Table of Contents
Index to Financial Statements
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
x ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
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
Common Stock, par value $0.01 per share
Name of Each Exchange on Which Registered
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 x No ¨
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 x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and
(2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding
12 months (or such shorter period that the registrant was required to submit and post such files). Yes x 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. x
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 “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
(Check one):
Large Accelerated filer x Accelerated filer ¨ 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 x
The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of June 30,
2011, based on the closing price of the common stock on the NASDAQ Global Select Market on June 30, 2011, the last business day of the
registrant’s most recently completed second fiscal quarter ($29.69 per share) was $1,134,495,605.
As of February 20, 2012, 55,621,371 shares of the registrant’s common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Gulfport Energy Corporation’s Proxy Statement for the 2012 Annual Meeting of Stockholders are incorporated by reference
in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.
TABLE OF CONTENTS
Table of Contents
Index to Financial Statements
FORWARD-LOOKING STATEMENTS
PART I
ITEM 1.
BUSINESS
ITEM 1A.
RISK FACTORS
ITEM 1B.
UNRESOLVED STAFF COMMENTS
ITEM 2.
PROPERTIES
ITEM 3.
LEGAL PROCEEDINGS
ITEM 4.
MINE SAFETY DISCLOSURES
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, 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 AND FINANCIAL STATEMENT SCHEDULES
Signatures
Index to Consolidated Financial Statements
Exhibit Index
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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.
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ITEM 1.
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, and in West Texas in the Permian Basin. During 2010,
we acquired our initial acreage position in the Niobrara Formation of northwestern Colorado and, during 2011, we acquired our initial acreage
position in the Utica Shale in Eastern Ohio. 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 2011, at our WCBB field, we recompleted 68 wells and drilled 21 wells for a total cost of approximately $42.4 million as of
December 31, 2011. Of the 21 new wells drilled at WCBB in 2011, 19 were completed as producing wells, one was non-productive and one
was waiting on completion. In the fourth quarter of 2011, production at WCBB was 362,996 net barrels of oil equivalent, or BOE, or an
average of 3,946 BOE per day, 96% of which was from oil and 4% of which was from natural gas. From January 1, 2012 through
January 31, 2012, our average net daily production at WCBB was 3,705 BOE, 96% of which was from oil and 4% of which was from natural
gas. During 2012, we currently anticipate drilling 22 to 24 wells and recompleting 60 wells at our WCBB field for an estimated aggregate cost
of $36.0 million to $38.0 million.
In 2011, at our East Hackberry field, we recompleted 24 wells and drilled 22 wells for a total cost of approximately $51.9 million as of
December 31, 2011. Of the 22 new wells drilled at East Hackberry during 2011, 17 were completed as producing wells, two were non-
productive and three were waiting on completion. In the fourth quarter of 2011, net production at East Hackberry was 190,930 BOE, or an
average of 2,075 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From January 1, 2012 through
January 31, 2012, our average net daily production at East Hackberry was 2,220 BOE, 99% of which was from oil and 1% of which was
from natural gas. During 2012, we currently anticipate drilling 10 to 12 wells and recompleting 10 wells for an aggregate estimated cost of
$24.0 million to $26.0 million.
In the fourth quarter of 2011, net production at West Hackberry was 3,279 BOE, or an average of 36 BOE per day, 100% of which was
from oil. From January 1, 2012 through January 31, 2012, our average net daily production at West Hackberry was 37 BOE, 100% of which
was from oil.
In 2011, 39 gross (17 net) wells were drilled and eight gross (four net) wells were recompleted on our Permian Basin acreage for a total
net cost of $38.4 million. As of December 31, 2011, 35 of the 39 wells had been completed and four wells were awaiting completion. In the
fourth quarter of 2011, net production from our Permian Basin acreage was 93,760 BOE, or an average of 1,019 BOE per day, of which
approximately 74% was from oil, 13% was from natural gas liquids and 13% was from natural gas. From January 1, 2012 through
January 31, 2012, our average daily net production from our Permian Basin acreage was 1,032 BOE, of which 72% was from oil, 16% was
from natural gas liquids and 12% was from natural gas. We currently anticipate that 23 to 25 gross (11.5 to 12.5 net) wells will be drilled and
five gross (2.5 net) wells will be recompleted on this acreage in 2012 for an estimated aggregate net cost of $23.0 million to $25.0 million. In
an effort to facilitate the development of our Permian Basin and other domestic acreage, we acquired a 25% equity interest in Bison Drilling
and Field Services LLC, or Bison, which owns and operates four drilling rigs. The remaining 75% equity interest is owned by entities
controlled by Wexford Capital LP, or Wexford. An affiliate of Wexford owned approximately 13.3% of our outstanding common stock as of
February 20, 2012. We have also purchased a 25% interest in Muskie Holdings LLC, or Muskie, which holds certain rights in a lease
covering land in Wisconsin for mining oil and natural gas fracture grade sand. Muskie is controlled by Wexford.
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Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in northwestern Colorado and held leases for
approximately 15,000 net acres as of December 31, 2011. During the year ended December 31, 2011, we drilled three gross (1.5 net) wells on
this acreage. In the fourth quarter of 2011, net production from our Niobrara acreage was 3,390 BOE, or an average of 37 BOE per day,
100% of which was from oil. From January 1, 2012 through January 31, 2012, our average net daily production from our Niobrara acreage
was 41 BOE, 100% of which was from oil. In the Niobrara Formation, we have completed a 60 square mile 3-D seismic survey, have
received a processed version of the seismic and are selecting future drilling locations. During 2012, we currently anticipate drilling five to
seven gross wells in the Niobrara Formation for approximately $5.0 million to $6.0 million.
As of December 31, 2011, we held approximately 800 net acres in the Williston Basin of western North Dakota and eastern Montana
with interests in six wells and an overriding royalty interest in wells drilled prior to our 2009 sale of certain of our Bakken acreage and
production from such acreage, wells drilled subsequent to such sale and wells that might be drilled in the future. In the fourth quarter of 2011,
our net production from this acreage was 7,167 BOE, or an average of 78 BOE per day, of which 91% was from oil, 6% was from natural gas
and 3% was from natural gas liquids. From January 1, 2012 through January 31, 2012, our average daily net production from our Bakken
acreage was 71 BOE, of which 92% was from oil and 8% was from natural gas.
As of December 31, 2011, we had acquired leasehold interests in approximately 98,000 gross (49,000 net) acres in the Utica Shale in
Eastern Ohio. As of February 20, 2012, we had closed on additional acquisitions bringing our leasehold interests to approximately 107,000
gross (53,500 net) acres. We intend to continue to pursue opportunities in this area and have commitments with various future closing dates
that could increase our acreage position in the Utica Shale to an aggregate of approximately 125,000 gross (62,500 net) leasehold acres. We
recently spud our first well on our Utica Shale acreage.
During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in
Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. As of December 31, 2011, Grizzly had
approximately 754,000 acres under lease in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles of
other existing oil sands projects. As of December 31, 2011, Grizzly had drilled an aggregate of 203 core holes and four water supply test
wells, tested nine separate lease blocks and conducted a seismic program. In March 2010, Grizzly filed an application for the development of
an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order-in Council
authorizing the Alberta Energy Resources Conservation Board (ERCB) to issue the formal regulatory approval of Grizzly’s Algar Lake
SAGD project. Grizzly’s currently contemplated 2012 activities include the completion of the 2011/2012 core hole drilling and seismic
program, submission of a SAGD project regulatory application for Thickwood Hills and the development of its Algar Lake SAGD project,
which includes the fabrication and onsite construction of a central processing facility and the drilling of ten initial SAGD well pairs.
We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. The remaining interests in Tatex II are owned by entities
controlled by Wexford. Tatex II, 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 approximately two million acres which includes the Phu Horm Field.
We also own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Approximately 68.7% of the remaining interests in
Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately one million acres. In 2009, Tatex
III completed a 3-D seismic survey on this concession. The first well was drilled on our concession in 2010 and was temporarily abandoned
pending further scientific evaluation. Drilling of the second well concluded in March 2011. The second well was drilled to a depth of 15,026
feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and carried a flare
measuring up to 25 feet throughout drilling below the intermediate casing point of 9,695 feet. During testing, the well produced at rates as high
as 16 million cubic feet per day of
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Index to Financial Statements
gas for short intervals, but would subsequently fall to a sustained rate of 2 million cubic feet per day. Pressure buildup information confirmed
that this wellbore lacked the permeability to deliver commercial quantities of gas. Despite an apparently well-developed porosity system
suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to produce in
commercial quantities. Tatex III intends to continue testing some of the structures identified through its 3-D seismic survey and has begun the
application process for two more drilling locations. Tatex III currently expects to drill the first, located to the south of the TEW-E well, late this
year or early 2013.
As of December 31, 2011, we had 19.4 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 $490.5 million and associated standardized measure of
discounted future net cash flows of approximately $376.7 million, excluding reserves attributable to our interests in Grizzly, Tatex II and Tatex
III. 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, 2011 reflecting our net interest in our principal producing oil and
natural gas properties along the Louisiana Gulf Coast, in the Permian Basin in West Texas, in the Niobrara Formation in northwestern
Colorado and in the Williston Basin in western North Dakota and eastern Montana.
Proved Reserves
NRI/WI (1)
Productive
Wells (2)
Non-Productive
Wells
Developed
Acreage (3)
Field
West Cote Blanche Bay Field (4)
E. Hackberry Field (5)
W. Hackberry Field
Permian Basin
Niobrara Formation
Williston Basin (6)
Overrides/Royalty Non-operated
Total
Percentages Gross
95
80.108/100
30
79.424/100
87.5/100
2
121
35.4/46.87
6
39.7/47.9
2.8/3.3
6
133
Various
393
Net
Gross Net Gross
5,668
189
3,291
93
592
23
8,880
—
3,954
1
1,708
—
—
—
24,093
306
189
93
23
—
2
—
—
307
95
30
2
57
3
.2
.2
187.4
Total
Gas
Oil
MBOE MBOE MBOE
3,969
1,832
76
12,885
526
74
5
19,367
3,617
1,606
76
10,877
500
67
2
16,745
352
226
—
2,008
26
7
3
2,622
Net
5,668
3,291
592
4,119
1,977
132
—
15,779
(1) Net Revenue Interest (NRI)/Working Interest (WI).
(2)
(3) Developed acres are acres spaced or assigned to productive wells. Approximately 36% of our acreage is developed acreage and has been
Includes six gross and net wells at WCBB that are producing intermittently.
perpetuated by production.
(4) We have a 100% working interest (80.108% 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) NRI shown is for producing wells.
(6) NRI/WI is from wells that have been drilled or in which we have elected to participate.
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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 (80.108% 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 994 wells drilled as of December 31, 2011, 900 were
completed as producing wells. As a result, the field has a historic success rate of 91% for all wells drilled. From the date of our acquisition of
WCBB in 1997 through December 31, 2011, we drilled 183 new wells, 166 of which were productive, for a 91% success rate. As of
December 31, 2011, estimated field cumulative gross production was 192.6 MMBOE and 236.6 billion cubic feet, or Bcf, of gas. Of the 994
wells drilled in WCBB as of December 31, 2011, 89 were producing, 189 were shut-in, six were producing intermittently and five were being
used as salt water disposal wells. The other 705 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 994 wells that had been drilled in the field as of December 31, 2011, 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
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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 at WCBB as of December 31, 2011 included 24 PUD wells. The drilling
schedule used in the reserve report anticipates that all of those wells will be drilled by 2015.
Facilities
We own and operate a production facility at WCBB that includes four production tank batteries, eight natural gas compressors, a storage
barge facility, a dock, a dehydration unit and a salt water disposal system.
Recent and Future Activity
In 2011, we recompleted 68 gross and net wells and drilled 21 gross and net wells at WCBB. Nineteen of the new wells were completed
as producers, one was non-productive and one was waiting on completion. As of February 20, 2012, we had drilled three wells, were in the
process of drilling two additional wells and recompleted six wells during 2012. Of the 21 wells drilled in 2011, 18 were considered deep
wells. The 19 productive wells, with total depths ranging from 2,500 to 10,748 feet, have approximately 1,855 feet of aggregate apparent net
pay. We currently anticipate drilling 22 to 24 gross and net wells and recompleting 60 gross and net wells at WCBB during 2012.
