceeds from the sale of shares of our common stock by
the selling stockholder.
Credit Facility. On March 11, 2005, we entered into a three-year secured reducing credit agreement, as
amended, providing for a revolving credit facility with Bank of America, N.A. Borrowings under the revolving
credit facility are subject to a borrowing base limitation, which was initially set at $18.0 million, subject to
adjustment. On November 1, 2005, the amount available under the borrowing base limitation was increased to
$23.0 million and was redetermined without change on May 30, 2006. On December 19, 2006, the amount
available under the borrowing base limitation was increased to $30.0 million. Effective July 19, 2007, the credit
facility increased to $150.0 million and the amount available under the borrowing base limitation was increased
to $60.0 million. In connection with our acquisition of strategic assets in West Texas in the Permian Basin,
effective as of December 20, 2007, our borrowing base under the revolving credit facility increased from $60.0
million to $90.0 million and the Eurodollar interest rate, which we can elect to use at our option, reduced by
0.75%. In addition, the maturity date was extended from March 31, 2009 to March 31, 2010. We agreed to pay a
borrowing base increase fee of 0.50% of any increase of the borrowing base over the highest borrowing base
previously in effect, payable on the day such increased borrowing base becomes effective. We make quarterly
42
interest payments on amounts borrowed under the facility, which amounts bear interest at Bank of America
prime plus 0.25% (7.5 % at December 31, 2007). Our obligations under the credit facility are collateralized by a
lien on substantially all of our Louisiana and West Texas oil and gas assets.
The credit facility contains certain affirmative and negative covenants, including, but not limited to the
following financial covenants: (a) the ratio of funded debt to EBITDAX (net income before deductions for taxes,
excluding unrealized gains and losses related to trading securities and commodity hedges, plus depreciation,
depletion, amortization and interest expense, plus exploration costs deducted in determining net income under
full cost accounting) for a twelve-month period may not be greater than 2.00 to 1.00; and (b) the ratio of
EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in
compliance with all covenants at December 31, 2007. As of December 31, 2007, approximately $59.5 million
was outstanding under this facility, which is included in long-term debt, net of current maturities on the
accompanying consolidated balance sheet. We have used the proceeds of our borrowings under the credit facility
for the exploration of our oil and natural gas properties and other capital expenditures, acquisition opportunities,
replacement of facilities and equipment due to Hurricane Rita and for other general corporate purposes.
On July 10, 2006, we entered into a $5.0 million term loan agreement with Bank of America, N.A. related to
the purchase of new gas compressor units. The loan began amortizing quarterly on March 31, 2007 on a straight-
line basis over seven years based on the outstanding principal balance at December 31, 2006. Amounts borrowed
bear interest at Bank of America prime (7.25 % at December 31, 2007). We make quarterly interest payments on
amounts borrowed under the agreement. Our obligations under the agreement are collateralized by a lien on the
compressor units. As of December 31, 2007, approximately $4.3 million was outstanding under this agreement,
of which $714,000 and $3,580,000 are included in current maturities of long-term debt and long-term debt, net of
current maturities, respectively, on our accompanying consolidated balance sheet.
Building Loans. We had three loans associated with two of our buildings. One loan, in the original principal
amount of $115,000, related to a building in Lafayette, Louisiana, that we purchased in 1996 to be used as our
Louisiana headquarters. This loan bore interest at the rate of 5.75% per annum. We repaid this loan in full during
the third quarter of 2007. In addition, in June 2004 we purchased the office building we occupy in Oklahoma
City, Oklahoma for $3.7 million. One of the two loans associated with this building, with an original principal
amount of $389,000, matured in March 2006 and bore interest at a rate of 6% per annum. The other loan
associated with this building, with an original principal amount of $3.0 million, matures in June 2011 and bears
interest at a rate of 6.5% per annum. The remaining building loan requires monthly interest and principal
payments and is collateralized by the respective land and buildings.
Capital Expenditures. Our recent capital commitments have been primarily for the development of our
proved reserves, to increase our net acreage position in Grizzly Oil Sands ULC and fund Grizzly’s delineation
drilling program and for acquisitions, primarily our recently completed transaction in the Permian Basin. Our
strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling,
workover, sidetrack and recompletion projects to exploit our existing properties and (2) explore other acquisition
opportunities. We have upgraded our infrastructure and our existing facilities with the goal of increasing
operating efficiencies and volume capacities and lowering lease operating expenses. These upgrades were also
intended to better enable our facilities to withstand future hurricanes with less damage. Additionally, we
completed the reprocessing of 3-D seismic data in one of our principal properties, WCBB. The reprocessed data
enables our geophysicists to continue to generate new prospects and enhance existing prospects in the
intermediate zones in the field, thus creating a portfolio of new drilling opportunities. In addition, with our
acquisition of strategic assets in the Permian Basin in West Texas, we will also be required to pay 50% of all
drilling costs for future drilling activity on such properties.
43
In our December 31, 2007 reserve reports, 72% of our net reserves were categorized as proved undeveloped.
Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct
successful exploration or development activities or acquire properties containing proved developed reserves, or
both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other
replacement activities or use third parties to accomplish those activities.
Our inventory of prospects includes approximately 111 drilling locations at WCBB. The drilling schedule
used in our December 31, 2007 reserve report anticipates that all of those wells will be drilled by 2019. From
January 1, 2008 through March 1, 2008, we drilled two wells and recompleted 14 existing wells at our WCBB
field. We currently intend to spend a total of approximately $21 to $23 million for drilling, recompletion and
other activities in our WCBB field during 2008.
In our East Hackberry field, from January 1, 2008 through March 1, 2008, we drilled one well and
recompleted three wells. We intend to drill three to five additional land wells and recomplete one additional well
during 2008. Total capital expenditures for our East Hackberry field during 2008 are estimated at $17 to $19
million.
During the third quarter of 2006, we purchased a 24.9999% interest in Grizzly. As of December 31, 2007,
our net investment in Grizzly was approximately $27.8 million. Capital requirements in 2008 for this project are
now estimated to be approximately $8 to $10 million, primarily for the expenses associated with our 2007/2008
55 to 60 well core hole drilling program, a seismic program and additional lease acquisitions.
Capital expenditures in 2008 relating to our interest in Thailand are expected to be approximately $1.0
million, which we believe will be mostly offset from our share of production from the Phu Horm field.
Capital expenditures in 2008 relating to our interest in the Bakken Shale in the Williston Basin are expected
to be approximately $10.0 million, which we believe will be partially offset from our share of production from
the field.
We anticipate that our capital requirements for our properties in the Permian Basin in West Texas purchased
on December 20, 2007 will be approximately $35 million during 2008. We have identified 178 gross future
development drilling locations. We currently expect that approximately 17 to 22 net wells will be drilled on this
acreage in 2008.
Our total capital expenditures for 2008 are currently estimated to be $95 million. We believe that our cash
on hand, cash flow from operations and borrowings under our credit facility will be sufficient to meet our normal
recurring operating needs, debt service obligations, and our WCBB, Hackberry, Bakken, and Permian Basin
capital requirements for the next twelve months. In the event we elect to further expand or accelerate our drilling
programs, pursue acquisitions or accelerate our Canadian oil sands project, we will be required to obtain
additional funds which we may do so through traditional borrowings, offerings of debt or equity securities or
other means, including the sale of assets. Needed capital may not be available to us on acceptable terms or at all.
If we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail
implementation of our business plan or not be able to complete acquisitions that may be favorable to us.
Commodity Price Risk
To mitigate the effects of commodity price fluctuations, during 2007, we entered into forward sales
contracts for the sale of 3,000 barrels of production per day for the month of June 2007 at a weighted average
daily price of $70.15 per barrel before transportation costs. For the period of July 2007 through December 2007,
we entered into forward sales contracts for the sale of 3,500 barrels of production per day at a weighted average
daily price of $70.29 per barrel before transportation costs. In addition, we have entered into agreements to sell
3,500 barrels of production per day for the month of January through May 2008 at a weighted average daily price
of $70.29 per barrel before transportation costs. For the month of June 2008, we have agreements to sell 3,500
44
barrels of production per day at a weighted average daily price of $71.69 per barrel before transportation costs.
For the month of July 2008, we have agreements to sell 3,000 barrels of production per day at a weighted average
daily price of $81.37 per barrel before transportation costs. For August 2008, we have agreements to sell 3,000
barrels of production per day at a weighted average daily price of $82.44 per barrel before transportation costs.
For the periods of September 2008 through December 2008, we have entered into forward sales contracts for the
sale of 3,000 barrels of production per day in each such period at weighted average daily prices of $82.20 per
barrel before transportation costs. Under these agreements we have committed to deliver approximately 60% of
our estimated production for January through December 2008. For the period of January through December
2009, we entered into agreements to sell 2,500 barrels of production per day at a weighted average daily price of
$84.62 per barrel before transportation costs. Such arrangements may expose us to risk of financial loss in certain
circumstances, including instances where production is less than expected or oil prices increase. These contracts
require physical delivery of production quantities and are exempted from the provisions of SFAS 133 as normal
sales of production. In addition, these arrangements may limit the benefit to us of increases in the price of oil.
Commitments
In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, we
assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004 to
a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years
commencing March 11, 1997. Chevron retained a security interest in production from these properties until
abandonment obligations to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in
plugging and abandonment charges associated with the property. As of December 31, 2007, the plugging and
abandonment trust totaled approximately $3,104,000, including interest received during 2007 of approximately
$126,000. At December 31, 2007, we had plugged 243 wells at WCBB since we began our plugging program in
1997. An additional ten wells were plugged in January 2008, which management believes fulfills our minimum
plugging obligation through March 31, 2008.
Contractual and Commercial Obligations
Contractual Obligations
Total
Less than 1 year
1-3 years
3-5 years
More than 5
years
Short-term and long-term debt
. . . . . . .
Asset retirement obligations . . . . . . . . .
$66,533,000
8,634,000
$ 808,000
480,000
$64,288,000
1,228,000
$1,437,000
779,000
$
—
6,147,000
Total
. . . . . . . . . . . . . . . . . . . . . . .
$75,167,000
$1,288,000
$65,516,000
$2,216,000
$6,147,000
Payment due by period
New Accounting Pronouncements
We adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation
of FASB Statement No. 109,” as of January 1, 2007. The adoption of this Interpretation had no effect on our
consolidated financial statements. We are subject to U.S. federal income tax as well as income tax of multiple
state jurisdictions. Our 1996–2006 U.S. federal and state income tax returns remain open to examination by the
Internal Revenue Service. We are continuing our practice of recognizing interest and penalties related to income
tax matters as interest expense and general and administrative expenses, respectively.
SFAS 157
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 addresses
how companies should measure fair value when they are required to use a fair value measure for recognition or
disclosure purposes under generally accepted accounting principles. SFAS No. 157 defines fair value, establishes
a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 is
effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. However, in
February, 2008, the FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157” which delays
45
the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except for items that
are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This
FSP partially defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and
interim periods within those fiscal years for items within the scope of this FSP. We are currently assessing the
impact, if any, of the adoption of SFAS 157.
SFAS No. 159
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and
Financial Liabilities—Including an Amendment of FASB Statement No. 115.” SFAS No. 159 permits companies
to choose to measure certain financial instruments and other items at fair value. The objective is to improve
financial reporting by providing companies with the opportunity to mitigate volatility in reported earnings caused
by measuring related assets and liabilities differently without having to apply complex hedge accounting
provisions. Unrealized gains and losses on any items for which we elect the fair value measurement option would
be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We are
currently assessing the impact, if any, of the adoption of SFAS No. 159.
SFAS No. 141(R)
In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS
141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for
how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities
assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also
establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the
business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins
after December 15, 2008. We are currently assessing the impact, if any, the adoption of SFAS No. 141(R) may
have on any future acquisitions.
SFAS No. 160
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial
Statements—an amendment of ARB No. 51.” SFAS 160 requires that accounting and reporting for minority
interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160
also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish
between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities
that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those
entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a
subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after
December 15, 2008. We are currently assessing the impact, if any, of the adoption of SFAS 160.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and
natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and
natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand,
market uncertainty and a variety of additional factors, including: worldwide and domestic supplies of oil and
natural gas; the level of prices, and expectations about future prices, of oil and natural gas; the cost of exploring
for, developing, producing and delivering oil and natural gas; the expected rates of declining current production;
weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; the level
of consumer demand; the price and availability of alternative fuels; technical advances affecting energy
consumption; risks associated with operating drilling rigs; the availability of pipeline capacity; the price and level
of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members of the
Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
political instability or armed conflict in oil and natural gas producing regions; and the overall economic
environment.
46
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and
natural gas price movements with any certainty. For example, over the last four years, the West Texas
Intermediate posted price for crude oil has ranged from a low of $30.83 per barrel, or bbl, in January 2004 to a
high of $102.20 per bbl on March 6, 2008. The Henry Hub spot market price of natural gas has ranged from a
low of $4.20 per million British thermal units, or MMBtu, in October 2006 to a high of $13.93 per MMBtu in
October 2005. On December 31, 2007, the West Texas Intermediate posted price for crude oil was $92.50 per bbl
and the Henry Hub spot market price of natural gas was $6.80 per MMBtu. Any substantial decline in the price
of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of
expenditures for the development of our oil and natural gas reserves, and may result in write downs of oil and
natural gas properties due to ceiling test limitations. To mitigate the effects of commodity price fluctuations,
during 2007, we entered into forward sales contracts for the sale of 3,000 barrels of production per day for the
month of June 2007 at a weighted average daily price of $70.15 per barrel before transportation costs. For the
period of July 2007 through December 2007, we entered into forward sales contracts for the sale of 3,500 barrels
of production per day at a weighted average daily price of $70.29 per barrel before transportation costs. In
addition, we have entered into agreements to sell 3,500 barrels of production per day for the months of January
through May 2008 at a weighted average daily price of $70.29 per barrel before transportation costs. For the
month of June 2008, we have agreements to sell 3,500 barrels of production per day at a weighted average daily
price of $71.69 per barrel before transportation costs. For the month of July 2008, we have agreements to sell
3,000 barrels of production per day at a weighted average daily price of $81.37 per barrel before transportation
costs. For August 2008, we have agreements to sell 3,000 barrels of production per day at a weighted average
daily price of $82.44 per barrel before transportation costs. For the periods of September 2008 through December
2008, we have entered into forward sales contracts for the sale of 3,000 barrels of production per day in each
such period at weighted average daily prices of $82.20 per barrel before transportation costs. Under these
agreements we have committed to deliver approximately 60% of our estimated production for January through
December 2008. For the period of January through December 2009, we entered into agreements to sell 2,500
barrels of production per day at a weighted average daily price of $84.62 per barrel before transportation costs.
Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where
production is less than expected or oil prices increase. These contracts require physical delivery of production
quantities and are exempted from the provisions of SFAS 133 as normal sales of production. In addition, these
arrangements may limit the benefit to us of increases in the price of oil.
Our credit facility and term loan with Bank of America are structured under floating rate terms and, as such,
our interest expense is sensitive to fluctuations in the prime rates in the U.S. Borrowings under our revolving
credit facility with Bank of America bear interest at Bank of America prime plus 0.25% (7.5 % at December 31,
2007). Borrowings under our term loan with Bank of America bear interest at Bank of America prime (7.25 % at
December 31, 2007). Based on the current debt structure, a 1% increase in interest rates would increase interest
expense by approximately $638,000 per year, based on an aggregate of $63.8 million outstanding under our
credit facilities as of December 31, 2007. As of December 31, 2007, we did not have any interest rate swaps to
hedge our interest risks.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item appears beginning on page F-1 following the signature pages of this
Report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
47
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Control and Procedures. Under the direction of our Chief Executive Officer and
Vice President and Chief Financial Officer, we have established disclosure controls and procedures that are
designed to ensure that information required to be disclosed by us in the reports that we file or submit under the
Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods
specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that
such information is accumulated and communicated to management, including our Chief Executive Officer and
Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding required
disclosures.
As of December 31, 2007, an evaluation was performed under the supervision and with the participation of
management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the
effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15
under the Securities Exchange Act of 1934. Based upon our evaluation, our Chief Executive Officer and Vice
President and Chief Financial Officer have concluded that as of December 31, 2007, our disclosure controls and
procedures are effective.
Changes in Internal Control over Financial Reporting. There have not been any changes in our internal
control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are
reasonably likely to materially affect, internal controls over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for the fair presentation of the consolidated financial statements of Gulfport
Energy Corporation. Management is also responsible for establishing and maintaining a system of internal
controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of
1934, as amended. These internal controls are designed to provide reasonable assurance that the reported
financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the
preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any
system of internal control, including the possibility of human error and overriding of controls. Consequently, an
effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting
financial information.
Management conducted an evaluation of the effectiveness of our internal control over financial reporting
based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control—
Integrated Framework, management did not identify any material weaknesses in our internal control over
financial reporting and concluded that our internal control over financial reporting was effective as of
December 31, 2007.
Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements
for the year ended December 31, 2007 included with this Annual Report on Form 10-K, has also audited our
internal control over financial reporting as of December 31, 2007, as stated in their accompanying report.
/s/ James D. Palm
Name:
Title:
James D. Palm
Chief Executive Officer
/s/ Michael G. Moore
Name: Michael G. Moore
Title:
Chief Financial Officer
48
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Gulfport Energy Corporation:
We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the
“Company”) as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s
management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying
Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion
on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether effective internal control over financial reporting was maintained in all material respects. Our audit
included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the
company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework
issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the consolidated balance sheets of the Company as of December 31, 2007 and 2006, and the
related consolidated statements of operations, stockholders’ equity and comprehensive income and cash flows for
each of the three years in the period ended December 31, 2007 and our report dated March 17, 2008 expressed an
unqualified opinion.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
March 17, 2008
ITEM 9B. OTHER INFORMATION
None.
49
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
For information concerning Item 10—Directors, Executive Officers and Corporate Governance, see our
definitive Information Statement, which will be filed with the Securities and Exchange Commission within 120
days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of
portions noted therein that are not incorporated by reference).
ITEM 11. EXECUTIVE COMPENSATION
For information concerning Item 11—Executive Compensation, see our definitive Information Statement,
which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous
fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not
incorporated by reference).
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
For information concerning Item 12—Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters, see our definitive Information Statement, which will be filed with the
Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is
incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by
reference).
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
For information concerning Item 13—Certain Relationships and Related Transactions, and Director
Independence, see our definitive Information Statement, which will be filed with the Securities and Exchange
Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference
(with the exception of portions noted therein that are not incorporated by reference).
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
For information concerning Item 14—Principal Accounting Fees and Services, see our definitive
Information Statement, which will be filed with the Securities and Exchange Commission with 120 days after the
close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted
therein that are not incorporated by reference).
50
ITEM 15. EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES
List the following documents filed as part of this report:
PART IV
Exhibit
Number
2.1
2.2
3.1
3.2
4.1
4.2
4.3
4.4
4.5
Description
Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I,
Ltd. and each of the other persons, which are listed as a party seller, and Windsor Permian
(incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company
with the SEC on December 24, 2007).
Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and
among Ambrose Energy I, Ltd., each of the other parties which are listed as a party seller, Windsor
Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 000-19514,
filed by the Company with the SEC on December 24, 2007).
Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File
No. 000-19514, filed by the Company with the SEC on April 26, 2006).
Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No.
000-19514, filed by the Company with the SEC on July 12, 2006).
Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to
the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC
on July 22, 2004).
Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the
Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the SEC on
July 22, 2004).
Registration Rights Agreement, dated as of February 23, 2005, by and among the Company,
Southpoint Fund LP, a Delaware limited partnership, Southpoint Qualified Fund LP, a Delaware
limited partnership and Southpoint Offshore Operating Fund, LP, a Cayman Islands exempted
limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514,
filed by the Company with the SEC on March 31, 2005).
Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy
Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party
thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, File No. 000-19514, filed by the
Company with the SEC on November 11, 2005).
Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of
March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, certain other
affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit
10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31,
2006).
10.1+
10.2+
10.3+
Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form
8-K, File No. 000-19514, filed by the Company with the SEC on April 26, 2006).
Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No.
000-19514, filed by the Company with the SEC on April 26, 2006).
Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K,
File No. 000-19514, filed by the Company with the SEC on April 26, 2006).
51
Exhibit
Number
10.4+
10.5
10.6
10.7
10.8
10.9
10.10
14
21*
23.1*
23.2*
23.3*
31.1*
31.2*
32.1*
32.2*
Description
Employment Agreement, dated as of May 18, 1999 and effective as of June 1, 1999, by and between
the Registrant and Mike Liddell (incorporated by reference to Exhibit 10.5 of Amendment No. 1 to
Form 10-KSB/A, File No. 000-19514, filed by the Company with the SEC on May 11, 2007).
Credit Agreement, dated as of March 11, 2005, by and among the Company, each lender from time
to time party thereto and Bank of America, N.A., as agent (incorporated by reference to Exhibit 10.9
of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 2005).
Second Amendment to Credit Agreement, dated as of July 19, 2007, between the Company and Bank
of America, N.A. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 000-19514, filed
by the Company with the SEC on July 19, 2007).
Note dated July 19, 2007 issued by the Company for the benefit of Bank of America, N.A.
(incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 000-19514, filed by the Company
with the SEC on July 19, 2007).
Third Amendment to Credit Agreement, dated as of December 20, 2007, between the Company,
Bank of America, N.A., as a lender and administrative agent and such other lenders from time to
time party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 000-19514, filed
by the Company with the SEC on December 26, 2007).
Note dated December 20, 2007 issued by the Company for the benefit of Bank of America, N.A.
(incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 000-19514, filed by the Company
with the SEC on December 26, 2007).
Administrative Services Agreement, effective as of April 1, 2005, by and between Bronco Drilling
Company, Inc. and Gulfport Energy Corporation (incorporated by reference from Exhibit 10.1 of
Form 10-QSB, File No. 000-19514, filed by the Company with the SEC on August 15, 2005).
Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by
the Company with the SEC on February 14, 2006).
Subsidiaries of the Registrant.
Consent of Grant Thornton LLP.
Consent of Netherland, Sewell & Associates, Inc.
Consent of Pinnacle Energy Services, LLC
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated
under the Securities Exchange Act of 1934, as amended.
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated
under the Securities Exchange Act of 1934, as amended.
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated
under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18
of the United States Code.
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated
under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18
of the United States Code.
Filed herewith
*
+ Management contract, compensatory plan or arrangement.
52
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Date: March 17, 2008
GULFPORT ENERGY CORPORATION
By:
/S/
JAMES D. PALM
James D. Palm
Chief Executive Officer
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf
of the registrant and in the capacities and on the dates indicated.
Date: March 17, 2008
Date: March 17, 2008
Date: March 17, 2008
Date: March 17, 2008
Date: March 17, 2008
Date: March 17, 2008
/S/
JAMES D. PALM
James D. Palm
Chief Executive Officer and Director
(Principal Executive Officer)
/S/ MIKE LIDDELL
Mike Liddell
Chairman of the Board and Director
/S/ MICHAEL G. MOORE
Michael G. Moore
Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
/S/ DONALD DILLINGHAM
Donald Dillingham
Director
/S/ DAVID L. HOUSTON
David L. Houston
Director
/S/ SCOTT E. STRELLER
Scott E. Streller
Director
By:
By:
By:
By:
By:
By:
S-1
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheets, December 31, 2007 and December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Operations, Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . .
Consolidated Statements of Stockholders’ Equity and Comprehensive Income, Years Ended December 31,
2007, 2006 and 2005
Consolidated Statements of Cash Flows, Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . .
Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
F-2
F-3
F-4
F-5
F-6
F-7
F-1
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Gulfport Energy Corporation:
We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries
(the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations,
stockholders’ equity and comprehensive income and cash flows for each of the three years in the period ended
December 31, 2007. These financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
financial position of Gulfport Energy Corporation and Subsidiaries as of December 31, 2007 and 2006, and the
results of their operations and their cash flows for each of the three years in the period ended December 31, 2007,
in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, the Company adopted Statement of Financial
Accounting Standards No. 123 (revised 2004), Share-Based Payment, on a modified prospective basis effective
January 1, 2006.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO) and our report dated March 17, 2008 expressed an
unqualified opinion.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
March 17, 2008
F-2
GULFPORT ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31,
2007
December 31,
2006
Current assets:
Assets
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable—oil and gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Insurance settlement receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable—related parties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2,764,000
10,510,000
—
2,208,000
1,346,000
$
6,627,000
7,585,000
541,000
4,202,000
972,000
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16,828,000
19,927,000
Property and equipment:
Oil and natural gas properties, full-cost accounting,
$37,278,000 and $1,459,000 excluded from amortization in 2007 and
2006, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated depletion, depreciation and amortization . . . . . . . . . . . . . . . .
484,487,000
7,108,000
(129,496,000)
250,838,000
6,651,000
(99,815,000)
Property and equipment, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
362,099,000
157,674,000
Other assets:
Equity investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
33,822,000
6,388,000
14,363,000
3,187,000
Total other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
40,210,000
17,550,000
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 419,137,000
$195,151,000
Current liabilities:
Liabilities and Stockholders’ Equity
Accounts payable and accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation—current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current maturities of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 39,848,000
480,000
808,000
$ 24,793,000
480,000
835,000
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
41,136,000
26,108,000
Asset retirement obligation—long-term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, net of current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,154,000
65,725,000
8,378,000
36,856,000
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
115,015,000
71,342,000
Commitments and contingencies (Notes 18 and 19)
Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as
redeemable 12% cumulative preferred stock, Series A; 0 issued and
outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stockholders’ equity:
—
—
Common stock—$.01 par value, 55,000,000 authorized, 42,453,587 issued
and outstanding in 2007 and 33,659,759 in 2006 . . . . . . . . . . . . . . . . . . .
Paid-in capital
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings (accumulated deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
424,000
271,807,000
2,254,000
29,637,000
337,000
131,610,000
—
(8,138,000)
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
304,122,000
123,809,000
Total liabilities and stockholders’ equity . . . . . . . . . . . . . . . . . .
$ 419,137,000
$195,151,000
See accompanying notes to consolidated financial statements.
F-3
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
2007
2006
2005
Revenues:
Oil and condensate sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income (expense)
$100,120,000
6,043,000
(325,000)
$56,038,000
4,194,000
158,000
$23,986,000
3,437,000
136,000
105,838,000
60,390,000
27,559,000
Costs and expenses:
Lease operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation, depletion and amortization . . . . . . . . . . . . . . . . .
General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16,670,000
12,667,000
29,681,000
5,802,000
554,000
10,670,000
7,366,000
12,652,000
3,251,000
596,000
7,654,000
3,622,000
4,789,000
1,561,000
516,000
INCOME FROM OPERATIONS
OTHER (INCOME) EXPENSE:
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense—preferred stock . . . . . . . . . . . . . . . . . . . . . . .
Business interruption insurance recoveries . . . . . . . . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
65,374,000
34,535,000
18,142,000
40,464,000
25,855,000
9,417,000
3,091,000
—
—
(523,000)
1,956,000
—
(3,601,000)
(308,000)
250,000
272,000
(1,710,000)
(290,000)
2,568,000
(1,953,000)
(1,478,000)
INCOME BEFORE INCOME TAXES . . . . . . . . . . . . . . . . . . . . . .
37,896,000
27,808,000
10,895,000
INCOME TAX EXPENSE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
121,000
—
—
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 37,775,000
$27,808,000
$10,895,000
NET INCOME PER COMMON SHARE:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
1.03
1.01
$
$
0.85
0.82
$
$
0.36
0.34
See accompanying notes to consolidated financial statements.
F-4
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
GULFPORT ENERGY CORPORATION
Common Stock
Shares Amount
Additional
Paid-in
Capital
Notes
Receivable
for
Exercise
of Options
Balance at January 1, 2005 . . . . . . . . . . . 20,146,566 $201,000 $ 95,737,000 $
Net income . . . . . . . . . . . . . . . . . . . . . . .
Other Comprehensive Income:
Deferred gain on settled contracts . . . .
Loss on hedging ineffectiveness . . . . .
Unrealized gain on hedges . . . . . . . . .