Production Status
In the fourth quarter of 2011, our production at WCBB was 362,996 net BOE, or an average of 3,946 BOE per day, 96% of which was
from oil and 4% of which was from natural gas. From January 1, 2012 through January 31, 2012, our average net daily production at WCBB
was 3,705 BOE, 96% of which was from oil and 4% of which was from natural gas. The decrease in production was due to normal
production declines.
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 3,291 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. We also
hold 2,868 net acres subject to a two-year exploration agreement we entered into with an active gulf coast operator. We are the designated
operator under the agreement and will participate in proposed wells with at least a 70% working interest. We have licensed approximately 54
square miles of 3-D seismic data covering a portion of the area and are reprocessing the data.
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 2011 was over 1,625 MBOE and 330 Bcf
of casinghead gas production. A total of 223 wells have been drilled on our portion of the field. As of December 31, 2011, 30 wells had daily
production, 93 were shut-in and two had been converted to salt water disposal wells. The remaining 98 wells had been plugged and
abandoned.
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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 own and operate two production facilities at
East Hackberry that include a land based tank battery, production barge, three natural gas compressors, dehydration units and salt water
disposal systems.
Recent and Future Activity
During 2005, we completed a proprietary 42 square mile 3-D seismic survey at East Hackberry, the first modern seismic program
undertaken at this field. We believe that this 3-D seismic data enhances our probability of drilling success, and we continue to evaluate the 3-D
seismic data to identify additional drilling locations. During 2011 at East Hackberry, we recompleted 24 gross and net wells and drilled 13
gross and net land wells and nine gross and net wells on water. Seventeen of the 22 wells drilled during 2011 were completed as producing
wells, two were non-productive and three were waiting on completion. As of February 20, 2012, we had recompleted two wells during 2012,
drilled two wells and were in the process of drilling two additional wells. We currently intend to drill 10 to 12 gross and net wells and
recomplete 10 gross and net wells at East Hackberry during 2012.
Production Status
In the fourth quarter of 2011, our net production at East Hackberry was 190,930 BOE, or an average of 2,075 BOE per day, 97% of
which was from oil and 3% of which was from natural gas. From January 1, 2012 through January 31, 2012, our average net daily production
at East Hackberry was 2,220 BOE, 99% of which was from oil and 1% of which was from natural gas. The increase in production in 2012 is
a result of our 2012 drilling activities.
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 2011 was 286 MBOE
and 140 Bcf of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, two are producing, 23 are
shut-in and one has been converted to a saltwater disposal well. The remaining 10 wells have been plugged and abandoned.
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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 the fourth quarter of 2011, our net production at West Hackberry was 3,279 BOE, or an average of 36 BOE per day. From January 1,
2012 through January 31, 2012, our average net daily production at West Hackberry was 37 BOE and was 100% oil.
Facilities
We own and operate a production facility at West Hackberry that includes a land based tank battery and salt water disposal system.
Permian Basin (West Texas)
Location and Land
We acquired approximately 4,100 net acres and 32 gross (16 net) producing wells in West Texas (near Midland) in the Permian Basin
effective November 1, 2007. Subsequently, we acquired approximately 11,200 additional net acres, which brought our total net acreage
position in the Permian Basin to approximately 15,300 net acres as of December 31, 2011. 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 Basin is semi-arid mesquite-mixed grassland steppe. Windsor Permian LLC, or Windsor, an entity controlled by Wexford, is the
operator of this field.
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 Petroleum decided to drill completely through the Wolfcamp section as Devonian wells. Henry Petroleum 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 Petroleum’s Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry Petroleum’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. As of December 31, 2011, we held interests in 121 gross (57 net) 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
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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.
Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20% from the Spraberry section. Ryder Scott
Company L.P., or Ryder Scott, an independent petroleum engineering firm, has estimated that at December 31, 2011, proved reserves net to
our interest in these assets were approximately 12.9 million BOE, of which 23% were classified as proved developed producing, or PDP.
Proved undeveloped, or PUD, reserves included in this estimate were from 252 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.
Production Status
In the fourth quarter of 2011, our net production from the Permian Basin field was 93,760 BOE, or an average of 1,019 BOE per day, of
which 74% was from oil, 13% was from natural gas liquids and 13% was from natural gas. From January 1, 2012 through January 31, 2012,
our average daily net production from our Permian Basin acreage was 1,032 BOE, 88% of which was from oil and natural gas liquids and
12% of which was from natural gas.
Facilities
There are typical land oil and natural 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
In 2011, 39 gross (17 net) wells were drilled in our Permian Basin acreage. From January 1, 2012 to February 20, 2012, two gross
(one net) wells had been drilled on this acreage and were waiting on completion and at February 20, 2012 one gross (0.5 net) additional well
was being drilled. We have identified 252 gross future development drilling locations. We currently expect an estimated 23 to 25 gross (11.5
to 12.5 net) wells to be drilled on our acreage in 2012. The wells are expected to be drilled to approximately 11,200 feet. In an effort to
facilitate the drilling of these and future wells, in 2011 we acquired a 25% equity interest in Bison Drilling and Field Services LLC, or Bison,
which owns and operates four drilling rigs. We acquired our interest in Bison from Windsor Permian LLC, or Windsor. Windsor is the
operator of our Permian Basin properties and is controlled by Wexford. An affiliate of Wexford owned approximately 13.3% of our
outstanding common stock as of February 20, 2012. During 2011, we also purchased a 25% interest in Muskie Holdings LLC, or Muskie,
which holds certain rights in a lease covering land in Wisconsin for mining oil and natural gas fracture grade sand. Muskie is controlled by
Wexford.
Niobrara Formation (Northwestern Colorado)
Location and Land
Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in northwestern Colorado, and held leases for
14,993 acres as of December 31, 2011. We are the operator on the acreage.
Area History
The Niobrara Formation is a shale oil rock formation located in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast
Wyoming. Oil and natural gas can be found at depths of 3,000 to 14,000 feet and is drilled both vertically and horizontally. The Upper
Cretaceous Niobrara formation has emerged as another
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potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara
has a history of producing through conventional technology with some of the earliest production dating back to the early 1900s. Natural
fracturing has played a key role in producing the Niobrara historically due to the low porosity and low permeability of the formation. Because
of this, conventional production has been very localized and limited in area extent. We believe the Niobrara can be produced on a more
widespread basis using today’s horizontal multi-stage fracture stimulation technology where the Niobrara is thermally mature.
Geology
The Niobrara Formation oil play in northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin
to the north. Rocks mainly consist of interbedded organic-rich shales, calcareous shales and marlstones. It is the fractured marlstone intervals
locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the areas production. These fractured
carbonate reservoirs are associated with anticlinal, synclinal and monoclinal folds, and fault zones. This proven oil accumulation is considered
to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect oil generation.
The producing intervals are geologically equivalent to the Niobrara reservoirs of the DJ and Powder River Basins which are currently
emerging as a major crude resource play.
Production Status
In the fourth quarter of 2011, our net production from our Niobrara acreage was 3,390 BOE, or an average of 37 BOE per day, 100% of
which was from oil. From January 1, 2012 through January 31, 2012, our average daily net production from our Niobrara acreage was 41
BOE, 100% of which was from oil.
Facilities
There are typical land oil and gas processing facilities in the Niobrara Formation. Our facilities located at well locations include storage
tank batteries, oil/gas/water separation equipment and pumping units.
Recent and Future Activity
We drilled three gross (1.5 net) wells at Niobrara during 2011. We have completed a 60 square mile 3-D seismic survey over our Craig
Dome prospect, have received a processed version of the seismic and are selecting future drilling locations. We currently intend to drill five to
seven gross wells at Niobrara during 2012.
Bakken
Location and Land
The Bakken Shale is located in the Williston Basin areas of western North Dakota and eastern Montana. During 2005, we purchased a
20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken were owned by entities controlled by
Wexford. Beginning in 2005, Bakken acquired leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had
commenced participating in the drilling of some of its undeveloped acreage. Effective January 1, 2008, we acquired a direct, undivided 20%
interest in Bakken’s assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and
approximately 190 net BOEPD of production for approximately $13.0 million, with an effective date of April 1, 2009. During September
2009, we sold approximately 5,721 net acres for approximately $5.8 million with an effective date of July 1, 2009. As of December 31, 2011,
we held approximately 800 net acres, interests in six wells and an overriding royalty interest in wells drilled prior to our 2009 sale, wells
drilled subsequent to such sale and wells that might be drilled in the future.
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Production Status
In the fourth quarter of 2011, our net production from our Bakken acreage was 7,167 BOE, or an average of 78 BOE per day, of which
91% was from oil, 3% was from natural gas liquids and 6% was from natural gas. From January 1, 2012 through January 31, 2012, our
average net daily production from this acreage was 71 BOE, of which 92% was from oil and 8% was from natural gas.
Facilities
There are typical land oil and gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank
batteries, oil/gas/water separation equipment and pumping units.
Recent and future activities
One gross (.01 net) well was drilled on our acreage in 2011. There are no new activities currently scheduled for 2012 for our Bakken
acreage.
Utica Shale (Eastern Ohio)
Location and Land
As of December 31, 2011, we had acquired leasehold interests in approximately 98,000 gross (49,000 net) acres in the Utica Shale in
Eastern Ohio. As of February 20, 2012, we had closed on additional acquisitions bringing our leasehold interests to approximately 107,000
gross (53,500 net) acres. We intend to continue to pursue opportunities in this area and have commitments with various future closing dates
that could increase our acreage position in the Utica Shale to an aggregate of approximately 125,000 gross (62,500 net) leasehold acres. We
recently spud our first well on our Utica Shale acreage.
Area History
Based on the estimates published by the Ohio Department of Natural Resources, the Utica Shale has a recoverable potential of 1.3 billion
to 5.5 billion barrels of oil and 3.8 to 15.7 trillion cubic feet of natural gas. During 2011, a number of oil and gas companies made significant
investments in acquiring Utica Shale acreage in Eastern Ohio and applied for drilling permits with the Ohio Department of Natural Resources.
During 2011, most of the drilling activity in the Utica Shale occurred in Eastern Ohio, where our acreage is located. Based on the initial
drilling results, the Utica Shale is prospective for oil and natural gas liquids. Specifically, early wells drilled in the Utica Shale indicated
potential for production of significant amounts of natural gas liquids, which generally have a higher value, on an energy-equivalent basis, than
natural gas.
Geology
The Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of
organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late Ordovician period. It
overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale, which is estimated to be the largest exploration
play in the Eastern United States.
Recently, the application of horizontal drilling, combined with multistaged hydraulic fracturing to create permeable flow paths from
wellbores into shale units, has resulted in increased drilling activity and production in the Devonian-age Marcellus Shale in the Appalachian
Basin states of Pennsylvania, West Virginia, Southern New York and Eastern Ohio. This proven technology has potential for application in
other shale units, such as the Ordovician-age Utica Shale, which extends across much of the Appalachian Basin region.
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The Utica Shale is estimated to be thicker and more geographically extensive than the Marcellus Shale and, based on early drilling
results, has the potential to support commercial production. The potential source rock portion of the Utica Shale underlies portions of
Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West Virginia and Virginia in the United States and is also present beneath
parts of Lake Ontario, Lake Erie and part of Ontario, Canada. Throughout the potential source rock area, the Utica Shale ranges in thickness
from less than 100 feet to over 500 feet. Over the rock unit as a whole, there is a general thinning from east to west.
The Utica Shale is also significantly deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be
over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west
into Ohio and to the northwest under the Great Lakes and into Canada to less than 2,000 feet below sea level.
The Utica Shale is estimated to have higher carbonate and lower clay mineral content than the Marcellus Shale. The difference in
mineralogy generally produces a different response to hydraulic fracturing treatments. Based on early fracturing results in the Utica Shale, the
hydraulic fracturing methods used in the Marcellus Shale are less productive when applied in the Utica Shale. However, drillers have
improved the fracturing rates in other gas shales with similar carbonate content. For example, drillers have discovered methods to make the
brittle carbonate zones fracture at higher rates than other gas shale rock units in the Eagle Ford Shale in Texas. Drillers are researching
methods to make similar fracturing improvements in the Utica Shale.
Facilities
There are typical land oil and gas processing facilities in the Utica Shale. We will be required to build facilities located at well locations
include storage tank batteries, oil/gas/water separation equipment and pumping units.
Recent and future activities
We recently spud our first well on our Utica Shale acreage and expect to drill approximately 20 gross (ten net) wells during 2012.
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, Texas and Oklahoma as described in the following table:
Field
Deer Island
Napoleonville
Crest
Eagle City South
State
Louisiana
Louisiana
Texas
Oklahoma
Parish/County
Terrebonne
Assumption
Ochiltree
Dewey
Acreage Working
Interest
Overriding Royalty
Interests
Producing
Wells
3.125%
0%
2.000%
1.040%
0%
2.5%
0%
0%
1
3
1
1
Non-
Producing
Wells
0
0
0
0
Thailand. During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II, at a cost of $2.4 million. The
remaining interests in Tatex II are owned by entities controlled by Wexford. Tatex II, 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 approximately two million acres which includes the Phu Horm Field. During
the year ended December 31, 2011, we received $870,000 in distributions, reducing our total investment in Tatex II to $1.0 million. Our
investment is accounted for on the equity method. Tatex II 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
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northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet per day. For 2011, net gas production was
approximately 83 MMcf per day and condensate production was 380 barrels per day. Hess Corporation operates the field with a 35% interest.
Other interest owners include APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10% interest). Our gross working interest
(through Tatex II as a member of APICO) in the Phu Horm field is 0.7%. Due to the fact that our ownership in the Phu Horm field is indirect
and Tatex II’s investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information.
During the first quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III, at a cost of $850,000.
In December 2009, we purchased an additional approximately 12.9% ownership interest at a cost of approximately $3.4 million bringing our
total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled
by Wexford. Tatex III owns a concession covering approximately one million acres. In 2009, Tatex III completed a 3-D seismic survey on this
concession. During the year ended December 31, 2011, we paid $3.8 million in cash calls, bringing our total investment in Tatex III to $8.3
million. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. Drilling of
the second well concluded in March 2011. The second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of
apparent possible gas saturated column. The well experienced gas shows and carried a flare measuring up to 25 feet throughout drilling below
the intermediate casing point of 9,695 feet. During testing, the well produced at rates as high as 16 million cubic feet per day of gas for short
intervals, but would subsequently fall to a sustained rate of 2 million cubic feet per day. Pressure buildup information confirmed that this
wellbore lacked the permeability to deliver commercial quantities of gas. Despite an apparently well-developed porosity system suggesting
potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial
quantities. Tatex III intends to continue testing some of the structures identified through its 3-D seismic survey and has begun the application
process for two more drilling locations. Tatex III currently expects to drill the first, located to the south of the TEW-E well, late this year or
early 2013.
Grizzly Oil Sands. During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a
24.9% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. As of December 31, 2011, Grizzly
had approximately 754,000 acres under lease in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles
of other existing oil sands projects. Our total net investment in Grizzly was approximately $69.0 million as of December 31, 2011. As of
December 31, 2011, Grizzly had drilled an aggregate of 203 core holes and four water supply test wells, tested nine separate lease blocks and
conducted a seismic program. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at
Algar Lake. In November 2011, the Government of Alberta provided a formal Order-in Council authorizing the Alberta Energy Resources
Conservation Board (ERCB) to issue the formal regulatory approval of Grizzly’s Algar Lake SAGD project. Grizzly’s currently contemplated
2012 activities include the completion of the 2011/2012 core hole drilling and seismic program, submission of a SAGD project regulatory
application for Thickwood Hills and the development of its Algar Lake SAGD project, which includes the fabrication and onsite construction
of a central processing facility and the drilling of ten initial SAGD well pairs.
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 demand for oil and natural gas and the level of domestic production and imports of oil, the
proximity and capacity of gas pipelines, the availability of
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Index to Financial Statements
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 from WCBB is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude
plus or minus Platt’s trade month average P+ value, plus or minus the Platt’s HLS/WTI trade month average differential less $2.70 per barrel
for transportation. During 2011, we sold 93% and 7% of our oil production to Shell and Windsor, the operator of our Permian wells,
respectively, and 22%, 27% and 50% of our natural gas production to Windsor, Chevron and Hilcorp Energy Company, respectively. During
2010, we sold 75% and 19% of our oil production to Shell and Windsor, the operator of our Permian wells, respectively, and 50%, 32%, and
10% of our natural gas production to Windsor, Chevron and Hilcorp Energy Company, respectively. During 2009, we sold 92% and 7% of
our oil production to Shell and Windsor, the operator of our Permian wells, respectively, and 45%, 38%, and 16% of our natural gas
production to Windsor, Chevron and Hilcorp Energy Company, respectively. We may not 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 price 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, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB
production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January
2010 through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of
2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials.
In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the
period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels
of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through December 2012, we entered into
fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from January 2013 through
June 2013, we entered into fixed price swaps for 1,000 barrels of oil per day at a weighted average price of $113.20 per barrel. Under the
2010 contracts, we delivered approximately 45% of our 2010 production. Under the 2011 contracts, we delivered approximately 31% of our
2011 production. Under the 2012 contracts, we have committed to deliver approximately 32% to 35% of our estimated 2012 production. 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 forward sales contacts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant
to FASB ASC 815, “Derivatives and Hedging,“ and related pronouncements.
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, West Texas and the
Niobrara Formation in northwestern Colorado. The states in which our fields are located in regulate the production and sale of oil and natural
gas, including requirements for obtaining drilling
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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 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 which often require difficult 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, result in the suspension or revocation of
necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for
pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several 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 pollution control or 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 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, as amended, 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 in Congress to re-categorize certain oil and natural gas exploration, development and
production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital
expenditures and operating expenses.
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 applicable requirements related to waste handling, 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.
Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended,
also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without
regard to fault or legality of the original conduct, on classes
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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 at the facility. Under CERCLA and comparable state statutes, persons
deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously
disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater
contamination), 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 released.
Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act”, the Safe
Drinking Water Act or SDWA, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose
restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into
navigable waters of the United States, as well as state waters. 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. Spill prevention, control and countermeasure, or SPCC, plan
requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable
waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations 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 individual permits or coverage under general permits for storm water discharges.
Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as
for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs
that require permits for discharges or operations that may impact groundwater conditions.
The OPA,is the primary federal law for oil spill liability. OPA contains numerous requirements relating to the prevention of and
response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain
onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant
levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict,
joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to,
the costs of responding to a release of oil to surface waters.
Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as
injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.
Air Emissions. The Federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air
pollutants through the issuance of permits and the imposition of other requirements. 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. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants
at specified sources. In particular, on August 23, 2011, the EPA published in the Federal Register a proposed rule to establish new air
emission controls for oil and natural gas production and natural gas processing operations. The new emission standards seek to reduce volatile
organic compound, or VOC, emissions, including a 95 percent reduction in VOCs emitted during the construction or modification of
hydraulically-fractured wells. The EPA received public comment and conducted public hearing regarding the proposed rules and must take
final action on them by April 3, 2012. These laws and regulations may increase the costs of compliance for some
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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. Our
operations may also soon be affected by rapidly emerging regulation of “green house gases,” such as carbon dioxide and methane, which are
emitted in the course of oil and natural gas exploration and production.
Operational Hazards and Insurance
The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases,
abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic
gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage
or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and
suspension of operations.
In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to
which our business is exposed. We insure some, but not all, of our properties for operational and hurricane related events. We currently have
insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of certain wells,
oil pollution, third party liability, workers compensation and employers’ liability and other coverage. Our insurance coverage includes
deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is no assurance
that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events
could cause a significant disruption to our business. For example, we experienced production interruptions in 2005 and 2006 from Hurricanes
Katrina and Rita and, in 2008, from Hurricanes Gustav and Ike. A loss not fully covered by insurance could have a material adverse affect on
our financial position, results of operations and cash flows.
Currently, we have general liability insurance coverage with an annual aggregate limit of up to $21.0 million which includes
environmental impairment coverage for the effects of onshore and offshore pollution on third parties arising from our operations. For our
offshore West Cote Blanche Bay properties, we also have a $25.0 million property physical damage policy which insures against most
operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to $10.0
million for damages arising as a result of a named windstorm. In the event of a loss under this policy, we have up to $6.6 million of business
interruption coverage available after a 90 day waiting period. All of our insurance coverage includes deductibles of up to $1,000,000 per
occurrence ($1.5 million in the case of a named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to
customary exclusions and limitations. We reevaluate the purchase of insurance, policy terms and limits annually each May. Future insurance
coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may
become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will
be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage.
We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to
restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against,
could have a material adverse effect on our financial condition and results of operations.
At the depths and in the areas in which we operate, and in light of the vertical and directional drilling that we undertake, we typically do
not encounter high pressures or extreme drilling conditions. Accordingly, we typically do not carry a control of well policy, although we
currently have such coverage in place for five specific Southern Louisiana wells. In addition, it is currently anticipated that we will carry
control of well coverage for all of our Utica Shale wells. We also require all of our third party vendors to sign master service agreements in
which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired
by the service provider.
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We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities at WCBB in
response to federal and state requirements. The plans are reviewed annually and updated as necessary. As required by applicable regulations,
our facilities are built with oil containment features and we own certain oil containment equipment, such as oil boom to surround drill sites and
production facilities if needed. In addition, we have a national emergency response company on retainer. This company specializes in the clean
up of hydrocarbons as a result of spills, blow-outs and natural disasters. This emergency response company has been involved in the clean up
efforts of some of the largest oil spills along the Gulf Coast and is on call to us 24 hours a day when its services are needed. It has previously
reported that it owns over 164 response vehicles, 65 response vessels, 116 response trailers equipped with decontaminant supplies, personal
protective equipment and other equipment used in responding to oil spills, two storage barge sets, allowing for storage of up to 248 barrels of
recovered oil each, and over 20 roll-off boxes and vacuum boxes. We pay this company a retainer plus additional amounts when it provides us
with clean up services. Our aggregate payments for the retainer and clean up services during 2011 were approximately $220,000. While this
company has been able to meet our service needs when required from time to time in the past, it is possible that its ability to provide services to
us in the future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the depths and
the areas in which we operate, and the necessity for gas lift to produce our WCBB wells due to low reservoir pressure at our WCBB field, we
believe other companies would be available to us in the event our primary remediation company was unable to perform.
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. 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, 2011, we had 50 employees. An unrelated Louisiana well servicing company provides all necessary field personnel
needed to operate the WCBB and the Hackberry fields. In addition, in the past, certain of our employees performed management and
administrative services for affiliated companies. We were reimbursed by these affiliates for the salaries and benefits of these individuals based
on the estimated time they spent working for those affiliates. For the year ended December 31, 2009, expenses reimbursed to us under these
arrangements were $0.6 million, respectively, and are reflected as a reduction in our general and administrative expenses. No amounts were
reimbursed to us under these arrangements in 2011 or 2010.
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.
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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;
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, and other natural disasters 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;
speculative trading in crude oil and natural gas derivative contracts;
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, during the past five years, the West Texas Intermediate posted price for crude oil has ranged from a low of
$30.28 per barrel, or bbl, in December 2008 to a high of $145.31 per bbl in July 2008. The Henry Hub spot market price of natural gas has
ranged from a low of $1.83 per million British thermal units, or MMBtu, in September 2009 to a high of $15.52 per MMBtu in January 2006.
On February 15, 2012, the West Texas Intermediate posted price for crude oil was $101.80 per bbl and the Henry Hub spot market price of
natural gas was $2.43 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.
Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and
financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, the availability and cost of credit, the United States
mortgage market and a declining real estate market in the United States have contributed
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to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil,
natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic
slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and
commodity prices. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could
continue to diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect our vendors,
suppliers and customers ability to continue operations, and ultimately adversely impact our results of operations, liquidity and financial
condition.