—
—
—
—
—
—
—
—
—
—
—
—
Total Comprehensive Income . . . . .
Issuance of Common Stock . . . . . . . . . . 4,000,000
Issuance of Common Stock through
40,000
13,960,000
exercise of warrants . . . . . . . . . . . . . . 7,958,470
80,000
9,390,000
Issuance of Common Stock through
—
—
—
—
—
—
—
exercise of options . . . . . . . . . . . . . . .
63,167
1,000
105,000
(105,000)
Repayment of Notes Receivable for
Stock . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
— 105,000
Balance at December 31, 2005 . . . . . . . . . 32,168,203 322,000 119,192,000
—
—
—
Net income . . . . . . . . . . . . . . . . . . . . . . .
Other Comprehensive Income:
Deferred gain on settled contracts . . . .
Gain on hedging ineffectiveness . . . . .
Reclassification adjustment on settled
hedges . . . . . . . . . . . . . . . . . . . . . . .
Total Comprehensive Income . . . . .
Stock Compensation . . . . . . . . . . . . . . . .
Issuance of Common Stock in public
offering, net of related expenses of
$479,000 . . . . . . . . . . . . . . . . . . . . . . .
Issuance of Restricted Stock . . . . . . . . . .
Issuance of Common Stock through
—
—
—
—
—
—
—
—
—
—
—
1,063,000
790,000
21,981
8,000
—
9,965,000
—
exercise of Warrants . . . . . . . . . . . . . .
113,852
1,000
120,000
Issuance of Common Stock through
exercise of Options . . . . . . . . . . . . . . .
565,723
6,000
1,270,000
Balance at December 31, 2006 . . . . . . . . . 33,659,759 337,000 131,610,000
—
—
—
Net income . . . . . . . . . . . . . . . . . . . . . . .
Other Comprehensive Income:
Foreign currency translation
adjustment . . . . . . . . . . . . . . . . . . . .
Total Comprehensive Income . . . . .
Stock Compensation . . . . . . . . . . . . . . . .
Issuance of Common Stock in public
—
—
—
—
—
1,158,000
offerings, net of related expenses of
$740,000 . . . . . . . . . . . . . . . . . . . . . . . 8,547,500
35,930
Issuance of Restricted Stock . . . . . . . . . .
Issuance of Common Stock through
85,000 138,173,000
—
—
exercise of options . . . . . . . . . . . . . . .
210,398
2,000
866,000
Balance at December 31, 2007 . . . . . . . . . 42,453,587 $424,000 $271,807,000 $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Accumulated
Other
Comprehensive
Income
Retained
Earnings
(Accumulated
Deficit)
Total
Stockholders’
Equity
$
—
—
$(46,841,000) $ 49,097,000
10,895,000
10,895,000
114,000
24,000
621,000
—
—
—
—
—
—
—
—
—
—
—
114,000
24,000
621,000
11,654,000
14,000,000
9,470,000
1,000
105,000
759,000
—
(35,946,000)
27,808,000
84,327,000
27,808,000
(114,000)
(24,000)
(621,000)
—
—
—
—
—
—
—
2,254,000
—
—
—
—
—
—
—
—
—
—
—
—
(114,000)
(24,000)
(621,000)
27,049,000
1,063,000
9,973,000
—
121,000
1,276,000
(8,138,000)
37,775,000
123,809,000
37,775,000
—
—
2,254,000
40,029,000
1,158,000
— 138,258,000
—
—
—
868,000
$2,254,000
$ 29,637,000 $304,122,000
See accompanying notes to consolidated financial statements.
F-5
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flows from operating activities:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustments to reconcile net income to net cash provided by operating
activities:
Year Ended December 31,
2007
2006
2005
$ 37,775,000
$ 27,808,000
$ 10,895,000
Accretion of discount—Asset Retirement Obligation . . . . . . . . . . .
Interest expense—preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . .
Depletion, depreciation and amortization . . . . . . . . . . . . . . . . . . . .
Stock-based compensation expense . . . . . . . . . . . . . . . . . . . . . . . . .
Loss from equity investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized (gain) loss on hedge ineffectiveness . . . . . . . . . . . . . . .
554,000
—
29,681,000
845,000
477,000
—
596,000
—
12,652,000
787,000
76,000
(24,000)
516,000
272,000
4,789,000
—
—
24,000
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable . . . . . . . . . . . . . . . . . . . .
Decrease (increase) in business interruption insurance settlement
receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decrease (increase) in accounts receivable—related party . . . . . . .
Increase in prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decrease in deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in accounts payable and accrued liabilities . . . . . . . . . . . .
(Increase) decrease in deferred hedge gains . . . . . . . . . . . . . . . . . . .
Settlement of asset retirement obligation . . . . . . . . . . . . . . . . . . . . .
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash flows from investing activities:
Additions to cash held in escrow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additions to deposits for oil and gas properties . . . . . . . . . . . . . . . . . . . .
Additions to other property, plant and equipment . . . . . . . . . . . . . . . . . .
Additions to oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of oil and gas properties . . . . . . . . . . . . . . . . . . . . . .
Investment in Grizzly Oil Sands ULC . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment in Tatex Thailand II, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment in Windsor Bakken, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash flows from financing activities:
Principal payments on borrowings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Borrowings on line of credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Redemption of Series A, Preferred Stock . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from issuance of common stock, net of offering costs of
(2,925,000)
(6,609,000)
2,584,000
—
1,994,000
(374,000)
—
2,153,000
—
(1,278,000)
68,902,000
(121,000)
(3,080,000)
(457,000)
(220,044,000)
500,000
(17,316,000)
(88,000)
(127,000)
(240,733,000)
1,710,000
(832,000)
(490,000)
107,000
4,608,000
(114,000)
(752,000)
39,523,000
(105,000)
—
(495,000)
(62,403,000)
—
(8,493,000)
(964,000)
(1,416,000)
(73,876,000)
(1,710,000)
(2,347,000)
(270,000)
—
1,074,000
114,000
(741,000)
15,200,000
(57,000)
—
(467,000)
(31,995,000)
70,000
—
(2,502,000)
(1,752,000)
(36,703,000)
(47,158,000)
76,000,000
(10,809,000)
38,300,000
—
—
(204,000)
7,000,000
(14,292,000)
$740,000 and $479,000, and exercise of stock options . . . . . . . . . . . .
Net cash provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
139,126,000
167,968,000
11,370,000
38,861,000
23,576,000
16,080,000
Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at beginning of period . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplemental disclosure of cash flow information:
Interest payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplemental disclosure of non-cash transactions:
Investment subscription payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capitalized stock based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payment of Series A Preferred Stock dividends through issuance of
Series A Preferred Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation capitalized . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
(3,863,000)
6,627,000
2,764,000
4,508,000
2,119,000
$ 6,627,000
(5,423,000)
7,542,000
$ 2,119,000
3,341,000
$ 1,956,000
$
250,000
121,000
151,000
313,000
$
$
$
— $
—
— $
688,000
276,000
$
—
— $
— $
272,000
500,000
$
405,000
$ 1,382,000
See accompanying notes to consolidated financial statements.
F-6
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2007, 2006 AND 2005
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business
Gulfport Energy Corporation (“Gulfport” or the “Company”) is a domestic independent oil and gas
exploration, development and production company with its principal properties located in the Louisiana Gulf
Coast. Gulfport also recently acquired strategic assets in West Texas in the Permian Basin and has investments in
companies operating in Canada and Thailand.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be
cash equivalents for purposes of the statement of cash flows.
Principles of Consolidation
The consolidated financial statements include the Company and its wholly owned subsidiaries, Grizzly
Holdings Inc. and Jaguar Resources LLC. All intercompany balances and transactions are eliminated in
consolidation.
Accounts Receivable
The Company’s accounts receivable—oil and gas primarily are from companies in the oil and gas industry
located in the southwestern part of the United States. The majority of its receivables are from two purchasers of
the Company’s oil and gas. Credit is extended based on evaluation of a customer’s payment history and,
generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due
from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful.
Accounts outstanding longer than the contractual payment terms are considered past due. The Company
determines its allowance by considering a number of factors, including the length of time accounts receivable are
past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the
Company, amounts which may be obtained by an offset against production proceeds due the customer and the
condition of the general economy and the industry as a whole. The Company writes off specific accounts
receivable when they become uncollectible, and payments subsequently received on such receivables are credited
to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2007 and
December 31, 2006.
Oil and Gas Properties
The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs,
including nonproductive costs and certain general and administrative costs directly associated with acquisition,
exploration and development of oil and gas properties, are capitalized. Net capitalized costs are limited to the
estimated future net revenues, as adjusted for the Company’s cash flow hedge positions and net of tax effects,
discounted at 10% per year, from proven oil and gas reserves and the cost of the properties not subject to
amortization. Such capitalized costs, including the estimated future development costs and site remediation costs
of proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to
barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and
gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven
oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds
and totaled $37,278,000 and $1,459,000 at December 31, 2007 and December 31, 2006, respectively. These costs
are reviewed periodically by management for impairment, with the impairment provision included in the cost of
F-7
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
oil and gas properties subject to amortization. Factors considered by management in its impairment assessment
include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production,
and available funds for exploration and development.
The Company accounts for its abandonment and restoration liabilities under Statement of Financial
Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), which
requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset
retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is
generally when the asset is placed into service. When the liability is initially recorded, the Company increases the
carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is
accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related
long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability
amounts may change because of changes in asset lives, estimated costs of abandonment or legal or statutory
remediation requirements.
Other Property and Equipment
Depreciation of other property and equipment is provided on a straight-line basis over estimated useful lives
of the related assets, which range from 7 to 30 years.
Foreign Currency
The U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company
has an equity investment in a Canadian entity whose functional currency is the Canadian dollar. The assets and
liabilities of the Canadian investment are translated into U.S. dollars based on the current exchange rate in effect
at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods
presented. Translation adjustments have no effect on net income and are included in accumulated other
comprehensive income in stockholders’ equity.
Net Income per Common Share
Basic net income per common share is computed by dividing income attributable to common stock by the
weighted average number of common shares outstanding for the period. Diluted net income per common share
reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised
or converted into common stock. Potential common shares are not included if their effect would be anti-dilutive.
Calculations of basic and diluted net income per common share are illustrated in Note 14.
Income Taxes
Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets
and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial
statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit
carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future
period when those temporary differences are expected to be recovered or settled. The effect of a change in tax
rates on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted.
Deferred tax assets are recognized as income in the year in which realization becomes determinable. A valuation
allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be
realized.
F-8
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
Revenue Recognition
Gas revenues are recorded in the month produced and delivered to the purchaser using the entitlement
method, whereby any production volumes received in excess of the Company’s ownership percentage in the
property are recorded as a liability. If less than Gulfport’s entitlement is received, the underproduction is
recorded as a receivable. There is no such liability or asset recorded at December 31, 2007 and 2006 because the
Company has no imbalances. Oil revenues are recognized when ownership transfers, which occurs in the month
produced.
Investments—Equity Method
Investments in entities greater than 20% and less than 50% are accounted for under the equity method.
Under the equity method, the Company’s share of investees’ earnings or loss is recognized in the statement of
operations.
Accounting for Stock-Based Compensation
Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standard No. 123(R),
“Share-Based Payment” (“SFAS No. 123(R)”), using the modified prospective transition method. SFAS
No. 123(R) requires share-based payments to employees, including grants of employee stock options, to be
recognized as equity or liabilities at the fair value on the date of grant and to be expensed over the applicable
vesting period. Under the modified prospective transition method, share-based awards granted or modified on or
after January 1, 2006, are recognized as compensation expense over the applicable vesting period. Also, any
previously granted awards that are not fully vested as of January 1, 2006 are recognized as compensation expense
over the remaining vesting period. No retroactive or cumulative effect adjustments were required upon the
Company’s adoption of SFAS No. 123(R) (see Note 10). The shares of stock issued once the options are
exercised will be from authorized but unissued common stock.
Prior to adopting SFAS No. 123(R), the Company accounted for its fixed-plan employee stock options using
the intrinsic-value based method prescribed by Accounting Principles Board Opinion No. 25, “Accounting for
Stock Issued to Employees” (“APB No. 25”), and related interpretations. This method required compensation
expense to be recorded on the date of grant only if the current market price of the underlying stock exceeded the
exercise price.
If the Company had elected the fair value provisions of SFAS No. 123(R) and recognized compensation
expense over the vesting period based on the fair value of the stock options granted as of their grant date, the
Company’s 2005 net income and net income per share would have differed from the amounts actually reported as
shown in the following table.
Year Ended
December 31, 2005
Net income, as reported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock-based employee compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$10,895,000
248,000
Net income, pro forma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$10,647,000
Net income per share:
As reported:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pro forma:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
0.36
0.34
0.35
0.33
F-9
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
Accounting for Derivative Instruments and Hedging Activities
The Company may seek to reduce its exposure to unfavorable changes in oil prices by utilizing energy
swaps and collars (collectively “price swap contracts”). The Company follows the provisions of SFAS 133,
“Accounting for Derivative Instruments and Hedging Activities.” as amended. It requires that all derivative
instruments be recognized as assets or liabilities in the statement of financial position, measured at fair value.
The Company estimates the fair value of all derivative instruments using established index prices and other
sources. These values are based upon, among other things, futures prices, correlation between index prices and
the Company’s realized prices, time to maturity and credit risk. The values reported in the consolidated financial
statements change as these estimates are revised to reflect actual results, changes in market conditions or other
factors.
Accounting for changes in the fair value of a derivative depends on the intended use of the derivative and
the resulting designation. Designation is established at the inception of a derivative, but re-designation is
permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133,
changes in fair value are recognized in other comprehensive income until the hedged item is recognized in
earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between
the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is
recognized immediately in earnings. The Company had no derivative contracts at December 31, 2007 and 2006.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the
United States of America requires management to make estimates, judgments and assumptions that affect the
reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses
during the reporting period. Actual results could differ materially from those estimates. Significant estimates
with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the
related present value of estimated future net cash flows there from, the amount and timing of asset retirement
obligations and the realization of future net operating loss carryforwards available as reductions of income tax
expense.