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 have made and expect to make
in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil
and natural gas reserves. Historically, 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:
•
•
•
•
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 may not have sufficient resources to undertake our exploration, development and production activities or the acquisition of oil and
natural gas reserves, our exploratory projects or other replacement activities may not result in significant additional reserves and we may not
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. Further, these acquisitions may be in geographic regions in which we do
not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed
operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal
and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our
management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-
compliance with such additional legal requirements. 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.
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Our Canadian oil sands project is a complex undertaking and may not be completed at our estimated cost or at all.
During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in
Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. As of December 31, 2011, Grizzly had
approximately 754,000 acres under lease in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles of
other existing oil sands projects. Our total net investment in Grizzly was approximately $69.0 million as of December 31, 2011. As of
December 31, 2011, Grizzly had drilled an aggregate of 203 core holes and four water supply test wells, tested nine separate lease blocks and
conducted a seismic program. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at
Algar Lake. In November 2011, the Government of Alberta provided a formal Order-in Council authorizing the Alberta Energy Resources
Conservation Board (ERCB) to issue the formal regulatory approval of Grizzly’s Algar Lake SAGD project. Fabrication and onsite
construction on the first phase of development at Algar Lake is currently underway. This is a complex project and financing has not been
secured. There can be no assurance that financing can be obtained on commercially reasonable terms or at all.
Shortage of rigs, equipment, raw materials, supplies or personnel may restrict our operations.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and
other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and
demand for, and wage rates of, qualified drilling rig crews also rise 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, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars,
fracking 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 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’s written employment agreement and Mr. Palm’s oral employment
agreement, 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.
We may be limited in our ability to book additional proved undeveloped reserves under the recent SEC rules.
One of the impacts of the recent SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped
reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This rule may limit our
potential to book additional proved undeveloped reserves as we pursue our drilling program.
Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual production.
There are numerous uncertainties associated with estimating quantities of proved reserves and in projecting future rates of production
and timing of expenditures. The reserve information herein represents estimates
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prepared by Netherland, Sewell & Associates, Inc., or NSAI, with respect to our WCBB, Hackberry and Niobrara fields at December 31,
2011, with respect to our WCBB and Niobrara fields at December 31, 2010, and with respect to our WCBB field at December 31, 2009; by
Ryder Scott Company L.P., or Ryder Scott, at December 31, 2011, and by Pinnacle Energy Services, LLC, or Pinnacle, at December 31, 2010
and 2009, with respect to our assets in the Permian Basin in West Texas; and by our personnel with respect to our overriding royalty and non-
operated interests at December 31, 2011 and with respect to our Hackberry fields, overriding royalty and non-operated interests at
December 31, 2010 and 2009. 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.
Estimates of reserves as of year-end 2011, 2010 and 2009 were prepared using an average price equal to the unweighted arithmetic
average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended
December 31, 2011, 2010 and 2009, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for
such years. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for
undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.
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 for 2011, 2010 and 2009
on average price equal to the unweighted average of prices received on a field-by-field basis on the first day of each month within the 12-
month period ended December 31, 2011, 2010 and 2009, respectively, in accordance with the revised guidelines of the SEC applicable to
reserves estimates for such years. However, actual future net revenues from our oil and natural gas properties also will be affected by factors
such as:
•
•
•
•
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.
As of December 31, 2011, approximately 56% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves
requires significant capital expenditures and may require successful drilling operations. The reserve data assumes that we can and will make
these expenditures and conduct these operations successfully, but these assumptions may not be accurate, and this may not occur.
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There are numerous uncertainties in estimating quantities of bitumen reserves and resources in connection with our equity investment in
Grizzly and the indicated level of reserves or recovery of bitumen may not be realized.
There are numerous uncertainties in estimating quantities of bitumen reserves and resources, and the indicated level of reserves or
recovery of bitumen may not 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 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. The actual gravity or quality of bitumen to be produced from
Grizzly’s lands cannot be determined at this time.
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. 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 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 producing 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. 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.
A substantial portion of our producing properties is located in Louisiana, making us vulnerable to risks associated with operating in this
region.
Our largest field by production, 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 may not be able to obtain and maintain
adequate insurance at rates we consider reasonable or that any particular types of coverage will be available.
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Our identified drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially
alter the occurrence or timing of their drilling.
We have identified over 600 drilling locations on our Louisiana, West Texas and Western Colorado 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, drilling results and regulatory changes. 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 and could prevent us from realizing profits.
Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas,
including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline
failures, abnormally pressured formations, casing collapses, 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, suspension of operations and repairs to resume operations
In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not
all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer
be available to us or, if it is, its availability may be at premium levels that do not 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 not be able to secure additional insurance of bonding that might be required by new governmental regulations. This may cause
us to restrict our operations, which might severely impact our financial position. 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 development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We acquire significant amounts of unproved property in order to further our development efforts. Development and exploratory drilling
and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We
acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over
time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally,
there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new
wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved
property or wells.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do
not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a
well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed,
delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel,
environmental issues and for other reasons. In addition, wells that are profitable may not meet our internal return targets, which are dependent
upon the current and expected future market prices for oil and natural gas, expected
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costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. Drilling results in our newer oil and
liquids-rich shale plays may be more uncertain than in shale plays that are more developed and have longer established production histories,
and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to
maximize recoveries will be ultimately successful when used in newly developed shale formations.
We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development
efforts, the associated costs or the rate of production of the reserves on such properties.
Approximately 67% of our proved reserves at December 31, 2011 are attributable to our acreage position in the Permian Basin. We are
not the operator of these properties and may have limited ability to exercise influence over the operations of these and our other non-operated
properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to
influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The
success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be
largely outside of our control, including:
•
•
•
•
•
•
the timing and amount of capital expenditures;
the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
the operator’s expertise and financial resources;
approval of other participants in drilling wells;
selection of technology; and
the rate of production of the reserves.
In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund
our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be
reduced or forfeited.
Our undeveloped acreage in our Niobrara Formation must be drilled before lease expiration this year and within the next three years in
order to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could
result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified,
the leases for such acreage will expire. As of December 31, 2011, we had leases in our Niobara Formation representing approximately 13,000
net acres, 32%, 35%, 12%, 1% and 20% of which were scheduled to expire in 2012, 2013, 2014, 2015 and thereafter, respectively. The cost
to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As
such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business.
We may be unable to identify liabilities associated with the properties that we acquire or obtain protection from sellers against them.
Acquiring oil and gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves,
development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In
connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential
problems. In the course of our due
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diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipeline
corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our
purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the
properties may not perform in accordance with our expectations.
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, remediation, 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 primarily relating to protection of human health and the
environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or
criminal penalties, permit revocations and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and
regulations have continually imposed increasingly strict requirements for water and air pollution control and solid 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.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional
operating restrictions or delays.
Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons particularly natural gas, from
tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture
the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of
substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing generally is exempt from regulation under the
UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently
taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as
“Class II” UIC wells. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing
activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices.
Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing
activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As
part of these studies, both the EPA and the House committee have requested that certain companies provide them with information concerning
the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic
fracturing under the SDWA or otherwise.
In March 2011, companion bills entitled the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act of 2009 were
reintroduced in the United States Senate and House of Representatives. These bills, which are currently under consideration by Congress,
would repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate
regulations requiring permits and implementing potential new requirements on hydraulic fracturing under the SDWA. This could, in turn,
require state regulatory agencies in states with programs delegated under the SDWA to impose additional requirements on hydraulic fracturing
operations. In addition, the bills would require persons using hydraulic fracturing, such as us, to disclose the chemical constituents, but not the
proprietary formulas, of their fracturing fluids to a regulatory
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agency, which would make the information public via the internet. Additionally, fracturing companies would be required to disclose specific
chemical contents of fluids, including proprietary chemical formulas, to state authorities or to a requesting physician or nurse if deemed
necessary by the physician or nurse in connection with a medical emergency.
In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic
fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing
practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices.
Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with
hydraulic fracturing. In addition, the U.S. Department of Energy is conducting an investigation of practices the EPA could recommend to
better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior has
announced that it will consider regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing
fluid constituents. Also, certain members of the Congress have called upon the U.S. Government Accountability Office to investigate how
hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleading of
investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the
U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including
reserves from shale formations, as well as uncertainties associated with those estimates. On August 11, 2011, the Shale Gas Subcommittee of
the Secretary of Energy Advisory Board released a report proposing recommendations to reduce the potential environmental impacts from
shale gas production.
In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced
by natural gas extraction from underground coalbed and shale formations. The EPA stated that it will gather data, consult with stakeholders,
including ongoing consultation with industry, and solicit public comment on a proposed rule for coalbed methane in 2013 and a proposed rule
for shale gas in 2014.
These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to
further regulate hydraulic fracturing under the SDWA or other regulatory authorities.
Some states in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could
restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids.
For example, in September 2011, the Ohio legislature began consideration of legislation that would impose a temporary moratorium on drilling
involving hydraulic fracturing pending the delivery of the EPA study regarding the relationship between hydraulic fracturing and drinking
water resources. On May 31, 2011, the Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the
chemicals used in the hydraulic fracturing process. It was signed into law on June 17, 2011, effective as of September 1, 2011. The Texas
Railroad Commission will adopt rules and regulations implementing this legislation in two phases by July 1, 2012 and 2013, respectively. The
new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of federal OSHA for disclosure on
an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of
water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Effective
August 26, 2011, Montana adopted hydraulic fracturing disclosure regulations under which well operators must provide information in
drilling permit applications on the estimated volume and types of materials to be used in the proposed hydraulic fracturing activities. Upon
completion of the well, well operators must provide the Montana Board of Oil and Gas Conservation with the volume and type of chemicals
used, including the additive type, chemical ingredient names, and Chemical Abstracts Number, subject to certain trade secret protections. In
September 2011, the North Dakota Industrial Commission proposed new regulations for hydraulic fracturing activities that could require well
operators, under certain circumstances, to disclose the hydraulic fluid
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composition, including the trade name, supplier, ingredients, Chemical Abstracts Number, and the maximum ingredient concentrations of all
additives in the hydraulic fracturing fluid. We plan to use hydraulic fracturing extensively in connection with the development and production
of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing
or offshore drilling, including legislation and regulation in the states in which we operate, could reduce the volumes of oil and gas that we can
economically recover, which could materially and adversely affect our revenues and results of operations.
There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking
water supplies, use of waters and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits
and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that
significantly restrict hydraulic fracturing, such as the FRAC Act, are adopted, such laws could make it more difficult or costly for us to
perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing
process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect
groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject
to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and
recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs.
Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by
us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact
on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.
The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to
reduce the effect of commodity price, interest rate and other risks associated with our business.
The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative
instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress recently
adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal
oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed
into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission, or CFTC, and the SEC to promulgate
rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the new
legislation, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and
for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits.
It is not possible at this time to predict when the CFTC will finalize these regulations. The financial reform legislation may also require us to
comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future
derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also
require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as
creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative
contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of
derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our
derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we
use derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and its cash flows
may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended,
in part, to reduce the
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volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related
to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower
commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations
or cash flows.
Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and
cash flows.
The U.S. President’s Fiscal Year 2012 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax
laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs,
(ii) eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development and
(iii) implementing certain international tax reforms. These proposed changes in the U.S. tax laws, if adopted, could adversely affect our
business, financial condition, results of operations and cash flows.
The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural
gas we produce.
Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate
Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning
of oil, natural gas, and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United
States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to
reduce emissions of greenhouse gases. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA, that the
EPA has the authority to regulate carbon dioxide emissions from automobiles as “air pollutant” under the federal Clean Air Act. Thereafter, in
December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health
and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other
climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would
restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules,
one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain
large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it
became effective January 2011, although it does not require immediate reductions in GHG emissions. The EPA adopted the stationary source
rule in May 2010, and it also became effective January 2011, although it remains subject of several pending lawsuits filed by industry groups.
Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission
sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions
occurring in 2010. More recently, in November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil
and natural gas production and onshore processing, transmission, storage, and distribution facilities, which may include certain of our
facilities, beginning in 2012 for emissions occurring in 2011.