Recent Accounting Pronouncements
The Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an
interpretation of FASB Statement No. 109,” as of January 1, 2007. The adoption of FIN 48 had no effect on the
Company’s consolidated financial statements. The Company is subject to U.S. federal income tax as well as
income tax of multiple state jurisdictions. The Company’s 1996-2006 U.S. federal and state income tax returns
remain open to examination by tax authorities. As of December 31, 2007, the Company has no unrecognized tax
benefits that would have a material impact on the effective tax rate. The Company is continuing its practice of
recognizing interest and penalties related to income tax matters as interest expense and general and
administrative expenses, respectively. For the year ended December 31, 2007, there is no interest or penalties
associated with uncertain tax positions in the Company’s consolidated financial statements.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 addresses
how companies should measure fair value when they are required to use a fair value measure for recognition or
disclosure purposes under generally accepted accounting principles. SFAS No. 157 defines fair value, establishes
a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 is
effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. However, in
F-10
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
February, 2008, the FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157” which delays
the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except for items that
are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This
FSP partially defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and
interim periods within those fiscal years for items within the scope of this FSP. The Company is currently
assessing the impact, if any, of the adoption of SFAS 157.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and
Financial Liabilities—Including an Amendment of FASB Statement No. 115.” SFAS No. 159 permits companies
to choose to measure certain financial instruments and other items at fair value. The objective is to improve
financial reporting by providing companies with the opportunity to mitigate volatility in reported earnings caused
by measuring related assets and liabilities differently without having to apply complex hedge accounting
provisions. Unrealized gains and losses on any items for which the Company elects the fair value measurement
option would be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15,
2007. The Company does not expect the adoption of SFAS No. 159 to have a material impact to its consolidated
financial statements.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS
141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for
how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities
assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also
establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the
business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins
after December 15, 2008. The Company is currently assessing the impact, if any, the adoption of SFAS
No. 141(R) may have on any future acquisitions.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial
Statements—an amendment of ARB No. 51.” SFAS 160 requires that accounting and reporting for minority
interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160
also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish
between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities
that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those
entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a
subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after
December 15, 2008. The Company is currently assessing the impact, if any, of the adoption of SFAS 160.
2. ACQUISITIONS
On December 20, 2007, Gulfport closed on the acquisition of an ownership interest in certain oil and gas
properties located in the Permian Basin of West Texas, consisting of approximately 4,100 net acres with 32 gross
producing wells from ExL Petroleum, LP and 12 other sellers for a cash price of approximately $85 million. The
effective date of the acquisition was November 1, 2007. The total purchase price for the assets, as adjusted at the
original closing on December 20, 2007, was $85.2 million, which was recorded as oil and natural gas properties
on the accompanying consolidated balance sheet. This amount includes an adjustment for the results of
operations of the assets between the November 1, 2007 effective date and the December 20, 2007 closing date.
The Company may adjust the purchase price for any post closing adjustments, scheduled 90 days from the
original closing date of December 20, 2007. The results of operations from these properties were included in the
2007 consolidated statement of operations only for the period subsequent to the closing date, in this case, for the
period of December 21, 2007 through December 31, 2007.
F-11
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
Gulfport funded this transaction predominately through a 4.5 million common share offering, which closed
on December 12, 2007. The Company received net proceeds of approximately $75.6 million from the equity
offering, as discussed below in Note 9. The Company funded the remainder of the purchase price from
borrowings on its line of credit.
The following unaudited pro forma results for the year ended December 31, 2006 show the effect on the
Company’s consolidated results of operations as if the acquisition had occurred on January 1, 2006. The
unaudited pro forma results for the year ended December 31, 2007 show the effect on the Company’s
consolidated results of operations as if the acquisition had occurred on January 1, 2007. The pro forma results for
the 2006 and 2007 periods presented are the result of combining the Company’s consolidated statements of
operations with the revenues and direct operating expenses of the acquired properties adjusted for (1) incremental
depletion, depreciation, and amortization of oil and natural gas properties associated with the acquisition,
amortized on a unit-of-production basis over the remaining life of total proved reserves, as applicable,
(2) incremental accretion of discount on asset retirement obligation associated with the acquired properties,
(3) estimated incremental interest expense associated with borrowings under Gulfport’s revolving credit facility
to fund the acquisition, and (4) the issuance of 4.5 million shares of common stock in the offering at January 1,
2006 and January 1, 2007 rather than December 12, 2007. The pro forma information is based upon numerous
assumptions, and is not necessarily indicative of what the Company’s actual results would have been or the
Company’s future results of operations.
Total revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income per common share:
Unaudited
Year Ended December 31,
2007
2006
$121,903,000
46,799,000
$64,458,000
29,029,000
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
1.14
1.12
$
$
0.78
0.76
3.
INSURANCE SETTLEMENT RECEIVABLE
The Company sustained damage to both its Hackberry field located in Cameron Parish, Louisiana and its
West Cote Blanche Bay (“WCBB”) field located in St. Mary Parish, Louisiana as a result of Hurricane Rita in
September 2005. As of December 31, 2007, the Company had incurred costs of $14,388,000 relating to the
damage to the fields and facilities. Of this amount, $250,000 represents insurance deductible amounts that were
expensed to lease operating expenses in 2005. The Company received $8,396,000 in insurance proceeds related
to physical damage, of which $541,000 was received in the first quarter of 2007, which are reflected as investing
activity in the consolidated statements of cash flows. Approximately $5,634,000 of costs incurred during 2006
and the first quarter of 2007 related to equipment and facilities replacement costs which will not be reimbursed
by insurance and are included in the full cost pool. Approximately $108,000 previously included in insurance
settlement receivables was not collected and was expensed in 2006. At December 31, 2007, the Company had
collected all outstanding insurance receivable amounts related to physical damage.
The Company maintained business interruption insurance to cover lost production revenue in the event of
shut-in production. The business interruption insurance began 60 days after the occurrence of the insurable event,
subject to a daily limit of $45,000 and had a maximum coverage of 180 days. Coverage began on November 24,
2005 for shut-in production caused by Hurricane Rita. For the years ended December 31, 2006 and 2005, the
Company recognized $3,601,000 and $1,710,000, respectively, of business interruption insurance proceeds in
other income in the consolidated statements of operations. As of December 31, 2006, the Company had received
F-12
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
proceeds of $5,311,000 ($1,710,000 of which was accrued in 2005) related to business interruption for the period
of November 24, 2005 to May 1, 2006. Such recoveries are presented as operating cash flows in the consolidated
statements of cash flows. All business interruption recoveries were collected in 2006.
4. ACCOUNTS RECEIVABLE—RELATED PARTIES
Included in the accompanying December 31, 2007 and December 31, 2006 consolidated balance sheets are
amounts receivable from affiliates of the Company. These receivables represent amounts billed by the Company
for general and administrative functions, such as accounting, human resources, legal, and technical support,
performed by Gulfport’s personnel on behalf of the affiliates. These services are solely administrative in nature
and for entities in which the Company has no property interests. The amounts reimbursed to the Company for
these services are for the purpose of Gulfport recovering costs associated with the services and do not include the
assessment of any fees or other amounts beyond the estimated costs of performing such services. At
December 31, 2007 and December 31, 2006, this receivable amount totaled $2,208,000 and $4,202,000,
respectively. The Company was reimbursed $11,153,000, $12,738,000 and $6,232,000 for the years ended
December 31, 2007, 2006 and 2005, respectively, for general and administrative functions which are reflected as
a reduction of general and administrative expenses in the consolidated statements of operations and include the
amounts under service contracts discussed below.
The Company is or has been a party to administrative service agreements with Caliber Development
Company, LLC, Bronco Drilling Company, Inc., Great White Energy Services LLC, Diamondback Energy
Services LLC, Stampede Investments LLC and Grizzly Oil Sands ULC. Under the agreements, the Company’s
services include accounting, human resources, legal and technical support. The services provided and the fees for
such services can be amended by mutual agreement of the parties. The administrative service agreements have a
three-year term, and upon expiration of that term the agreements will continue on a month-to-month basis until
cancelled by either party with at least 30 days prior written notice. The administrative service agreements are
terminable (1) by the entity at any time with at least 30 days prior written notice to the Company and (2) by
either party if the other party is in material breach and such breach has not been cured within 30 days of receipt
of written notice of such breach. The Company was reimbursed the following amounts in consideration for those
services for the years ended December 31, 2007, 2006 and 2005. These amounts are reflected as a reduction of
general and administrative expenses in the consolidated statements of operations.
Agreement
Effective Date
Entity
2007
2006
2005
December 31,
Caliber Development Company, LLC . . . . . . . . . . . . . . . . .
2/9/2005
Bronco Drilling Company, Inc. * . . . . . . . . . . . . . . . . . . . . .
4/1/2005
Great White Energy Services LLC . . . . . . . . . . . . . . . . . . . .
7/22/2006
Diamondback Energy Services LLC . . . . . . . . . . . . . . . . . . .
9/26/2006
11/1/2007
Stampede Investments LLC . . . . . . . . . . . . . . . . . . . . . . . . .
11/15/2007 Grizzly Oil Sands ULC . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,249,000
—
754,000
17,000
123,000
953,000
$ 431,000
49,000
2,222,000
823,000
—
198,000
$147,000
346,000
—
294,000
—
—
* Agreement was terminated effective April 1, 2006.
F-13
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
5.
PROPERTY AND EQUIPMENT
The major categories of property and equipment and related accumulated depletion, depreciation and
amortization as of December 31, 2007 and 2006 are as follows:
December 31,
2007
2006
Oil and gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Office furniture and fixtures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Building . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 484,487,000
2,922,000
3,926,000
260,000
$250,838,000
2,465,000
3,926,000
260,000
Total property and equipment
Accumulated depreciation, depletion,amortization and impairment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
491,595,000
257,489,000
reserve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(129,496,000)
(99,815,000)
Property and equipment, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 362,099,000
$157,674,000
Included in oil and gas properties at December 31, 2007 and December 31, 2006 is the cumulative
capitalization of $5,969,000 and $3,928,000, respectively, in general and administrative costs incurred and
capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent
management’s estimate of costs incurred directly related to exploration and development activities such as
geological and other administrative costs associated with overseeing the exploration and development activities.
All general and administrative costs not directly associated with exploration and development activities were
charged to expense as they were incurred. Capitalized general and administrative costs were approximately
$2,041,000, $976,000 and $346,000 for the years ended December 31, 2007, 2006 and 2005, respectively.
At December 31, 2007, approximately $1,106,000 of oil and gas properties related to the Company’s Belize
properties are excluded from amortization as they relate to non-producing properties. In addition, approximately
$34,540,000 of non-producing leasehold costs resulting from the Company’s acquisition of West Texas Permian
properties are excluded from amortization at December 31, 2007. Approximately $1,632,000 of non-producing
leasehold costs related to the Company’s Southern Louisiana assets was also excluded from amortization at
December 31, 2007. At December 31, 2006, approximately $1,459,000 of non-producing leasehold costs related
to the Company’s Louisiana assets was excluded from amortization.
A reconciliation of the asset retirement obligation for the years ended December 31, 2007 and 2006 is as
follows:
Asset retirement obligation, beginning of period . . . . . . . . . . . . . . . . . . .
Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities settled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in cash flow estimate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligation as of end of period . . . . . . . . . . . . . . . . . . . . .
Less current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31,
2007
2006
$ 8,858,000
500,000
(1,278,000)
—
554,000
8,634,000
480,000
$8,609,000
405,000
(639,000)
(113,000)
596,000
8,858,000
480,000
Asset retirement obligation, long-term . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 8,154,000
$8,378,000
F-14
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
6. EQUITY INVESTMENTS
Investments accounted for by the equity method consist of the following as of December 31, 2007 and 2006:
Investment in Tatex Thailand II, LLC . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment in Windsor Bakken, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment in Grizzly Oil Sands ULC . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 3,553,000
2,468,000
27,801,000
$ 3,465,000
2,433,000
8,465,000
$33,822,000
$14,363,000
December 31,
2007
2006
Tatex Thailand II, LLC
During 2005, the Company purchased a 23.5% ownership interest in Tatex Thailand II, LLC (“Tatex”) at a
cost of $2,400,000. The remaining interests in Tatex are owned by entities controlled by Wexford Capital LLC,
an affiliate of Gulfport. Tatex, a non-public entity, holds 85,122 of the 1,000,000 outstanding shares of APICO,
LLC (“APICO”), an international oil and gas exploration company. APICO has a reserve base located in
Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm
Field. During 2007, Gulfport paid $88,000 in cash calls, bringing its total investment in Tatex (including
previous investments) to $3,553,000. The loss on equity investment related to Tatex was immaterial for the years
ended December 31, 2007 and 2006.
Windsor Bakken, LLC
During 2005, the Company purchased a 20% ownership interest in Windsor Bakken, LLC (“Bakken”). The
remaining interests in Bakken are owned by entities controlled by Wexford Capital LLC, an affiliate of Gulfport.
In 2005 and 2006, Bakken acquired leases on undeveloped acreage in the Williston Basin areas of western North
Dakota and eastern Montana. As of December 31, 2007 and December 31, 2006, Gulfport’s net investment in
Bakken was $2,468,000 and $2,433,000, respectively. As of December 31, 2007, Bakken had commenced
drilling of some of its undeveloped acreage. The Company recognized losses on equity investment of $92,000
and $48,000 for the years ended December 31, 2007 and 2006, respectively, which are included in other income
(expense) in the consolidated statements of operations. The loss on equity investment related to Bakken was
immaterial for the year ended December 31, 2005.
Grizzly Oil Sands ULC
During the third quarter of 2006, the Company, through its wholly owned subsidiary Grizzly Holdings Inc.,
purchased a 24.9999% interest in Grizzly Oils Sands ULC (“Grizzly”), a Canadian unlimited liability company,
for approximately $8.2 million. The remaining interests in Grizzly are owned by entities controlled by Wexford
Capital LLC, an affiliate of Gulfport. During 2006 and 2007, Grizzly acquired leases in the Athabasca region
located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has
commenced drilling of core holes for feasibility of oil production in five separate lease blocks but has not
commenced development of operations. As of December 31, 2007 and 2006, Gulfport’s net investment in
Grizzly was $27,801,000 and $8,465,000, respectively. Grizzly’s functional currency is the Canadian dollar. The
Company’s investment in Grizzly was increased by $2,254,000 as a result of a currency translation gain for the
year ended December 31, 2007. The Company recognized a loss on equity investment of $385,000 and $28,000
for the years ended December 31, 2007 and 2006, respectively, which is included in other income (expense) in
the consolidated statements of operations.
F-15
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
7. OTHER ASSETS
Other assets consist of the following as of December 31, 2007 and 2006:
Plugging and abandonment escrow account on the WCBB properties
(Note 18) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Certificates of deposit securing letter of credit . . . . . . . . . . . . . . . . . . . . . .
Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$3,104,000
200,000
3,084,000
$2,983,000
200,000
4,000
$6,388,000
$3,187,000
December 31,
2007
2006
8. LONG-TERM DEBT
A break-down of long-term debt as of December 31, 2007 and 2006 is as follows:
December 31,
2007
2006
Reducing credit agreement (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Term loan (1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Building loans (2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . .
Less: current maturities of long term debt
$59,521,000
4,294,000
2,718,000
(808,000)
$29,848,000
5,000,000
2,843,000
(835,000)
Debt reflected as long term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$65,725,000
$36,856,000
Maturities of long-term debt as of December 31, 2007 are as follows:
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter
$
808,000
815,000
60,342,000
3,131,000
714,000
723,000
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$66,533,000
(1) On March 11, 2005, Gulfport entered into a three-year secured reducing credit agreement providing for a
$30.0 million revolving credit facility with Bank of America, N.A. Borrowings under the revolving credit facility
are subject to a borrowing base limitation, which was initially set at $18.0 million, subject to adjustment. On
November 1, 2005, the amount available under the borrowing base limitation was increased to $23.0 million and
was redetermined without change on May 30, 2006. On December 19, 2006, the amount available under the
borrowing base limitation was increased to $30.0 million. Effective July 19, 2007, the credit facility was
increased to $150.0 million and the amount available under the borrowing base limitation was increased to $60.0
million. On December 20, 2007, the amount available under the borrowing base limitation was increased to $90.0
million and the Eurodollar interest rate, which the Company can elect to use at its option, was reduced by 0.75%.
In addition, the maturity date was extended from March 31, 2009 to March 31, 2010. The Company makes
quarterly interest payments on amounts borrowed under the facility. Amounts borrowed under the credit facility
F-16
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
bear interest at Bank of America Prime plus 0.25% (7.5% at December 31, 2007). The Company’s obligations
under the credit facility are collateralized by a lien on substantially all of the Company’s Louisiana and West
Texas assets. The credit facility contains certain affirmative and negative covenants, including, but not limited to
the following financial covenants: (a) the ratio of funded debt to EBITDAX (net income before deductions for
taxes, excluding unrealized gains and losses related to trading securities and commodity hedges, plus
depreciation, depletion, amortization and interest expense, plus exploration costs deducted in determining net
income under full cost accounting) for a twelve-month period may not be greater than 2.00 to 1.00; and (b) the
ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. The
Company was in compliance with all covenants at December 31, 2007. As of December 31, 2007, approximately
$59.5 million was outstanding under this facility, which is included in long-term debt, net of current maturities
on the accompanying consolidated balance sheet.
On July 10, 2006, Gulfport entered into a $5 million term loan agreement with Bank of America, N.A.
related to the purchase of new gas compressor units. The loan amortizes quarterly beginning March 31, 2007 on a
straight-line basis over seven years based on the outstanding principal balance at December 31, 2006. Amounts
borrowed bear interest at Bank of America Prime (7.25% at December 31, 2007). The Company makes quarterly
interest payments on amounts borrowed under the agreement. The Company’s obligations under the agreement
are collateralized by a lien on the compressor units. As of December 31, 2007, approximately $4.3 million was
outstanding under this agreement, of which $714,000 and $3,580,000 are included in current maturities of long-
term debt and long-term debt, net of current maturities, respectively, on the accompanying consolidated balance
sheet.
(2) In June 2004, the Company purchased the office building it occupies in Oklahoma City, Oklahoma, for
$3,700,000. One loan associated with this building matured in March 2006 and bore interest at the rate of 6% per
annum, while the other loan matures in June 2011 and bears interest at the rate of 6.5% per annum. In addition,
the building loans included a loan related to a building in Lafayette, Louisiana, purchased in 1996 to be used as
the Company’s Louisiana headquarters. This loan bore interest at the rate of 5.75% per annum. The Company
paid this loan in full during the third quarter of 2007, in advance of its February 2008 maturity date. All building
loans require monthly interest and principal payments and are collateralized by the respective land and buildings.
9. COMMON STOCK OPTIONS, RESTRICTED STOCK, WARRANTS AND CHANGES IN
CAPITALIZATION
Options
The Company sponsors the 1999 Stock Option Plan (the “Plan”), which is administered by the
Compensation Committee (the “Committee”) of the Board of Directors of the Company. Under the terms of the
Plan, the Committee could determine: to which eligible participants options shall be granted, the number of
shares covered by such options, the purchase price or exercise price of such options, the vesting period of such
options and the exercisable period of such options. Eligible participants are defined as (i) all directors of the
Company; (ii) all officers of the Company; and (iii) all key employees of the Company with a customary work
week of at least 40 hours in the employ of the Company. The maximum number of shares for which options
could be granted under the Plan, as adjusted for changes in capitalization which have taken place since the Plan’s
adoption, was 883,000. The Company has granted 627,337 options for the purchase of shares of the Company’s
common stock under the Plan as of December 31, 2007. No additional securities will be issued under the Plan
other than upon exercise of options that are outstanding.
F-17
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
The Company replaced the Plan in January 2005 with the 2005 Stock Incentive Plan (“2005 Plan”), which is
administered by the Committee. Under the terms of the 2005 Plan, the Committee may determine: when options
shall be granted, to which eligible participants options shall be granted, the number of shares covered by such
options, the purchase price or exercise price of such options, the vesting periods of such options and the
exercisable period of such options. Eligible participants are defined as employees, consultants, and directors of
the Company.
On April 20, 2006, the Company amended and restated the 2005 Plan to include (a) Incentive Stock
Options, (b) Nonstatutory Stock Options, (c) Restricted Awards (Restricted Stock and Restricted Stock Units),
(d) Performance Awards and (e) Stock Appreciation Rights; and to increase the maximum aggregate amount of
common stock that may be issued under the 2005 Plan from 1,904,606 shares to 3,000,000 shares, including the
627,337 shares underlying options granted to employees under the Plan prior to adoption of the 2005 Plan. As of
December 31, 2007, the Company has granted 997,269 options for the purchase of shares of the Company’s
common stock under the 2005 Plan.
During the first quarter of 2005, the Company granted a total of 677,269 options for the purchase of shares of
the Company’s common stock. The exercise price per share of these options is $3.36. During the third quarter of
2005, the Company granted a total of 120,000 options for the purchase of shares of the Company’s common stock.
The exercise price per share of these options is $9.07. In the fourth quarter 2005, the Company granted a total of
200,000 options for the purchase of shares of the Company’s common stock. The exercise price per share of these
options is $11.20. All options were issued at the market value of the Company’s stock on the date of issuance.
During the second and third quarters of 2005, several non-executive employees of the Company exercised stock
options by signing full recourse notes receivable for the exercise price of those options. The notes bore interest at an
annual rate of 6%. All principal amounts along with related accrued interest were paid as of December 31, 2005.
During the first quarter of 2006, the Company granted a total of 40,000 options for the purchase of shares of
the Company’s common stock. The exercise price per share of these options is $12.17. The options vest in equal
monthly installments over a three-year period and expire ten years after the date of grant. During August 2006,
these options were cancelled and 6,666 restricted shares of the Company’s common stock were issued to the
option holder. These shares were fully vested on the date of grant.
Restricted Stock
On May 16, 2006, the Company issued 57,000 shares of restricted common stock of the Company. These
shares vest in equal monthly installments over a three year period. During August and September 2006, 29,666
shares of restricted common stock were issued. These shares vest in equal monthly installments over a three year
period. On August 17, 2006, the Company issued an additional 6,666 shares of fully vested restricted common
stock in connection with the cancellation of 40,000 options to purchase the Company’s common stock.
On April 1, 2007, the Company granted 16,389 shares of restricted common stock of the Company. These
shares vest monthly over a three year period. On May 15, 2007, the Company granted 10,000 shares of restricted
common stock of the Company. These shares vest in equal monthly installments over a three year period. On
August 14, 2007, the Company granted 8,000 shares of restricted common stock of the Company. These shares
vest in equal monthly installments over a three year period. On November 9, 2007, the Company granted 3,000
shares of restricted common stock of the Company. These shares vest in equal monthly installments over a three
year period. All shares of restricted common stock of the Company were granted under the 2005 Plan, as
amended.
F-18
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
Exercise of Warrants
During the first quarter of 2006, the holders of warrants issued in 2002 in conjunction with a private
placement offering exercised their warrants resulting in 12,171 net shares of the Company’s common stock
issued. No proceeds were received by the Company related to the exercise of these warrants. During the third
quarter of 2006, the holders of warrants exercised their warrants resulting in 101,681 net shares of the
Company’s common stock issued. The Company had 60,550 warrants outstanding at December 31, 2007 which
can be converted into 203,529 shares of common stock at current exercise price of $1.19 per share. The warrants
expire in 2012.
Sale of Common Stock
On February 17, 2005, the Company entered into a stock purchase agreement with certain accredited
investors providing for the issuance by the Company of an aggregate of 2,000,000 shares of the Company’s
common stock at a price of $3.50 per share for gross proceeds to the Company of $7,000,000. On February 22,
2005 the Company entered into another stock purchase agreement with certain other accredited investors
providing for the issuance by the Company of an aggregate of 2,000,000 shares of the Company’s common stock
at a price of $3.50 per share for gross proceeds to the Company of $7,000,000. The transactions closed effective
as of February 18, 2005 and February 23, 2005, respectively. The Company granted certain piggyback
registration rights to the investors. The Company also filed a registration statement on Form S-3 with respect to
the resale of the shares of common stock purchased by the investors in the private placements, which was
declared effective by the Securities and Exchange Commission on December 31, 2005. No underwriting
discounts or commissions were paid in conjunction with the issuances.
In May 2006, the Company closed a public offering of 6,050,000 shares of common stock at a price of
$14.00 per share. All shares were sold by the Company’s selling shareholders and the Company did not receive
any proceeds. In connection with the offering, the Company granted the underwriters a 30-day option to purchase
additional shares of the Company’s common stock to cover over-allotments, if any. On May 8, 2006, the
underwriters exercised their option with respect to 790,000 shares. The Company received net proceeds of
$10,452,000 from the sale of these shares on May 10, 2006 after deducting the underwriting discount and before
offering expenses.
On January 30, 2007, the Company sold 1,150,000 shares of common stock in an underwritten offering at an
offering price to the public of $11.92 per share. In connection with the offering, the Company granted the
underwriter an option to purchase up to an additional 172,500 shares of common stock to cover any over-
allotments, which the underwriter exercised in full on February 1, 2007. The Company received the net proceeds
of approximately $15.3 million from the sale of these shares on February 5, 2007 after deducting the
underwriting discount and before offering expenses.
In May 2007, the Company sold 1,500,000 shares of common stock in an underwritten offering at an
offering price to the public of $16.00 per share. In connection with the offering, the Company granted the
underwriter an option to purchase up to an additional 225,000 shares of common stock to cover any over-
allotments, which the underwriter exercised in full. The Company received the net proceeds of approximately
$26.8 million from the sale of these shares on May 22, 2007 after deducting the underwriting discount and before
offering expenses.
F-19
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
In July 2007, the Company sold 1,000,000 shares of common stock in an underwritten offering at an
offering price to the public of $22.00 per share. The Company received the net proceeds of approximately $21.2
million from the sale of these shares on July 25, 2007 after deducting the underwriting discount and before
offering expenses.
In December 2007, the Company sold 4,500,000 shares of common stock in an underwritten offering at an
offering price to the public of $17.50 per share. The Company received the net proceeds of approximately $75.6
million from the sale of these shares on December 12, 2007 after deducting underwriting discounts and before
offering expenses. In connection with the offering, a selling stockholder granted the underwriter an option to
purchase an additional 675,000 shares of common stock to cover any over-allotments, which the underwriter
exercised in full. The Company did not receive any proceeds from the sale of shares of the common stock by the
selling stockholder.
Private Placement Offering
In March 2002, the Company completed a private placement offering of 10,000 units. Each unit consisted of
(i) one share of Cumulative Preferred Stock, Series A, of the Company (Preferred) and (ii) a warrant to purchase
up to 250 shares of common stock, par value $0.01 per share, of the Company. Holders of the Preferred were
entitled to receive dividends at the rate of 12% of the liquidation preference per annum payable quarterly in cash
or, at the option of the Company for all quarters ending on or prior to March 31, 2004, payable in whole or in
part in additional shares of Preferred at the rate of 15% of the liquidation preference per annum. All preferred
shares were redeemed in 2005.
The 2,322,962 Warrants issued have a term of ten years and an exercise price of $1.19 per share of common
stock subject to adjustment. The Company granted to holders of the Warrants certain demand and piggyback
registration rights with respect to shares of common stock issuable upon exercise of the warrants. The Company
considered the valuation of these warrants and did not consider them materially significant. At December 31,
2007 and 2006, 60,550 warrants were outstanding.
Exercise of Warrants and Redemption of Preferred Stock
During 2005, the holders of warrants to purchase 7,958,470 shares of the Company’s common stock
exercised their warrants for an exercise price of $1.19 per share resulting in proceeds to the Company of $9.5
million. No underwriting discounts or commissions were paid in conjunction with the issuances. The total
warrants exercised in 2005 included 108,625 warrants issued to CD Holdings, LLC, in accordance with the
origination of the note payable to Gulfport Funding in 2002 (and retired during 2002).
Also during 2005, the Company redeemed all of the 14,292 shares of the Company’s outstanding Series A
preferred stock for an aggregate of $14.3 million, including accrued but unpaid dividends.