Furthermore, in July 2011, the EPA proposed several new emissions standards to reduce volatile organic compound, or VOC,
emissions from several types of processes and equipment used in the oil and natural gas industry, including a 95 percent reduction in VOCs
emitted during the construction or modification of hydraulically-fractured wells. Additionally, on August 23, 2011, the EPA published a
proposed rule in the Federal Register that would establish new air emission controls for oil and natural gas production and natural gas
processing operations. The EPA received public comment an conducted public hearings regarding the proposed rules and must take final
action on them by April 3, 2012.
In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security (ACES) Act that, among other things,
would have established a cap-and-trade system to regulate greenhouse gas
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emissions and would have required an 80% reduction in GHG emissions from sources within the United States between 2012 and 2050. The
ACES Act did not pass the Senate, however, and so was not enacted by the 111th Congress. The United States Congress is likely to again
consider a climate change bill in the future. Moreover, almost half of the states have already taken legal measures to reduce emissions of
GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs. Most of
these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such
as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs.
The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the
number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.
Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural
gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely
impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential
future laws or regulations addressing greenhouse gas emissions would impact our business.
Any failure by us to comply with applicable environmental laws and regulations may result in governmental authorities taking actions
that could adversely impact our operations and financial condition, including the:
•
•
•
•
•
issuance of administrative, civil and criminal penalties;
denial, suspension or revocation of necessary permits, licenses or other authorizations;
imposition of injunctive obligations or limitations on our operations;
requirement for additional pollution controls; and
required performance of site investigatory, remedial or other corrective actions.
In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more
intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate
change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience
temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our
costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to
which climate change may lead to increased storm or weather hazards affecting our operations.
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/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
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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 from WCBB is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude
plus or minus Platt’s trade month average P+ value, plus or minus the Platt’s HLS/WTI differential less $2.70 per barrel for transportation.
During 2011, we sold 93% and 7% of our oil production to Shell and Windsor, respectively and 22%, 27%, and 50% of our natural gas
production to Windsor, Chevron and Hilcorp Energy Company, respectively. During 2010, we sold 75% and 19% of our oil production to
Shell and Windsor, respectively and 50%, 32%, and 10% of our natural gas production to Windsor, Chevron and Hilcorp Energy Company,
respectively. During 2009, we sold 92% and 7% of our oil production to Shell and Windsor, respectively, and 45%, 38%, and 16% of our
natural gas production to Windsor, Chevron and Hilcorp Energy Company, respectively. We may not continue to have ready access to suitable
markets for our future oil and natural gas production.
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 the 12-month unweighted average of the first-day-of-the-month prices for
2011, 2010 and 2009 and prior to 2009, unescalated year-end prices, 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. If prices of oil, natural gas and natural gas liquids
decrease, we may be required to further write down the value of our oil and gas properties. Future non-cash asset impairments could
negatively affect our results of operations.
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.
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We have entered into forward sales contracts and fixed price swaps 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 mitigate the effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB
production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January
2010 through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of
2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials.
In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the
period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels
of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through December 2012, we entered into
fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from January 2013 through
June 2013, we entered into fixed price swaps for 1,000 barrels of oil per day at a weighted average price of $113.20 per barrel. Under the
2010 contracts, we delivered approximately 45% of our 2010 production. Under the 2011 contracts, we delivered approximately 31% of our
2011 production. Under the 2012 contracts, we have committed to deliver approximately 32% to 35% of our estimated 2012 production. 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. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contracts and
fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “Derivatives and Hedging,”
and related pronouncements.
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. The impact of the
changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of
operations and cash flows.
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:
•
•
•
changes in oil and natural gas prices;
changes in production levels;
changes in governmental regulations and taxes;
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•
•
•
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 largest stockholder controls a significant percentage of our common stock, and its interests may conflict with those of our other
stockholders.
As of February 20, 2012, Charles E. Davidson, our largest stockholder, beneficially owned approximately 13.3% of our outstanding
common stock. As a result, this stockholder acting alone is 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.
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 we may not 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, 2011, we had a net operating loss, or NOL, carry forward of approximately $116.8 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 February 20, 2012, there were 55,621,371 shares of our common stock
issued and outstanding, excluding 203,348 shares of unvested restricted stock awarded under our Amended and Restated 2005 Stock
Incentive Plan, 29,832 shares issuable upon exercise of outstanding warrants and 356,241 shares issuable upon exercise of outstanding
options to purchase our common stock granted under our Amended and Restated 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
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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.
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
SEC Rule-Making Activity
In December 2008, the SEC released its final rule for “Modernization of Oil and Gas Reporting.” These rules require disclosure of oil
and gas proved reserves by significant geographic area, using the arithmetic 12-month average beginning-of-the-month price for the year, as
opposed to year-end prices as had previously been required unless contractual arrangements designate the price to be used. Other significant
amendments included the following:
•
•
•
•
•
Disclosure of unproved reserves: probable and possible reserves may be disclosed separately on a voluntary basis.
Proved undeveloped reserve guidelines: reserves may be classified as proved undeveloped if there is a high degree of confidence that
the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances
justify a longer time.
Reserves estimation using new technologies: reserves may be estimated through the use of reliable technology in addition to flow
tests and production history.
Reserves personnel and estimation process: additional disclosure is required regarding the qualifications of the chief technical person
who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to
assure the objectivity of the reserves estimate.
Non-traditional resources: the definition of oil and gas producing activities has expanded and focuses on the marketable product
rather than the method of extraction.
We adopted the rules effective December 31, 2009, as required by the SEC.
Evaluation and Review of Reserves.
Reserve estimates at December 31, 2011 were prepared by NSAI with respect to our WCBB, Hackberry and Niobrara fields (33% of
our proved reserves at December 31, 2011), by Ryder Scott with respect to our assets in
34
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the Permian Basin in West Texas (67% of our proved reserves at December 31, 2011) and by our personnel with respect to our overriding
royalty and non-operated interests (less than 1% of our proved reserves at December 31, 2011).
NSAI and Ryder Scott are independent petroleum engineering firms. Copies of their summary reserve reports are included as Exhibit
99.1 and 99.2, respectively, to this Annual Report on Form 10-K. The technical persons responsible for preparing our proved reserve
estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards
Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our
independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI and Ryder Scott to
ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our WCBB, Hackberry and Niobrara
fields and our assets in the Permian Basin, respectively. Our internal technical team members meet with NSAI and Ryder Scott periodically
throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information
to NSAI and Ryder Scott for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating
and development costs. Our proved reserves attributable to our other minority interests are prepared internally by our internal staff of
petroleum engineers and geoscience professionals. Our chief reserve engineer is primarily responsible for overseeing the preparation of all of
our reserve estimates. He is a petroleum engineer with over 30 years of reservoir and operations experience and our geophysical staff has over
60 years combined industry experience. Our technical staff uses historical information for our properties such as ownership interest, oil and
gas production, well test data, commodity prices and operating and development costs.
The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures,
which are intended to ensure reliability of reserve estimations, include the following:
•
•
•
•
•
review and verification of historical production data, which data is based on actual production as reported by us;
preparation of reserve estimates by our experienced reservoir engineers or under their direct supervision;
review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the
review of all significant reserve changes and all new proved undeveloped reserves additions;
direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer; and
verification of property ownership by our land department.
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The following table sets forth our estimated proved reserves at December 31, 2011, 2010 and 2009:
2011
Year Ended December 31,
2010
2009
Proved developed
Proved undeveloped
Total (1)
Total net proved oil and natural gas reserves (MBOE) (1)
PV-10 value (in millions) (2)
Standardized measure (in millions) (3)
Oil
Oil
(MMcf)
(MBbls)
Natural
Gas
Natural
Gas
Natural
Gas
(MMcf)
7,485 6,152 7,230 6,068 6,165 4,325
9,260 9,576 12,474 10,090 11,323 10,007
16,745 15,728 19,704 16,158 17,488 14,332
(MBbls)
(MBbls)
(MMcf)
Oil
2011
19,367
$ 490.5
$ 376.7
Year Ended December 31,
2010
22,397
$ 392.6
$ 315.5
2009
19,877
$ 263.0
$ 240.8
(1) Estimates of reserves as of year-end 2011, 2010 and 2009 were prepared using an average price equal to the unweighted arithmetic
average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended
December 31, 2011, 2010 and 2009, respectively, in accordance with revised guidelines of the SEC applicable to reserves estimates as of
year-end 2011, 2010 and 2009. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they
include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe
these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of
recoverable oil and natural gas reserves may vary substantially from these estimates.
(2) 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 certain prevailing economic conditions. The estimated future
production in our reserve reports for the years ended December 31, 2011, 2010 and 2009 is priced based on the 12-month unweighted
arithmetic average of the first-day-of-the month price for the period January through December of the applicable year, using $96.19 per
barrel and $4.12 per MMBtu, $76.16 per barrel and $4.38 per MMBtu and $57.90 per barrel and $3.87 per MMBtu, respectively, and in
each case 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:
Standardized measure of discounted future net cash flows
Add: Present value of future income tax discounted at 10%
PV-10 value
2011
$376,681,000
113,791,000
$490,472,000
December 31,
2010
$315,487,000
77,117,000
$392,604,000
2009
$240,774,000
22,237,000
$263,011,000
(3) 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.
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The above table does not include proved reserves net to our interest in Tatex II, Tatex III or Grizzly. For further discussion of our
interest in Tatex II, Tatex III and Grizzly, see Item 1. “Description of Business—Additional Properties.”
The foregoing reserves are all located within the continental United States. 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.
Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves, or PUDs,
at December 31, 2011, 2010 and 2009 and changes in proved reserves during the last three years are contained in the Supplemental
Information on Oil and Gas Exploration and Production Activities, or Supplemental Information, in Note 20 to our consolidated financial
statements included in this report. Also contained in the Supplemental Information are our estimates of future net cash flows and discounted
future net cash flows from proved reserves. Additional information regarding our proved reserves can be found in “Management’s Discussion
and Analysis of Financial Condition and Results of Operations—Results of Operations” and “—Critical Accounting Policies and Estimates”
included in this report.
Proved Undeveloped Reserves (PUDs)
As of December 31, 2011, our proved undeveloped reserves totaled 9,260 MBOE of oil and 9,576 MMcf of natural gas, for a total of
10,856 MBOE. Approximately 88% of our PUDs at year-end 2011 were located in the Permian Basin, 6% of our PUDs were located in
WCBB, 3% were located in our East Hackberry field and 3% of our PUDs were located in our Niobrara field. PUDs will be converted from
undeveloped to developed as the applicable wells begin production. Changes in PUDs that occurred during 2011 were primarily due to:
•
•
•
•
Additions of 531 MBOE attributable to 2011 acquisitions and extensions;
Conversion of approximately 2,502 MBOE attributable to PUDs into proved developed reserves;
Positive revisions of approximately 331 MBOE in PUDs due to changes in commodity prices; and
Downward revisions to estimates of approximately 1,660 MBOE
Costs incurred relating to the development of PUDs were approximately $41.2 million in 2011. Estimated future development costs
relating to the development of PUDs are projected to be approximately $52.6 million in 2012, $49.9 million in 2013, $55.4 million in 2014,
$51.4 million in 2015 and $58.3 in 2016.
All PUD drilling locations are scheduled to be drilled prior to the end of 2016.
As of December 31, 2011, 16% of our total proved reserves were classified as proved developed non-producing.