10. STOCK-BASED COMPENSATION
During the year ended December 31, 2007 and December 31, 2006, the Company’s stock-based
compensation expense was $1,158,000 and $1,063,000, respectively, of which the Company capitalized
F-20
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
$313,000 and $276,000 respectively, relating to its exploration and development efforts, which reduce basic and
diluted earnings per share by $0.02 and $0.02 for the year ended December 31, 2007 and December 31, 2006,
respectively.
The fair value of each option award is estimated on the date of grant using the Black-Scholes option
valuation model that uses the assumptions noted in the following table. Expected volatilities are based on the
historical volatility of the market price of Gulfport’s common stock over a period of time ending on the grant
date. Based upon historical experience of the Company, the expected term of options granted is equal to the
vesting period plus one year. The risk-free rate for periods within the contractual life of the option is based on the
U.S. Treasury yield curve in effect at the time of the grant. The 2005 Plan provides that all options must have an
exercise price not less than the fair value of the Company’s common stock on the date of the grant.
No stock options were issued during the twelve months ended December 31, 2007. The following table
provides information relating to stock options granted for the years ended December 31, 2006 and 2005:
December 31,
2006
December 31,
2005
Expected volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected life in years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average risk free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . .
40.9%
4.0
4.0%
40.70%
4.0
4.0%
The Company has not declared dividends and does not intend to do so in the foreseeable future, and thus did
not use a dividend yield. In each case, the actual value that will be realized, if any, depends on the future
performance of the common stock and overall stock market conditions. There is no assurance that the value an
optionee actually realizes will be at or near the value estimated using the Black-Scholes model.
A summary of the status of stock options and related activity for the years ended December 31, 2007, 2006
and 2005 are presented below:
Options outstanding at December 31, 2004 . . . . . . . .
627,337
$ 2.00
4.85
$
816,000
Weighted
Average
Exercise Price
per Share
Weighted
Average
Remaining
Contractual Term
Aggregate
Intrinsic
Value
Shares
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited/expired . . . . . . . . . . . . . . . . . . . . . . . . .
Options outstanding at December 31, 2005 . . . . . . . .
997,269
(63,167)
(2,666)
1,558,773
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cancelled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited/expired . . . . . . . . . . . . . . . . . . . . . . . . .
40,000
(40,000)
(565,723)
(25,817)
Options outstanding at December 31, 2006 . . . . . . . .
967,233
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited/expired . . . . . . . . . . . . . . . . . . . . . . . . .
Options outstanding at December 31, 2007 . . . . . . . .
—
(210,398)
(82,445)
674,390
Options exercisable at December 31, 2007 . . . . . . . .
269,917
5.62
2.01
3.36
4.31
12.17
12.17
2.26
3.26
5.54
—
4.13
3.66
$ 6.22
$ 8.19
F-21
7.33
12,061,000
5,770,000
7.76
7,782,000
2,284,000
6.97
6.59
$ 8,098,000
$ 2,717,000
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
The 40,000 options granted in 2006 and subsequently cancelled had a fair value of $4.40 per share, or
$176,000.
Unrecognized compensation expense as of December 31, 2007 related to outstanding stock options and
restricted shares was $1,593,000. The expense is expected to be recognized over a weighted average period of
1.38 years.
The following table summarizes information about the stock options outstanding at December 31, 2007:
Exercise
Price
$ 2.00
$ 3.36
$ 9.07
$11.20
Number
Outstanding
53,250
345,695
75,445
200,000
674,390
Weighted Average
Remaining Life
(in years)
1.85
7.06
7.69
7.92
Number
Exercisable
53,250
27,333
50,445
138,889
269,917
The following table summarizes restricted stock activity for the twelve months ended December 31, 2007
and 2006:
Number of
Unvested
Restricted Shares
Weighted
Average
Grant Date
Fair Value
Unvested shares as of December 31, 2005 . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unvested shares as of December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unvested shares as of December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . .
—
93,332
(21,981)
(1,833)
69,518
37,389
(35,930)
(11,944)
59,033
$ —
12.78
12.64
13.27
$12.81
$15.66
13.13
15.24
$13.94
11. DIVIDENDS ON SERIES A PREFERRED STOCK
The Company may, at its option, accrue additional shares of Preferred Stock for the payment of dividends at
a rate of 15% per annum rather than accrue cash dividends at a rate of 12% per annum during the initial two
years following the closing date of its offering which expired on March 31, 2004. Effective April 1, 2004, as a
result of the amendment discussed below, the Company continued to issue additional shares of Preferred Stock
for payment of dividends. As a result, the Company issued additional shares with liquidation preference totaling
$272,000 for the year ended December 31, 2005 related to the Preferred Stock Series A shares issued and
outstanding during that time period. These dividends were calculated based upon the Preferred’s $1,000 per share
redemptive value. As a result of the adoption of SFAS 150, the dividends issued as additional shares for the year
ended December 31, 2005 are shown as “Interest expense—preferred stock” in the accompanying consolidated
statements of operations.
F-22
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents,
accounts receivable, accounts payable and accrued liabilities, and current and long-term debt are carried at cost,
which approximates market value.
The fair value of the derivative instruments are computed based on the difference between the prices
provided by the fixed-price contracts and forward market prices as of the specified date, as adjusted for basis
differentials. Forward market prices for oil are dependent upon supply and demand factors in such forward
market and are subject to significant volatility.
13. INCOME TAXES
A reconciliation of the statutory federal income tax amount to the recorded expense follows:
2007
2006
2005
Income before federal income taxes . . . . . . . . . . . . . .
$ 37,775,000
$ 27,808,000
$10,895,000
Expected income tax at statutory rate . . . . . . . . . . . . .
Interest expense not tax deductible . . . . . . . . . . . . . . .
State income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other differences . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in valuation allowance . . . . . . . . . . . . . . . . .
13,221,000
—
2,131,000
528,000
(15,759,000)
9,455,000
—
1,668,000
1,034,000
(12,157,000)
3,704,000
272,000
654,000
(849,000)
(3,781,000)
Income tax expense recorded . . . . . . . . . . . . . . . . . . .
$
121,000
$
—
$
—
The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred
tax assets and liabilities at December 31, 2007, 2006 and 2005 are estimated as follows:
2007
2006
2005
Deferred tax assets:
Net operating loss carryforward . . . . . . . . . . . . . . . . .
SFAS 123(R) compensation expense . . . . . . . . . . . . .
Investment in pass through entities . . . . . . . . . . . . . .
AMT credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized loss on hedging activities . . . . . . . . . . . . .
Non-oil and gas property basis difference . . . . . . . . .
$37,197,000
216,000
72,000
64,000
—
148,000
$ 38,373,000
319,000
—
—
—
99,000
$ 40,143,000
—
—
—
211,000
144,000
Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . .
37,697,000
38,791,000
40,498,000
Deferred tax liabilities:
Oil and gas property basis difference . . . . . . . . . . . . .
Unrealized gain on hedging activities . . . . . . . . . . . .
27,947,000
—
13,273,000
9,000
2,821,000
—
Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . .
27,947,000
13,282,000
2,821,000
Total deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . .
Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . .
9,750,000
(9,750,000)
25,509,000
(25,509,000)
37,677,000
(37,677,000)
Net deferred tax asset (liability) . . . . . . . . . . . . . . . . .
$
—
$
—
$
—
F-23
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
The Company has an available tax net operating loss carry forward estimated at approximately $92,991,000
as of December 31, 2007. This carryforward will begin to expire in the year 2012. A valuation allowance has
been provided at December 31, 2007, 2006, and 2005 because it is management’s belief, based upon the
Company’s past history of no taxable income, it is more likely than not the net deferred tax assets will not be
realized.
The Company had income tax expense of $121,000 during the year ended December 31, 2007 related to the
payment of alternative minimum taxes due for 2006 and 2007. Although the Company has substantial net
operating loss carryforwards, these cannot be used to offset alternative minimum tax liabilities.
14. EARNINGS PER SHARE
A reconciliation of the components of basic and diluted net income per common share is presented in the
table below:
Basic:
2007
2006
2005
Income
Shares
Per
Share
Income
Shares
Per
Share
Income
Shares
Per
Share
Net income . . . . . . $37,775,000 36,774,163 $1.03 $27,808,000 32,789,280 $0.85 $10,895,000 30,329,682 $0.36
Effect of dilutive
securities:
Stock options
and awards . . . .
—
676,935
— 1,146,794
— 2,171,782
Diluted:
Net income . . . . . . $37,775,000 37,451,098 $1.01 $27,808,000 33,936,074 $0.82 $10,895,000 32,501,464 $0.34
Options to purchase 200,000 shares at $11.20 per share were excluded from the calculation of dilutive
earnings per share for the year ended December 31, 2006 because they were anti-dilutive. Options to purchase
120,000 shares at $9.07 per share and 200,000 shares at $11.20 per share were excluded from the calculation of
dilutive earnings per share for the year ended December 31, 2005 because they were anti-dilutive. There were no
potential shares of common stock that were considered anti-dilutive for the year ended December 31, 2007.
15. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
Oil Price Hedging Activities
The Company established an oil price-hedging program in August 2005. The Company may seek to reduce
its exposure to unfavorable changes in oil prices, which are subject to significant and often volatile fluctuation,
by taking receive-fixed positions in price swap contracts. The Company pays the counterparty the excess of the
oil market price over the fixed price and will receive the excess of the fixed price over the market price as
defined in each contract. These contracts allow the Company to predict with greater certainty the effective oil
prices to be received for hedged production and benefit operating cash flows and earnings when market prices are
less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices
that are higher than the fixed prices in the contracts for hedged production. For the years ended December 31,
2006 and 2005, price swap contracts hedged 62% and 8.7% of the Company’s oil production, respectively. As of
December 31, 2005, price swap contracts were in place to hedge 540,000 barrels (“Bbls”) of estimated future
production during 2006. There were no price swap contracts in place as of December 31, 2006 and 2007.
F-24
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
The Company’s price swap contracts were tied to commodity prices on the New York Mercantile Exchange
(“NYMEX”). The Company received the fixed price amount stated in the contract and paid to its counterparty
the current market price for oil as listed on the NYMEX West Texas Index (WTI). However, due to the
geographic location of the Company’s assets and the cost of transporting oil to another market, the amount that
the Company receives when it actually sells its oil differs from the index price. The difference between oil prices
on the NYMEX WTI and average price received by the Company during the month for its oil is referred to as a
basis differential.
The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value
attributable to the price swap contracts as of December 31, 2005.
Contract volumes (Bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average fixed price per Bbls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fixed-price sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value, of hedging (assets)
Year Ending
December 31,
2005
540,000
$
64.05
$34,587,000
621,000
$
The estimates of fair value of the price swap contracts are computed based on the difference between the
prices provided by the price swap contracts and forward market prices as of the specified date, as adjusted for
basis differentials. Forward market prices for oil are dependent upon supply and demand factors in such forward
market and are subject to significant volatility. The fair value estimates shown above are subject to change as
forward market prices and basis change.
All price swap contracts have been executed in connection with the Company’s oil price hedging program.
The differential between the fixed price and the floating price for each contract settlement period multiplied by
the associated contract volume is the contract profit or loss. For price swap contracts qualifying as cash flow
hedges pursuant to SFAS 133, the realized contract profit or loss is included in oil sales in the period for which
the underlying production was hedged. For the years ended December 31, 2006 and 2005, there were net realized
losses of $1,008,000 and $26,000 under price swap contracts, respectively, which are included in oil sales on the
consolidated statements of operations. The losses for the year ended December 31, 2006 included $191,000 of
gains that had previously been deferred within other comprehensive income and are further discussed in the
subsequent paragraph.
The Company’s oil production was shut-in during the fourth quarter of 2005 and for a portion of the first
quarter of 2006 due to Hurricane Rita’s impact on the Company’s facilities. In accordance with SFAS 133
Derivative Implementation Group Issue Number G3, certain extenuating circumstances that impact the timing of
the forecasted transaction and are outside the control or influence of the Company permit the gain or loss related
to the cash flow hedge being reported in accumulated other comprehensive income until the forecasted
transaction is recognized in earnings. As a result, all fourth quarter 2005 and first quarter 2006 contract profits
and losses (net gain of $114,000 and $77,000, respectively) remained in accumulated other comprehensive
income at March 31, 2006. During the second quarter of 2006, production was restored and the Company
recognized gains of $47,000 in the second quarter of 2006. The remaining deferred gain of $144,000 was
recognized during the third quarter of 2006.
For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133,
changes in fair value are recognized in accumulated other comprehensive income until the hedged item is
recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair
F-25
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
value between the derivative contract and the hedged item over time. Any change in fair value resulting from
ineffectiveness is recognized immediately in earnings. During the year ended December 31, 2006, a gain of
$24,000 was recognized into earnings resulting from hedge ineffectiveness.
In October 2006, the company terminated the remaining three months of its hedging contracts. Through the
termination of these remaining contracts the Company received a total of $566,000 of proceeds during the fourth
quarter of 2006 resulting from the differential in the fixed hedged price of $64.05 per barrel and the market prices
of the associated futures contracts at the date of the termination of these contracts. In accordance with SFAS 133,
these amounts were recognized into earnings during the fourth quarter of 2006, the period in which the hedged
forecasted transactions occurred. The Company has no derivative contracts at December 31, 2007 and 2006.
16. OPERATING LEASES
In October 2006, the Company began leasing the Louisiana building that it owns to an unrelated party. The
cost of the building totaled approximately $217,000 and accumulated depreciation amounted to approximately
$75,000 as of December 31, 2007. The lease commenced on October 15, 2006 and expires October 14, 2009,
with equal monthly installments of $10,500. The future minimum lease payments to be received are as follows:
Fiscal year ending December 31
2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
126,000
94,500
$220,500
17. RELATED PARTY TRANSACTIONS
In the ordinary course of business, the Company conducts business activities with certain entities affiliated
with its largest stockholder.
Certain personnel of the Company perform management and administrative services for affiliate companies.
The Company is reimbursed for salaries and benefits of these individuals based on the estimated time spent on
those affiliates compared to time spent on the Company. For the years ended December 31, 2007, 2006 and 2005,
expenses reimbursed to the Company under this arrangement and reflected as a reduction to general and
administrative expense were $11,153,000, $12,738,000 and $6,232,000, respectively.
Windsor Energy Group (“WEG”), an affiliate of Gulfport, operated the Marquiss wells in Wyoming. At
December 31, 2007 and December 31, 2006, the Company owed WEG approximately $440,000 and $225,000,
respectively, related to reimbursement for services provided. Approximately $125,000 and $1,217,000 of
services provided by WEG are included in lease operating expenses in the consolidated statements of operations
for the years ended December 31, 2007 and 2006, respectively.
Athena Construction LLC (“Athena”), an affiliate of Gulfport, performs services for the Company at its
WCBB and Hackberry fields. At December 31, 2007 and December 31, 2006, the Company owed Athena
approximately $1,561,000 and $1,045,000, respectively, related to these services. Approximately $989,000 and
$197,000 of services provided by Athena are included in lease operating expenses in the consolidated statements
of operations for the years ended December 31, 2007 and 2006, respectively. Approximately $4,784,000 and
$980,000 related to services performed by Athena are included in oil and natural gas properties at December 31,
2007 and 2006, respectively.
F-26
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
Packers & Service Tools, Inc. (“Packers”), an affiliate of Gulfport, performs services for the Company at its
WCBB and Hackberry fields. At December 31, 2007 and December 31, 2006, the Company owed Packers
approximately $425,000 and $354,000, respectively, related to these services. Approximately $41,000 of services
provided by Packers are included in lease operating expenses in the consolidated statements of operations for the
year ended December 31, 2007. Approximately $1,439,000 and $954,000 related to services performed by
Packers are included in oil and natural gas properties at December 31, 2007 and 2006, respectively.
Diamondback Completions LLC (“Completions”), an affiliate of Gulfport, performs services for the
Company at its WCBB and Hackberry fields. At December 31, 2007, the Company owed Completions
approximately $241,000 related to these services. There were no amounts outstanding at December 31, 2006.
Approximately $519,000 relating to services performed by Completions in 2007 are included in oil and natural
gas properties on the accompanying consolidated balance sheets at December 2007.
Great White Towing LLC (“Towing”), an affiliate of Gulfport, performs services for the Company at its
WCBB field. At December 31, 2007, the Company owed Towing approximately $50,000 related to these
services. There were no amounts outstanding at December 31, 2006. Approximately $13,000 of services
performed by Towing is included in lease operating expenses in the consolidated statements of operations for the
year ended December 31, 2007. Approximately $133,000 relating to services performed during 2007 are included
in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2007.
At December 31, 2007, the Company’s wholly owned subsidiary, Grizzly Holdings Inc., owed Grizzly Oil
Sands ULC approximately $151,000 for shares issued in 2007.
18. COMMITMENTS
Plugging and Abandonment Funds
In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, the
Company assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through
March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for
20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties
until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the Company can access the
trust for use in plugging and abandonment charges associated with the property. As of December 31, 2007, the
plugging and abandonment trust totaled approximately $3,104,000 including interest received during 2007 of
approximately $126,000. At December 31, 2007, the Company has plugged 243 wells at WCBB since it began its
plugging program in 1997. An additional ten wells were plugged in January 2008, which management believes
fulfills its minimum plugging obligation through March 31, 2008.
Texaco Global Settlement
Pursuant to the terms of a global settlement between Texaco and the State of Louisiana which includes the
State Lease No. 50 portion of Gulfport’s East Hackberry Field, Gulfport was obligated to commence drilling a
well or other qualifying development operation on certain non-producing acreage in the field prior to March
1998. Because of prevailing market conditions during 1998, the Company believed it was commercially
impractical to shoot seismic or commence drilling operations on the subject property. As a result, Gulfport has
agreed to surrender approximately 440 non-producing acres in this field to the State of Louisiana. At
December 31, 2007, Gulfport was in the process of releasing these properties to the State of Louisiana.
F-27
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
Contributions to 401(k) Plan
Gulfport sponsors a 401(k) and Profit Sharing plan under which eligible employees may contribute up to
15% of their total compensation through salary deferrals. Also under these plans, the Company will make a
contribution each calendar year on behalf of each employee equal to at least 3% of his or her salary, regardless of
the employee’s participation in salary deferrals. During the years ended December 31, 2007, 2006, and 2005
Gulfport incurred $640,000, $308,000 and $144,000, respectively, in contributions expense related to this plan.
Employment Agreement
In May 1999, Gulfport entered into an employment agreement with its Chairman of the Board. The original
term of the agreement expired on May 31, 2004, but automatically renews for successive terms of one year
unless Gulfport or the Chairman elects otherwise. The employment agreement calls for an annual salary of
$200,000, which may be adjusted for cost of living increases.
19. CONTINGENCIES
The Louisiana State Mineral Board (“LSMB”) is disputing Gulfport’s royalty payments to the State of
Louisiana resulting from the sale of oil under fixed price contracts. The LSMB maintains that Gulfport paid
approximately $1,400,000 less in royalties under the fixed price contracts than the royalties Gulfport would have
had to pay had it sold the oil at prevailing market rates. Gulfport has denied any liability to the LSMB for
underpayment of royalties and has maintained that it was entitled to enter into the fixed price contracts with
unrelated third parties and pay royalties based upon the sales proceeds from those contracts. Gulfport met with
the Attorney General on several occasions and recently reached a mutual settlement. The settlement requires
Gulfport to pay $250,000, which has been accrued in accounts payable and accrued liabilities in the
accompanying consolidated balance sheets and all future royalties will be paid at market price, regardless of the
presence of fixed price contracts. The settlement was approved by the LSMB during its February 2008 session.
Gulfport is currently awaiting the settlement and release documentation from the LSMB to finalize the matter.
Other Litigation
In November 2006, Cudd Pressure Control, Inc. (“Cudd”) filed a lawsuit against Gulfport and Great White
Pressure Control LLC, an affiliate of the Company, among others, in the 129th Judicial District Harris County,
Texas. The lawsuit was subsequently removed to the United States District Court for the Southern District of
Texas (Houston Division). The lawsuit alleges RICO violations and several other causes of action relating to an
affiliate company’s employment of several former Cudd employees. The defendants in the suit are Ronnie Roles,
Rocky Roles, Steve Winters, Bert Ballard, Nelson Britton, Michael Fields, Steve Bickle, Great White Pressure
Control LLC and Gulfport. On stipulation by the parties, the Plaintiff’s RICO claim was dismissed without
prejudice by order of the court on February 14, 2007. Co-defendant, Steve Bickle, was dismissed from the case
on July 18, 2007. The case against Gulfport was stayed by order of the court on July 31, 2007. The court further
ordered co-defendant, Great White Pressure Control, to move for summary judgment by August 24, 2007. Cudd
was ordered to respond by September 14, 2007. The Company filed a motion for summary judgment on
October 5, 2007. Plaintiff filed a response on November 15, 2007, and Gulfport filed a reply on November 21,
2007. Gulfport is currently awaiting the ruling from the court.
In October 2006, an accident occurred north of the Company’s production facilities in the WCBB field in
southern Louisiana involving two contracted vessels that were performing work on behalf of the Company in the
field. A tugboat, the M/V Miss Megan, and two barges laden with construction materials ruptured an underwater
F-28
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
natural gas pipeline and a subsequent fire damaged the vessels. Six fatalities resulted from the accident. The
following lawsuits relating to this incident are currently pending before the courts:
• On October 13, 2006, Athena Construction LLC (“Athena”) filed a limitation action in the United States
District Court for the Eastern District of Louisiana, alleging that all losses and damages as a result of the
pipeline incident were incurred without fault on its part. Furthermore, Athena claims the benefit of the
limitation of liability provided for in 42 U.S.C. § 183 and seeks an injunction restraining filing
commencement and further prosecution in any court of any lawsuit against Athena related to the
pipeline incident. The limitation of liability action was subsequently transferred to the United States
District Court for the Western District of Louisiana, which is where the case remains pending. On
December 20, 2006, 4-K Marine LLC, as owner of the M/V Miss Megan, and Central Boat Rentals,
Inc., as operator of the M/V Miss Megan also filed a limitation action in the Western District. On
January 10, 2007, the Athena and the 4-K/Central Boat limitation proceedings were consolidated by
order of the court. On May 5, 2007, Diamondback Energy Services LLC (“Diamondback”), an affiliate
of Gulfport, filed an intervener with the Court to become a party to the suit. The remaining parties filed
claims on July 9, 2007, which included claims by Nicholas Aucoin, one of the initial responders to the
scene of the accident. A record hearing was held on August 13, 2007, to discuss the status of the
consolidated matters and a subsequent work plan was filed on October 3, 2007. No other deadlines have
been set.
• On October 16, 2006, a lawsuit was filed in the 16th Judicial District Court for the Parish of St. Mary,
Louisiana against Gulfport, Athena, and Central Boat seeking compensatory and punitive damages for
claims related to the death of the plaintiff’s husband, a crewmember on the Athena barge. The suit
alleges that the husband’s death was caused by the defendants’ negligence and the unseaworthiness of
the barge to which he was assigned. Under the Blanket Time Charter between Gulfport and Central
Boat, Central Boat tendered the defense and indemnification of the lawsuit to Gulfport. On November 2,
2006, all proceedings were stayed as a result of the limitation of liability action discussed above.
Settlement was reached during mediations held in December 2007. The Company is currently working
to obtain settlement approvals and releases within the next 30 to 45 days.
• On October 22, 2006, a lawsuit was filed in United States District Court for the Southern District of
Texas, Galveston Division against Gulfport, Central Boat, Diamondback, Chevron Pipeline Company,
Chevron USA, Inc., and ChevronTexaco Pipeline Holdings, Inc. This lawsuit is a result of the death of
three individuals. These individuals were employed by Athena and were on the Athena barge at the time
of the accident. The plaintiffs seek compensatory and punitive damages as a result of the alleged
negligence of defendants. Central Boat has tendered the defense and indemnification of this lawsuit to
Gulfport. On April 30, 2007, an order was filed transferring the case to the Western District of
Louisiana. A successful settlement was reached during mediations held in December 2007. The
Company is currently working to obtain settlement approvals and releases within the next 30 to 45 days.
• On February 2, 2007, a lawsuit was filed in the United States District Court for the Western District of
Louisiana, Lafayette Division against Chevron Pipeline Company, Chevron USA Inc., Chevron Texaco
Pipeline Holdings, Inc., Chevron Natural Gas Services Inc., Diamondback and Gulfport. The suit was filed on
behalf of April Hummel, individually and as the representative of the minor, Aleya Hummel, the surviving
child of Terry Abraham who died in the accident. On March 27, 2007, the Company filed its answer. On
September 2, 2007, the case was stayed by order of the Court. A successful settlement was reached in
mediations held in November 2007. We are currently working to obtain settlement approvals and releases.
• On October 15, 2007, Brian Dumesnil filed suit in the 16th Judicial District Court for the Parish of St.
Mary, Louisiana, against Gulfport, Chevron USA, Chevron Texaco Pipeline Holdings, Chevron Natural
F-29
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
Gas, Diamondback, and the Estate of Timothy Tauzin. Mr. Dumesnil was employed by Athena and was
on the Athena barge at the time of the accident. He is seeking unspecified sums as a result of the alleged
negligence of defendants and injuries incurred following the October 12, 2006 accident. By mutual
agreement of the parties on October 19, 2007, Gulfport is not required to respond until receipt of further
notification from the plaintiff.
On July 27, 2007, Robotti & Company, LLC filed a putative class action lawsuit in the Court of Chancery
for the State of Delaware in and for Kent County, Delaware. The lawsuit alleges a breach of fiduciary duty by
Gulfport and its directors in connection with the pricing of the 2004 rights offering. The Company received
service of this matter on August 10, 2007. By mutual agreement of the parties, Gulfport was not required to
respond until notified by the plaintiff, which was received on January 16, 2008. Plaintiff filed an amended
complaint on January 15, 2008, and Gulfport filed a motion to dismiss in early February 2008.
In July 2007, Michael Tripkovich filed suit in the 16th Judicial District Court of the Parish of St. Martin,
Louisiana, against 113 entities, including Gulfport, alleging his contraction of chronic myeloid leukemia (CML)
was caused by exposure to various substances while maintaining natural gas compressors over a nineteen year
period. Gulfport was served on July 23, 2007 and filed a response accordingly. The suit is currently in the early
phases of discovery. Gulfport has no record that Mr. Tripkovich was ever employed by the Company. No other
deadlines have been set at this time.
Due to the early stages of certain of the above litigation, the outcome is uncertain and management cannot
determine the amount of loss, if any, that may result. Litigation is inherently uncertain. Adverse decisions in one
or more of the above matters could have a material adverse effect on the Company’s financial condition or results
of operations.
The Company has been named as a defendant on various other litigation matters. The ultimate resolution of
these matters is not expected to have a material adverse effect on the Company’s financial condition or results of
operations for the periods presented in the consolidated financial statements.
Concentration of Credit Risk
Gulfport operates in the oil and gas industry principally in the state of Louisiana with sales to refineries,
re-sellers such as pipeline companies, and local distribution companies. While certain of these customers are
affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry,
Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and
will continue to be immaterial to the Company’s results of operations in the long term.
The Company maintains cash balances at several banks. Accounts at each institution are insured by the
Federal Deposit Insurance Corporation up to $100,000. At December 31, 2007, Gulfport held cash in excess of
insured limits in these banks totaling $2,440,000.
During the year ended December 31, 2007, approximately 99% of Gulfport’s oil sales and 69% and 23% of
Gulfport’s natural gas sales were attributable to three purchasers: Shell, Chevron, and Hilcorp, respectively.
During the year ended December 31, 2006, Gulfport sold approximately 100% of its oil production to Shell and
approximately 96% of its natural gas production to Chevron. During the year ended December 31, 2005, Gulfport
sold approximately 99% of its oil production to Shell and 88% of its natural gas production to Chevron.