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Production, Prices, and Production Costs
The following table presents our production volumes, average prices received and average production costs during the periods indicated:
Production Volumes:
Oil (MBbls)
Gas (MMcf)
Natural gas liquids (MGal)
Oil equivalents (MBOE)
Average Prices:
Oil (per Bbl)
Gas (per Mcf)
Natural gas liquids (per Gal)
Oil equivalents (per BOE)
Production Costs:
Average production costs (per BOE)
Average production taxes (per BOE)
Total production costs and production taxes (per BOE)
(1)
Includes various derivative contracts at a weighted average price of:
January – December 2009
January – December 2010
January – December 2011
2011
2010
2009
2,128
878
2,468
2,333
$104.33
(1)
4.37
$
$
1.25
$ 98.13
8.96
$
$ 11.29
$ 20.25
1,777
788
2,821
1,976
$68.29
(1)
$ 4.40
$ 1.00
$64.61
$ 8.92
$ 7.07
$15.99
1,531
491
2,719
1,677
$53.29
(1)
$ 4.06
$ 0.73
$51.01
$ 9.73
$ 5.84
$15.57
$55.01
$57.55
$86.96
Excluding the effect of fixed price swap contracts, the average oil price for 2011 would have been $107.13 per barrel of oil and $100.68
per BOE. The total volume hedged for 2011 represented approximately 31% of our total sales volumes for the year. Excluding the effect
of forward sales contracts, the average oil price for 2010 would have been $78.12 per barrel of oil and $73.45 per BOE. The total volume
hedged for 2010 represented approximately 45% of our total sales volumes for the year. Excluding the effect of forward sales contracts,
the average oil price for 2009 would have been $57.98 per barrel of oil and $55.29 per BOE. The total volume hedged for 2009
represented approximately 49% of our total sales volumes for the year.
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The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields
containing 15% or more of our total proved reserves as of December 31, 2011:
WCBB
Net Production
Oil (MBbls)
Gas (MMcf)
NGL (Mgal)
Total (MBOE)
Average Sales Price:
Oil (per Bbl)
Gas (per Mcf)
NGL (per Gal)
Average Production Cost (per BOE)
Permian Basin
Net Production
Oil (MBbls)
Gas (MMcf)
NGL (Mgal)
Total (MBOE)
Average Sales Price:
Oil (per Bbl)
Gas (per Mcf)
NGL (per Gal)
Average Production Cost (per BOE)
Productive Wells and Acreage
Year Ended December 31,
2011
2010
2009
1,258
237
—
1,298
1,176
410
—
1,244
1,209
192
—
1,241
$104.49
$
4.16
$ —
$62.57
$ 4.44
$ —
$52.39
$ 4.44
$ —
$
8.71
$ 8.90
$ 8.54
208
272
2,436
312
134
256
2,797
243
118
236
2,694
221
$ 90.86
3.94
$
1.25
$
$76.48
$ 4.21
$ 1.00
$55.19
$ 3.72
$ 0.73
$ 17.59
$ 9.78
$10.71
The following table presents our total gross and net productive and non-productive wells, expressed separately for oil and gas, and the
total gross and net developed and undeveloped acres as of December 31, 2011.
Field
West Cote Blanche Bay Field
(5)
E. Hackberry Field (6)
W. Hackberry Field
Permian Basin
Niobrara Formation (7)
Williston Basin (8)
Overrides/Royalty Non-
operated
Total
Productive
NRI/WI (1)
Oil Wells (2)
Percentages Gross Net
Productive
Gas Wells
Non-Productive
Oil Wells
Non-Productive
Gas Wells
Developed
Acreage (3)
Undeveloped
Acreage
(4)
Gross Net Gross
Net
Gross
Net
Gross Net
Gross Net
80.1/100 94
79.4/100 30
87.5/100
2
35.4/46.87 121
6
39.7/47.9
6
2.8/3.3
1 171 171
18 18 5,668 5,668 — —
1
94
93 93 — — 3,291 3,291 — —
30 — —
2 — —
592 — —
23 23 — —
57 — — — — — — 8,880 4,119 26,786 11,190
1 — — 3,954 1,977 26,033 13,016
3 — —
685
.2 — — — — — — 1,708
132 3,659
592
2
Various 133
.2
392 186.4
— — — — — — — — —
18 18 24,093 15,779 56,478 24,891
1 289 288
1
(1) Net Revenue Interest (NRI)/Working Interest (WI).
(2)
(3) Developed acres are acres spaced or assigned to productive wells. Approximately 36% of our acreage is developed acreage and has been
Includes six gross and net wells at WCBB that are producing intermittently.
perpetuated by production.
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(4) E. Hackberry acreage does not include 2,868 net acres subject to a two-year exploration agreement.
(5) We have a 100% working interest (80.108% 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).
(6) NRI shown is for producing wells.
(7) The leases relating to our Niobrara Formation acreage will expire at the end of their respective primary terms unless the applicable leases
are renewed or extended, we have commenced the necessary operations required by the terms of the applicable leases or we have obtained
actual production from acreage subject to the applicable leases, in which event they will remain in effect until the cessation of production.
Leases representing 32%, 35%, 12%, 1% and 20% of our total Niobrara undeveloped acreage are currently scheduled to expire in 2012,
2013, 2014, 2015 and thereafter, respectively.
(8) NRI/WI is from wells that have been drilled or in which we have elected to participate.
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.
Recompletions:
Productive
Dry
Total
Development:
Total
Exploratory:
Productive
Dry
Total
2011
2010
2009
Gross Net Gross Net Gross
Net
100
—
100
96
—
96
87
—
87
84
—
84
64
—
64
62.5
—
62.5
Productive
Dry
82
3
85
57
57
42
3 — —
42
57
60
25
1
26
18
1
19
1
—
1
1
—
1
—
—
—
—
—
—
1
—
1
1
—
1
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.
ITEM 3.
LEGAL PROCEEDINGS
The Louisiana Department of Revenue, or LDR, is disputing our severance tax payments to the State of Louisiana from the sale of oil
under fixed price contracts during the years 2005 through 2007. The LDR maintains that we paid approximately $1.8 million less in severance
taxes under fixed price terms than the
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Index to Financial Statements
severance taxes we would have had to pay had we paid severance taxes on the oil at the contracted market rates only. We have denied any
liability to the LDR for underpayment of severance taxes and have maintained that we were entitled to enter into the fixed price contracts with
unrelated third parties and pay severance taxes based upon the proceeds received under those contracts. We have maintained our right to
contest any final assessment or suit for collection if brought by the State. On April 20, 2009, the LDR filed a lawsuit in the 15th Judicial
District Court, Lafayette Parish, in Louisiana against our company seeking $2,275,729 in severance taxes, plus interest and court costs. We
filed a response denying any liability to the LDR for underpayment of severance taxes and are defending our company in the lawsuit. The
LDR had taken no further action on this lawsuit since filing its petition two years ago until recently when it propounded discovery requests to
which we have responded. We recently served discovery requests on the LDR and are awaiting the LDR’s response.
In December 2010, the LDR filed two identical lawsuits against us in different venues to recover allegedly underpaid severance taxes on
crude oil for the period January 1, 2007 through December 31, 2010, together with a claim for attorney’s fees. The petitions do not make any
specific claim for damages or unpaid taxes. As with the first lawsuit filed by the LDR in 2009, we have denied all liability and will vigorously
defend the lawsuit. The cases are in the very early stages, and we have not yet filed a response to these lawsuits. Recently, the LDR filed
motions to stay the lawsuits before we filed any responsive pleadings. The LDR has advised us that it intends to pursue settlement discussions
with us and other similarly situated defendants in separate proceedings.
In November 2006, Cudd Pressure Control, Inc., or Cudd, filed a lawsuit against us, Great White Pressure Control LLC, or Great
White, and six former Cudd employees 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 alleged RICO violations and several other
causes of action relating to Great White’s employment of the former Cudd employees and sought unspecified monetary damages and
injunctive relief. On stipulation by the parties, the plaintiff’s RICO claim was dismissed without prejudice by order of the court on
February 14, 2007. We filed a motion for summary judgment on October 5, 2007. The Court entered a final interlocutory judgment in favor of
all defendants, including us, on April 8, 2008. On November 3, 2008, Cudd filed its appeal with the U.S. Court of Appeals for the Fifth
Circuit. The Fifth Circuit vacated the district court decision finding, among other things, that the district court should not have entered
summary judgment without first allowing more discovery. The case was remanded to the district court, and Cudd filed a motion to remand the
case to the original state court, which motion was granted. On February 3, 2010, Cudd filed its second amended petition with the state court
(a) alleging that we conspired with the other defendants to misappropriate, and misappropriated Cudd’s trade secrets and caused its employees
to breach their fiduciary duties, and (b) seeking unspecified monetary damages. On April 13, 2010, our motion to be dismissed from the
proceeding for lack of personal jurisdiction was denied. This state court proceeding is in its initial stages. In 2011, the parties have continued
with written discovery and production of documents. On February 15, 2011, Cudd filed a third amended petition seeking $26.5 million (based
on a report prepared by its expert) plus disgorgement of $6.0 million in payments by Great White to the individual defendants and punitive
damages. Gulfport denies these claims with respect to itself. Recently, the parties began the process of scheduling and taking depositions and it
is anticipated that the case will remain in the discovery phase for at least the next several months.
On July 30, 2010, six individuals and one limited liability company sued 15 oil and gas companies in Cameron Parish Louisiana for
contamination across the surface of where the defendants operated in an action entitled Reeds et al. v. BP American Production Company et
al., 38th Judicial District. No. 10-18714. The plaintiffs’ original petition for damages, which did not name us as a defendant, alleges that the
plaintiffs’ property located in Cameron Parish, Louisiana within the Hackberry oil field is contaminated as a result of historic oil and gas
exploration and production activities. Plaintiffs allege that the defendants conducted, directed and participated in various oil and gas exploration
and production activities on their property which allegedly have contaminated or otherwise caused damage to the property, and have sued the
defendants for alleged breaches of oil, gas and mineral leases, as well as for alleged negligence, trespass, failure to warn, strict liability,
punitive damages, lease liability, contract liability, unjust enrichment, restoration damages, assessment and
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response costs and stigma damages. On December 7, 2010, we were served with a copy of the plaintiffs’ first supplemental and amending
petition which added four additional plaintiffs and six additional defendants, including us, bringing the total number of defendants to 21. It
also increased the total acreage at issue in this litigation from 240 acres to approximately 1,700 acres. In addition to the damages sought in the
original petition, the plaintiffs now also seek: damages sufficient to cover the cost of conducting a comprehensive environmental assessment of
all present and yet unidentified pollution and contamination of their property; the cost to restore the property to its pre-polluted original
condition; damages for mental anguish and annoyance, discomfort and inconvenience caused by the nuisance created by defendants; land loss
and subsidence damages and the cost of backfilling canals and other excavations; damages for loss of use of land and lost profits and income;
attorney fees and expenses; and damages for evaluation and remediation of any contamination that threatens groundwater. In addition to us,
current defendants include ExxonMobil Oil Corporation, Mobil Exploration & Producing North America Inc., Chevron U.S.A. Inc., The
Superior Oil Company, Union Oil Company of California, BP America Production Company, Tempest Oil Company, Inc., ConocoPhillips
Company, Continental Oil Company, WM. T. Burton Industries, Inc., Freeport Sulphur Company, Eagle Petroleum Company, U.S. Oil of
Louisiana, M&S Oil Company, and Empire Land Corporation, Inc. of Delaware. On January 21, 2011, we filed a pleading challenging the
legal sufficiency of the petitions on several grounds and requesting that they either be dismissed or that plaintiffs be required to amend such
petitions. In response to the pleadings filed by us and similar pleadings filed by other defendants, the plaintiffs filed a third amending petition
with exhibits which expands the description of the property at issue, attaches numerous aerial photos and identifies the mineral leases at issue.
In response, we and numerous defendants re-urged their pleadings challenging the legal sufficiency of the petitions. Some of the defendants’
grounds for challenging the plaintiffs’ petitions were heard by the court on May 25, 2011 and were denied. The court signed the written
judgment on December 9, 2011. We noticed our intent to seek supervisory review on December 19, 2011 and the trial court fixed a return date
of January 11, 2012 for the filing of the writ application. We filed our supervisory writ and the matter is currently pending before the
Louisiana Third Circuit Court of Appeal. We have served discovery requests and are currently responding to discovery requests from the
plaintiffs.
Due to the current stages of the above litigation, the outcomes are 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.
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. MINE SAFETY DISCLOSURES
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
Since July 14, 2006, our common stock has been quoted on The NASDAQ Global Select Market under the symbol “GPOR.” The
following table sets forth the high and low sale prices of our common stock for the periods presented:
2010
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2011
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2012
First Quarter (through February 15, 2012)
Price Range of
Common Stock
High
Low
$12.68
15.25
14.71
22.92
$ 8.89
10.60
10.37
13.59
$36.38
38.09
37.49
37.80
$20.00
23.84
22.00
18.72
$36.54
$29.63
On February 15, 2012, the last reported sale price of our common stock on The NASDAQ Global Select Market was $35.34.
Unregistered Sales of Equity Securities and Use of Proceeds
None, except that we issued 566 shares of our common stock upon exercise of certain outstanding warrants to purchase our common
stock in transactions exempt from registration under the Securities Act of 1933, as amended.
Holders of Record
At the close of business on February 15, 2012, there were 332 stockholders of record holding 55,621,371 shares of our outstanding
common stock. There were approximately 21,921 beneficial owners of our common stock as of February 15, 2012.
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 prohibit the
payment of any dividends to the holders of our common stock.
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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, 2011, December 31, 2010 and
December 31, 2009 and the selected consolidated balance sheet data at December 31, 2011 and December 31, 2010 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, 2008 and December 31, 2007 and the selected consolidated balance sheet data at December 31,
2009, December 31, 2008 and December 31, 2007 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
Costs and expenses:
Lease operating expenses
Production taxes
Depreciation, depletion and amortization
Impairment of oil and natural gas properties
General and administrative
Accretion expense
Income (Loss) from Operations
Other (Income) Expense:
Interest expense
Insurance recoveries
Settlement of fixed price contracts
Interest income
Loss from equity method investments
Income (Loss) before Income Taxes
Income Tax Expense (Benefit)
Net Income (Loss)
Net Income (Loss) Available to Common
Stockholders
Net Income (Loss) Per Common Share—Basic:
Net Income (Loss) Per Common Share—Diluted:
2011
Fiscal Year Ended December 31,
2009
2008
2010
2007
$229,254,000 $127,921,000 $85,968,000 $ 141,873,000 $106,315,000
20,897,000
26,333,000
62,320,000
—
8,074,000
666,000
118,290,000
110,964,000
17,614,000
13,966,000
38,907,000
—
6,063,000
617,000
77,167,000
50,754,000
16,316,000
9,797,000
29,225,000
—
4,992,000
582,000
60,912,000
25,056,000
22,856,000
15,813,000
42,472,000
272,722,000
6,843,000
560,000
361,266,000
(219,393,000)
16,670,000
12,667,000
29,681,000
—
5,802,000
554,000
65,374,000
40,941,000
1,400,000
—
—
(186,000)
1,418,000
2,632,000
108,332,000
(90,000)
108,422,000
2,761,000
—
—
(387,000)
977,000
3,351,000
47,403,000
40,000
47,363,000
2,309,000
(1,050,000)
—
(564,000)
706,000
1,401,000
23,655,000
28,000
23,627,000
4,762,000
(769,000)
(39,000,000)
(540,000)
656,000
(34,891,000)
(184,502,000)
—
(184,502,000)
3,091,000
—
—
(523,000)
477,000
3,045,000
37,896,000
121,000
37,775,000
$108,422,000 $ 47,363,000 $23,627,000 $(184,502,000) $ 37,775,000
1.03
$
1.01
$
(4.33) $
(4.33) $
1.08 $
1.07 $
0.55 $
0.55 $
2.22 $
2.20 $
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Index to Financial Statements
2011
2010
At December 31,
2009
2008
2007
Selected Consolidated Balance Sheet Data:
Total assets
Total debt, including current maturity
Total liabilities
Stockholders’ equity
$691,158,000
$
2,283,000
$ 58,808,000
$632,350,000
$319,693,000
$ 51,917,000
$108,637,000
$211,056,000
$227,344,000
$ 52,428,000
$102,293,000
$125,051,000
$221,873,000
$ 70,731,000
$107,772,000
$114,101,000
$419,137,000
$ 66,533,000
$115,015,000
$304,122,000
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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, and in West Texas in the Permian Basin. During 2010,
we acquired an acreage position in the Niobrara Formation of northwestern Colorado and, during 2011, we acquired our initial acreage
position in the Utica Shale in Eastern Ohio and have commitments to acquire additional acreage there. 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.
2011 Highlights
•
•
•
•
•
•
•
Oil and natural gas revenues increased 79% to $229.0 million for the year ended December 31, 2011 from $127.6 million for the
year ended December 31, 2010.
Net income increased 129% to $108.4 million for the year ended December 31, 2011 from $47.4 million for the year ended
December 31, 2010.
Production increased 18% to approximately 2,333,208 barrels of oil equivalent, or BOE, for the year ended December 31, 2011
from approximately 1,975,576 BOE for the year ended December 31, 2010.
During 2011, we drilled 86 gross (61 net) wells, which includes 40 gross (17 net) wells drilled by our operators in the Permian
Basin and Bakken, and recompleted 100 gross (96 net) wells. Of our 86 new wells drilled, 75 were completed as producing wells,
three were non-productive and eight were waiting on completion.
During 2011, we acquired approximately 600 additional net acres in the Permian Basin, which brought our total net acreage position
in the Permian Basin to approximately 15,300 net acres.
During 2011, we acquired leasehold interests in approximately 98,000 gross (49,000 net) acres in the Utica Shale in Eastern Ohio.
We intend to continue to pursue additional opportunities in this area and have commitments with various future closing dates which
could increase our acreage position in the Utica Shale to an aggregate of approximately 125,000 gross (62,500 net) leasehold acres.
We recently spud our first well on our Utica Shale acreage in February 2012.
In March, July and December of 2011, we completed a series of underwritten public offerings of an aggregate of 10,810,000 shares
of our common stock and received approximately $307.1 million in aggregate net proceeds, which we used to repay then outstanding
balances under our revolving credit facility, fund acquisitions of certain of our Utica Shale properties and for general corporate
purposes, which include future capital expenditures associated with drilling, development and infrastructure, principally in the Utica
Shale in Ohio.
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
46
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Index to Financial Statements
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. 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 the 12-month unweighted average
of the first-day-of-the-month price for the period 2011, 2010 and 2009, and prior to 2009, 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, including related deferred taxes for
differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds
the ceiling, an impairment or noncash writedown is required. 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 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 $138.6 million at December 31, 2011 and $16.8 million at
December 31, 2010. These costs are reviewed quarterly 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 the 12-month unweighted average of the first-day-of-the-month price
for the period January – December of the applicable year beginning with 2009, and prior to 2009, 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, including related
deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related
deferred taxes, 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 decline in oil and gas prices may result in an impairment of oil and
gas properties. For instance, as a result of the drop in commodity prices on December 31, 2008 and subsequent reduction in our proved
reserves, we recognized a ceiling test impairment of $272.7 million for the year ended December 31, 2008. If prices of oil, natural gas and
natural gas liquids decline, we may be required to further write down the value of our oil and gas properties, which could negatively affect our
results of operations. No ceiling test impairment was required for the year ended December 31, 2011.
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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 FASB ASC 410 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., Ryder Scott Company and to a lesser extent our personnel have prepared
reserve reports of our reserve estimates at December 31, 2011 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. Therefore,
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.
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Index to Financial Statements
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, 2011, a valuation allowance of $12.3 million 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 FASB ASC 815, “Derivatives and Hedging,” 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 FASB ASC 815, 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, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB
production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January
2010 through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of
2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials.
In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the
period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels
of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through December 2012, we entered into
fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from January 2013 through
June 2013, we entered into fixed price swaps for 1,000 barrels of oil per day at a weighted average price of $113.20 per barrel. Under the
2010 contracts, we delivered approximately 45% of our 2010 production. Under the 2011 contracts, we delivered approximately 31% of our
2011 production. Under the 2012 contracts, we have committed to deliver approximately 32% to 35% of our estimated 2012 production. 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 forward sales contracts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant
to FASB ASC 815 and related pronouncements.
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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)
Natural gas liquids (MGal)
Oil equivalents (MBOE)
Average Prices:
Oil (per Bbl)
Gas (per Mcf)
Natural gas liquids (per Gal)
Oil equivalents (per BOE)
Production Costs:
Average production costs (per BOE)
Average production taxes (per BOE)
Total production costs and production taxes (per BOE)
(1)
Includes various derivative contracts at a weighted average price of:
January – December 2009
January – December 2010
January – December 2011
2011
2010
2009
2,128
878
2,468
2,333
$104.33
(1)
4.37
$
$
1.25
$ 98.13
1,777
788
2,821
1,976
$68.29
(1)
$ 4.40
$ 1.00
$64.61
1,531
491
2,719
1,677
$53.29
(1)
$ 4.06
$ 0.73
$51.01
8.96
$
$ 11.29
$ 20.25
$ 8.92
$ 7.07
$15.99
$ 9.73
$ 5.84
$15.57
$55.01
$57.55
$86.96
Excluding the net effect of fixed price swap contracts, the average oil price for 2011 would have been $107.13 per barrel of oil and
$100.68 BOE. The total volume hedged for 2011 represented approximately 31% of our total sales volumes for the year. Excluding the
net effect of forward sales contracts, the average oil price for 2010 would have been $78.12 per barrel of oil and $73.45 per BOE. The
total volume hedged for 2010 represented approximately 45% of our total sales volumes for the year. Excluding the effect of forward sales
contracts, the average oil price for 2009 would have been $57.98 per barrel of oil and $55.29 per BOE. The total volume hedged for 2009
represented approximately 49% of our total sales volumes for the year.
From 2010 to 2011, our net equivalent oil production increased 18% from 1,975,576 BOE to 2,333,208 BOE due to the results of our
2011 drilling and recompletion activities. From 2009 to 2010, our net equivalent oil production also increased 18% from 1,677,000 BOE to
1,976,000 BOE due to increased drilling activity, the success of our drilling activities and our acquisitions of additional properties in the
Permian Basin and the Niobrara Formation. We currently estimate that our 2012 production will be between 3,000,000 and 3,200,000 BOE.
However, such estimate may change based on a change in our expected drilling and recompletion activities or the changing economic climate
and unforeseen events, such as hurricanes.
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Index to Financial Statements
Comparison of the Years Ended December 31, 2011 and December 31, 2010
We reported net income of $108,422,000 for the year ended December 31, 2011 as compared to net income of $47,363,000 for the year
ended December 31, 2010. This 129% increase in period-to-period net income was due primarily to an 18% increase in net production to
2,333,208 BOE and a 52% increase in realized BOE prices to $98.13 for the year ended December 31, 2011, partially offset by a 19%
increase in lease operating expenses, a 33% increase in general and administrative expenses and an 89% increase in production taxes.
Oil and Gas Revenues. For the year ended December 31, 2011, we reported oil and natural gas revenues of $228,953,000 as compared
to oil and natural gas revenues of $127,636,000 during 2010. This $101,317,000, or 79%, increase in revenues was primarily attributable to
an 18% increase in net production to 2,333,208 BOE from 1,975,576 BOE and a 52% increase in realized BOE prices to $98.13 from $64.61,
in each case for the year ended December 31, 2011 as compared to the year ended December 31, 2010.
The following table summarizes our oil and natural gas production and related pricing for the years ended December 31, 2011 and
December 31, 2010:
Oil production volumes (MBbls)
Gas production volumes (MMcf)
Natural gas liquids production volumes (MGal)
Oil equivalents (MBOE)
Average oil price (per Bbl)
Average gas price (per Mcf)
Average natural gas liquids (per Gal)
Oil equivalents (per BOE)
Year Ended
December 31,
2011
2,128
878
2,468
2,333
$104.33
4.37
$
$
1.25
$ 98.13
2010
1,777
788
2,821
1,976
$68.29
$ 4.40
$ 1.00
$64.61
Lease Operating Expenses. Lease operating expenses, or LOE, not including production taxes increased to $20,897,000 for the year
ended December 31, 2011 from $17,614,000 for 2010. This increase was mainly the result of an increase in expenses related to chemicals and
fuel, equipment repairs and maintenance, field supervision, overhead, property taxes, rentals, salt water disposal and well workovers.