F-30
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
Forward Sales Contracts
The Company has entered into forward sales contracts for the sale of 3,000 barrels of production per day for
the month of June 2007 at a weighted average daily price of $70.15 per barrel before transportation costs. For the
period of July 2007 through December 2007, the Company has entered into forward sales contracts for the sale of
3,500 barrels of production per day at a weighted average daily price of $70.29 per barrel before transportation
costs. In addition, the Company has entered into forward sales contracts for the sale of 3,500 barrels of
production per day for the months of January 2008 through May 2008 at a weighted average daily price of
$70.29 per barrel before transportation costs. For June 2008, the Company has agreements to sell 3,500 barrels of
production per day at a weighted average daily price of $71.69 per barrel before transportation costs. For the
month of July 2008, the Company has agreements to sell 3,000 barrels of production per day at a weighted
average daily price of $81.37 per barrel before transportation costs. For August 2008, Gulfport has agreements to
sell 3,000 barrels of production per day at a weighted average daily price of $82.44 per barrel before
transportation costs. For the periods of September 2008 through December 2008, the Company has entered into
forward sales contracts for the sale of 3,000 barrels of production per day in each such period at weighted
average daily prices of $82.20 per barrel before transportation costs. For the period of January 2009 through
December 2009, the Company entered into agreements to sell 2,500 barrels of production per day at a weighted
average daily price of $84.62 per barrel before transportation costs. These contracts require physical delivery of
production quantities and are exempted from the provisions of SFAS 133 as normal sales of production.
20. LITIGATION TRUST ENTITY
Pursuant to the Company’s 1997 plan of reorganization, all of Gulfport’s possible causes of action against
third parties (with the exception of certain litigation related to recovery of marine and rig equipment assets and
claims against Tri-Deck), existing as of the effective date of that plan, were transferred into a “Litigation Trust”
controlled by an independent party for the benefit of most of the Company’s existing unsecured creditors. The
litigation related to recovery of marine and rig equipment and the Tri-Deck claims were subsequently transferred
to the Litigation Trust as described below.
The Litigation Trust was funded by a $3,000,000 cash payment from the Company, which was made on the
effective date of reorganization. Gulfport owns a 12% interest in the Litigation Trust with the other 88% being
owned by the former general unsecured creditors of Gulfport. For financial statement reporting purposes,
Gulfport has not recognized the potential value of recoveries which may ultimately be obtained, if any, as a result
of the actions of the Litigation Trust, treating the entire $3,000,000 payment as a reorganization cost at the time
of Gulfport’s reorganization.
On January 20, 1998, Gulfport and the Litigation Trust entered into a Clarification Agreement whereby the
rights to pursue various claims reserved by Gulfport under the plan of reorganization were assigned to the
Litigation Trust. In connection with this agreement, the Litigation Trust agreed to reimburse the Company
$100,000 for legal fees Gulfport had incurred in connection with these claims. As additional consideration for the
contribution of this claim to the Litigation Trust, Gulfport is entitled to 20% to 80% of the net proceeds from
these claims.
No proceeds were received from the Litigation Trust for the years ended December 31, 2007, 2006, and
2005. The Company does not have knowledge of the amount or timing of any future proceeds.
F-31
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
21. SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION
ACTIVITIES
The following is historical revenue and cost information relating to the Company’s oil and gas operations
located entirely in the southeastern United States:
Capitalized Costs Related to Oil and Gas Producing Activities
December 31,
2007
2006
Proven Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unproven Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 447,209,000
36,172,000
$249,379,000
1,459,000
Accumulated depreciation, depletion amortization and
impairment reserve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(126,793,000)
(97,574,000)
Net capitalized costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 356,588,000
$153,264,000
Equity investment in Windsor Bakken LLC . . . . . . . . . . . . . . . . . . .
$
4,292,000
$
1,995,000
483,381,000
250,838,000
Costs Incurred in Oil and Gas Property Acquisition and Development Activities
Acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development of Proved
Undeveloped Properties . . . . . . . . . . . . . . . . . . .
Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recompletions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capitalized Asset Retirement Obligation . . . . . . . . . .
Year Ended December 31,
2007
2006
2005
$ 85,247,000
$
—
$
376,000
55,930,000
57,668,000
9,875,000
500,000
41,770,000
8,607,000
4,235,000
405,000
19,783,000
4,382,000
5,593,000
1,382,000
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$209,220,000
$55,017,000
$31,516,000
Equity investment in Windsor Bakken LLC . . . . . . . .
$
2,297,000
$ 1,995,000
$
—
F-32
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
Results of Operations for Producing Activities
The following schedule sets forth the revenues and expenses related to the production and sale of oil and
gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after
deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the
permanent differences. The results of operations exclude general office overhead and interest expense
attributable to oil and gas production.
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production costs . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depletion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$106,163,000
(29,337,000)
(29,220,000)
$ 60,232,000
(18,036,000)
(12,259,000)
$ 27,423,000
(11,276,000)
(4,468,000)
2007
2006
2005
Income tax expense
Current
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
47,606,000
29,937,000
11,679,000
121,000
—
121,000
—
—
—
—
—
—
Results of operations from producing activities . . . .
$ 47,485,000
$ 29,937,000
$ 11,679,000
Depletion per BOE . . . . . . . . . . . . . . . . . . . . . . . . . .
Net earnings from equity method investment in
Windsor Bakken LLC . . . . . . . . . . . . . . . . . . . . . .
$
$
17.85
20,000
$
$
12.48
—
$
$
7.29
—
F-33
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
Oil and Gas Reserves (Unaudited)
The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves
as of December 31, 2007, 2006 and 2005 and changes in proved reserves during the last three years, assuming
continuation of economic conditions prevailing at the end of each year. Volumes for oil are stated in thousands of
barrels (MBbls) and volumes for gas are stated in millions of cubic feet (MMcf). The weighted average prices at
December 31, 2007 used for reserve report purposes are $92.50 per barrel and $6.80 per MMbtu, adjusted by
lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The
weighted average prices at December 31, 2006 and 2005 used for reserve report purposes are $57.75 per barrel
and $5.64 per MMbtu and $57.75 per barrel and $10.08 per MMbtu, respectively.
Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are
subject to revision. The estimates are made using all available geological and reservoir data, as well as
production performance data. These estimates are reviewed annually and revised, either upward or downward, as
warranted by additional performance data.
2007
2006
2005
Oil
Gas
Oil
Gas
Oil
Gas
Proved Reserves
Beginning of the period . . . . . . . . . . . . . . . . . . . . . . .
Purchases of oil and gas reserves in place . . . . . . . .
Revisions of prior reserve estimates . . . . . . . . . . . . .
Current production . . . . . . . . . . . . . . . . . . . . . . . . . .
19,692
5,699
1,225
(1,501)
20,801
5,587
(1,313)
(816)
19,542
—
1,020
(870)
21,781
—
(303)
(677)
20,905
—
(846)
(517)
23,162
—
(806)
(575)
End of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
25,115
24,259
19,692
20,801
19,542
21,781
Proved developed reserves . . . . . . . . . . . . . . . . . . . .
7,116
6,746
4,876
4,077
4,308
3,758
Equity Investment in Windsor Bakken LLC
Net proved developed and undeveloped reserves . . .
Net proved developed reserves . . . . . . . . . . . . . . . . .
77
18
26
8
—
—
—
—
—
—
—
—
Discounted Future Net Cash Flows (Unaudited)
Estimates of future net cash flows from proven oil and gas reserves were made in accordance with SFAS
No. 69, “Disclosures about Oil and Gas Producing activities.” The following tables present the estimated future
cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2007, 2006 and
2005 assuming continuation of economic conditions prevailing at the end of each year.
F-34
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Year ended December 31,
2007
2006
2005
Future cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future development and abandonment costs . . . . . . . . . . . .
Future production costs . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future production taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$2,405,458,000
(326,229,000)
(420,646,000)
(275,977,000)
(280,538,000)
$1,296,729,000
(193,543,000)
(261,955,000)
(155,566,000)
(93,569,000)
$1,380,555,000
(174,462,000)
(234,508,000)
(172,282,000)
(172,045,000)
Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10% discount to reflect timing of cash flows . . . . . . . . . . . .
1,102,068,000
(433,773,000)
592,096,000
(239,448,000)
627,258,000
(257,434,000)
Standardized measure of discounted future net cash
flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 668,295,000
$ 352,648,000
$ 369,824,000
Equity investment in Windsor Bakken Standardized
measure of discounted cash flows . . . . . . . . . . . . . . . . . .
$
1,753,000
$
— $
—
In order to develop its proved undeveloped reserves according to the drilling schedule used by the engineers
in Gulfport’s reserve report, the Company will need to spend $97,962,000, $81,634,000 and $22,849,000 during
years 2008, 2009 and 2010, respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas
Reserves
Year ended December 31,
2007
2006
2005
Sales and transfers of oil and gas produced, net of production
costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ (76,826,000) $(42,196,000) $ (16,147,000)
Net changes in prices, production costs, and development
costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of oil and gas reserves in place . . . . . . . . . . . . . . . . .
Revisions of previous quantity estimates, less related production
costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net changes in income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in production rates and other . . . . . . . . . . . . . . . . . . . . . .
Total change in standardized measure of discounted future net
246,657,000
121,267,000
(67,273,000)
126,255,000
—
—
27,970,000
35,265,000
(106,145,000)
67,459,000
14,419,000
36,982,000
40,282,000
610,000
(14,869,000)
30,105,000
(26,591,000)
(29,976,000)
cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 315,647,000
$(17,176,000) $ 68,777,000
F-35
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
DECEMBER 31, 2007, 2006 AND 2005
22. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table summarizes quarterly financial data for the years ended December 31, 2007 and 2006:
Revenues . . . . . . . . . . . . . . . . . . . . . . .
Income from operations . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . .
Income per share:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . .
Revenues . . . . . . . . . . . . . . . . . . . . . . .
Income from operations . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . .
Income per share:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . .
2007
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
$20,381,000
7,870,000
53,000
7,287,000
$25,009,000
10,136,000
—
9,570,000
$29,975,000
13,245,000
4,000
12,701,000
$30,473,000
9,213,000
64,000
8,217,000
$
$
0.21
0.21
$
$
0.27
0.26
$
$
0.34
0.33
$
$
0.21
0.21
2006
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
$ 4,456,000
395,000
—
2,828,000
$14,360,000
6,779,000
—
7,059,000
$23,988,000
12,744,000
$17,586,000
5,937,000
—
—
12,517,000
5,404,000
$
$
0.09
0.08
$
$
0.22
0.21
$
$
0.38
0.37
$
$
0.16
0.16
F-36
CERTIFICATION
Exhibit 31.1
I, James D. Palm, Chief Executive Officer of Gulfport Energy Corporation, certify that:
1.
I have reviewed this annual report on Form 10-K of Gulfport Energy Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state
a material fact necessary to make the statement made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report,
fairly present in all material respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control
over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and
have:
a)
b)
c)
d)
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to
be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of
internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s
board of directors (or persons performing the equivalent functions):
a)
b)
all significant deficiencies and material weaknesses in the design or operation of internal controls over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal controls over financial reporting.
Date: March 17, 2008
/S/
JAMES D. PALM
James D. Palm
Chief Executive Officer
CERTIFICATION
Exhibit 31.2
I, Michael G. Moore, Chief Financial Officer of Gulfport Energy Corporation, certify that:
1.
I have reviewed this annual report on Form 10-K of Gulfport Energy Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state
a material fact necessary to make the statement made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report,
fairly present in all material respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control
over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and
have:
a)
b)
c)
d)
designed such disclosure controls and procedures, or caused such disclosure controls and procedures to
be designed under our supervision, to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly
during the period in which this report is being prepared;
designed such internal control over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end
of the period covered by this report based on such evaluation; and
disclosed in this report any change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the
case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of
internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s
board of directors (or persons performing the equivalent functions):
a)
b)
all significant deficiencies and material weaknesses in the design or operation of internal controls over
financial reporting which are reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
any fraud, whether or not material, that involves management or other employees who have a
significant role in the registrant’s internal controls over financial reporting.
Date: March 17, 2008
/S/ MICHAEL G. MOORE
Michael G. Moore
Chief Financial Officer
CERTIFICATION OF PERIODIC REPORT
Exhibit 32.1
I, James D. Palm, Chief Executive Officer of Gulfport Energy Corporation (the “Company”), certify, pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:
(1)
the Annual Report on Form 10-K of the Company for the period ended December 31, 2007 (the “Report”)
fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15
U.S.C. 78m(a) or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and
results of operations of the Company.
Date: March 17, 2008
/S/
JAMES D. PALM
James D. Palm
Chief Executive Officer
A signed original of this written statement required by Section 906 has been provided to the Company and
will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon
request.
CERTIFICATION OF PERIODIC REPORT
Exhibit 32.2
I, Michael G. Moore, Chief Financial Officer of Gulfport Energy Corporation (the “Company”), certify, pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:
(1)
the Annual Report on Form 10-K of the Company for the year ended December 31, 2007 (the “Report”)
fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15
U.S.C. 78m(a) or 78o(d)); and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and
results of operations of the Company.
Date: March 17, 2008
/S/ MICHAEL G. MOORE
Michael G. Moore
Chief Financial Officer
A signed original of this written statement required by Section 906 has been provided to the Company and
will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon
request.
d
Board of Directors
Don Dillingham*
David Houston*
Mike Liddell
James Palm
Scott Streller *
* Independent Directors
Annual Meeting
The annual meeting of shareholders is scheduled to be held at 10:00 AM on Wednesday, June 4, 2008. The
meeting will be held at the company headquarters at 14313 North May Avenue, Oklahoma City, OK.
Transfer Agent
For information regarding change of address, lost certifi cates or similar inquires, please contact our transfer agent:
Computershare Trust Company, N.A.
250 Royall Street
Canton, MA 02021
Toll free number for shareholders: 800-884-4225
Outside the U.S. and Canada: 781-575-4706
Market Information
Gulfport Energy’s common stock is traded on the NASDAQ Global Select Market under the symbol GPOR.
More Information
Additional company information, such as company presentations, press releases and other material can be found
on the company website at www.gulfportenergy.com
Investor Relations
For additional information concerning Gulfport Energy’s operation and fi nancial results, investor and analysts,
please contact John Kilgallon, Director of Investor Relations at (405) 242-4474.
Historical Stock Trading Data
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2007
High
$13.89
Low
$10.82
$21.34
$12.86
$23.70
$15.36
$25.62
$16.60
2006
High
$16.00
$18.59
$13.64
$14.11
Low
$10.00
$9.90
$9.82
$9.95