Production Taxes. Production taxes increased to $26,333,000 for the year ended December 31, 2011 from $13,966,000 for 2010. This
increase was primarily related to an 18% increase in production and a 52% increase in the average realized BOE price received resulting in a
79% increase in oil and gas revenues.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense increased to $62,320,000 for
the year ended December 31, 2011, and consisted of $61,965,000 in depletion of oil and natural gas properties and $355,000 in depreciation
of other property and equipment, as compared to total DD&A expense of $38,907,000 for 2010. This increase was due to an increase in our
full cost pool as a result of our capital activities, an increase in our production and a decrease in our total proved reserves volume used to
calculate our total DD&A expense.
General and Administrative Expenses. Net general and administrative expenses increased to $8,074,000 for the year ended
December 31, 2011 from $6,063,000 for 2010. This $2,011,000 increase was due to an increase in salaries, stock compensation expenses and
benefits resulting from an increased number of employees, increases in legal expenses, franchise taxes and bank fees, partially offset by an
increase in administrative services reimbursements under the acquisition team agreement and an increase in general and administrative costs
related to exploration and development activity capitalized to the full cost pool.
Accretion Expense. Accretion expense increased slightly to $666,000 for the year ended December 31, 2011 from $617,000 for the same
period in 2010.
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Index to Financial Statements
Interest Expense. Interest expense decreased to $1,400,000 for the year ended December 31, 2011 from $2,761,000 for 2010 due to a
decrease in the interest rate paid and the repayment of all of our outstanding debt under our revolving credit facility during the fourth quarter of
2011 so that no amounts were outstanding as of December 31, 2011, as compared to $49,500,000 outstanding as of the same date in 2010.
Further, during 2010, in conjunction with the repayment of our prior revolving credit facility on September 30, 2010, we expensed
approximately $225,000 in unamortized loan fees associated with this facility, which is included in interest expense in our consolidated
statements of operations for the year ended December 31, 2010. Total weighted debt outstanding under our revolving credit facility was
$21,084,000 for the year ended December 31, 2011 and $46,931,000 for 2010. As of December 14, 2011 (the latest date during the year
ended December 31, 2011 on which we had borrowings outstanding), amounts borrowed under our credit facility bore interest at the
Eurodollar rate of 2.26%.
Income Taxes. As of December 31, 2011, we had a net operating loss carry forward of approximately $116.8 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, 2011, a valuation allowance of $12,347,000 had been provided for deferred tax assets, with the exception of
$1,000,000 related to alternative minimum taxes. We recognized an income tax benefit of $90,000 for the year ended December 31, 2011.
Comparison of the Years Ended December 31, 2010 and December 31, 2009
We reported net income of $47,363,000 for the year ended December 31, 2010, as compared to net income of $23,627,000 for the year
ended December 31, 2009. This 100% increase in 2010 was due primarily to a 27% increase in realized BOE prices to $64.61 from $51.01
and an 18% increase in net production to 1,976,000 BOE, partially offset by an 8% increase in lease operating expenses, a 21% increase in
general and administrative expenses and a 43% increase in production taxes.
Oil and Gas Revenues. For the year ended December 31, 2010, we reported oil and natural gas revenues of $127,636,000 as compared
to oil and natural gas revenues of $85,576,000 during 2009. This $42,060,000, or 49%, increase in revenues is primarily attributable to a 27%
increase in realized BOE prices to $64.61 from $51.01 and an 18% increase in net production to 1,975,576 BOE for the year ended
December 31, 2010 from 1,677,474 BOE for the year ended December 31, 2009.
The following table summarizes our oil and natural gas production and related pricing for the years ended December 31, 2010 and
December 31, 2009:
Oil production volumes (MBbls)
Gas production volumes (MMcf)
Natural gas liquids production volumes (MGal)
Oil equivalents (MBOE)
Average oil price (per Bbl)
Average gas price (per Mcf)
Average natural gas liquids (per Gal)
Oil equivalents (per BOE)
Year Ended
December 31,
2010
1,777
788
2,821
1,976
$68.29
$ 4.40
$ 1.00
$64.61
2009
1,531
491
2,719
1,677
$53.29
$ 4.06
$ 0.73
$51.01
Lease Operating Expenses. Lease operating expenses not including production taxes increased to $17,614,000 for 2010 from
$16,316,000 for 2009. This increase is mainly a result of an increase in ad valorem taxes and expenses related to well workovers.
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Production Taxes. Production taxes increased to $13,966,000 for 2010 from $9,797,000 for 2009. This increase was primarily related to
a 49% increase in oil and gas revenues as a result of a 27% increase in average realized BOE price received and an 18% increase in
production.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense increased to $38,907,000 for
2010, and consisted of $38,600,000 in depletion on oil and natural gas properties and $307,000 in depreciation of other property and
equipment. This compares to total depreciation, depletion and amortization expense of $29,225,000 for 2009. This increase was due to an
increase in our full cost pool as a result of our capital activities and an increase in our production used to calculate our total DD&A expense.
General and Administrative Expenses. Net general and administrative expenses increased to $6,063,000 for 2010 from $4,992,000 for
2009. This $1,071,000 increase was primarily due to a $450,000 increase in franchise taxes, a $200,000 increase in legal expenses and
increases related to salaries, benefits expenses partially offset by an increase in general and administrative overhead related to exploration and
development activity capitalized to the full cost pool.
Accretion Expense. Accretion expense increased slightly to $617,000 for 2010 from $582,000 for 2009.
Interest Expense. Interest expense increased to $2,761,000 for 2010 from $2,309,000 for 2009. This increase was due to an increase in
the interest rate paid as well as the recognition of approximately $225,000 in unamortized loan fees associated with the termination of the Bank
of America revolving credit facility. Effective September 30, 2010, this facility, along with the term loan with Bank of America, were repaid
with borrowings under our new senior secured revolving credit facility with The Bank of Nova Scotia, as administrative agent and letter of
credit issuer and lead arranger, and Amegy Bank National Association, entered into on September 30, 2010. This increase in interest expense
was partially offset by a decrease in average debt outstanding for the year ended December 31, 2010, as compared to the year ended
December 31, 2009. Total debt outstanding under our new revolving credit facility was $49.5 million as of December 31, 2010, as compared
to $49.9 million outstanding under our prior facilities with Bank of America as of the same date in 2009. Total weighted debt outstanding
under our facilities was $46.9 million for 2010 and $59.9 million for 2009. Until September 30, 2010, amounts borrowed under our term loan
and revolving credit facility with Bank of America bore interest of 3.76% and 3.25%, respectively. At December 31, 2010, amounts borrowed
under our new revolving credit agreement bore interest at the Eurodollar rate of 3.77%.
Income Taxes. As of December 31, 2010, we had a net operating loss carry forward of approximately $52.4 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, 2010, a valuation allowance of $54.4 million had been provided for deferred tax assets, with the exception of
$628,000 for alternative minimum taxes. We paid $40,000 of state income tax for the year ended December 31, 2010.
Liquidity and Capital Resources
Overview. Historically, our primary sources of funds have been cash flow from our producing oil and natural gas properties, borrowings
under our bank and other credit facilities and the issuance of equity securities. Our ability to access any of these sources of funds can be
significantly impacted by decreases in oil and natural gas prices or our oil and natural gas production. During 2011, we received aggregate net
proceeds (before offering expenses) of approximately $307.1 million from the sale of shares of our common stock. During 2010, we received
net proceeds (before offering expenses) of approximately $21.6 million from the sale of shares of our common stock.
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Net cash flow provided by operating activities was $158,138,000 for the year ended December 31, 2011 as compared to net cash flow
provided by operating activities of $85,835,000 for 2010. This increase was primarily the result of an increase in cash receipts from our oil
and natural gas purchasers due to a 52% increase in net realized BOE prices and an 18% increase in our net BOE production.
Net cash flow provided by operating activities was $85,835,000 for 2010, as compared to $53,299,000 for 2009. This increase was
primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to a 27% increase in net realized prices and an
18% increase in our net BOE production.
Net cash used in investing activities for the year ended December 31, 2011 was $323,248,000 as compared to $105,315,000 for 2010.
During the year ended December 31, 2011, we spent $287,292,000 in additions to oil and natural gas properties, of which $106,947,000 was
spent on our 2011 drilling and recompletion programs, $31,872,000 was spent on expenses attributable to the wells drilled and recompleted
during 2010, $8,320,000 was spent on compressors and other facility enhancements, $177,000 was spent on plugging costs, $124,713,000
was spent on lease related costs, primarily the acquisition of leases in the Utica Shale and $3,651,000 was spent on tubulars, with the
remainder attributable mainly to capitalized general and administrative expenses. In addition, $3,182,000 was loaned to, and $22,676,000 was
invested in, Grizzly during the year ended December 31, 2011, and $3,794,000, $6,009,000 and $2,142,000 was invested in our investments
in Tatex III, Bison and Muskie, respectively, during the year ended December 31, 2011. During the year ended December 31, 2011, we used
cash from operations and proceeds from our equity offering for our investing activities.
Net cash used in investing activities for 2010 was $105,315,000, as compared to $39,246,000 for 2009. During 2010, we spent
$101,644,000 in additions to oil and natural gas properties, of which $51,356,000 was spent on our 2010 drilling and recompletion programs,
$16,735,000 was spent on acquisitions in our Niobrara and Permian fields, $11,697,000 was spent on expenses attributable to the wells
drilled during 2009, $3,093,000 was spent on our 2009 recompletions, $6,838,000 was spent on compressors and other facility
enhancements, $1,425,000 was spent on plugging costs, $771,000 was spent on lease related costs and $3,449,000 was spent on tubulars,
with the remainder attributable mainly to capitalized general and administrative expenses. In addition, we paid $3,719,000 in cash calls to
Grizzly during 2010. During 2010, we used cash from operations, borrowings under our credit facilities and proceeds from our equity
offering to fund our investing activities.
Net cash provided by financing activities for the year ended December 31, 2011 was $256,539,000 as compared to $20,224,000 for
2010. The 2011 amount provided by financing activities was primarily attributable to the net proceeds of $307,154,000 from our equity
offerings and exercise of stock options, partially offset by net principal payments of $49,500,000 on borrowings under our credit facility. The
2010 amount provided by financing activities was primarily attributable to the net proceeds from our equity offerings of $21,358,000.
Net cash provided by financing activities for 2010 was $20,224,000 as compared to net cash used by financing activities of $18,273,000
for 2009. The 2010 amount provided by financing activities is primarily attributable to the net proceeds of $21,358,000 from our equity
offering and borrowings of $52,200,000 under our new credit facility, partially offset by principal payments of $49,903,000 on borrowings
under our prior credit facilities with Bank of America. We used the net proceeds of our 2010 equity offering to fund the acquisition of our
interests in the Niobrara Formation, pay the purchase price for a portion of the additional acreage acquired by us in the Permian Basin in 2010
and for general corporate purposes.
The 2009 amount used by financing activities was primarily attributable to principal payments on borrowings of $18,206,000 under our
credit facility with Bank of America, partially offset by $30,000 received from the exercise of stock options.
Credit Facility. On September 30, 2010, we entered into a $100.0 million senior secured revolving credit facility with The Bank of Nova
Scotia, as administrative agent and letter of credit issuer and lead arranger, and Amegy Bank National Association, or Amegy Bank, which
revolving credit facility initially matured on
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September 30, 2013 and had a borrowing base availability of $50.0 million, which was increased to $65.0 million effective December 24,
2010. On May 3, 2011, we entered into a first amendment to the revolving credit facility with the Bank of Nova Scotia, Amegy Bank,
KeyBank National Association, or KeyBank, and Société Générale. Pursuant to the terms of the first amendment, KeyBank and Société
Générale were added as additional lenders, the maximum amount of the revolving credit facility was increased to $350.0 million, the
borrowing base was increased to $90.0 million, certain fees and rates payable by us under the credit facility were decreased, and the maturity
date was extended until May 3, 2015. On October 31, 2011, we entered into additional amendments to our revolving credit facility pursuant to
which, among other things, the borrowing base under this facility was increased to $125.0 million. On December 14, 2011, we repaid all
outstanding borrowings under this credit facility with a portion of the net proceeds of our equity offering completed on December 5, 2011
pending the application of such proceeds to fund our additional Utica Shale lease acquisitions and for general corporate purposes. Our
revolving credit facility is secured by substantially all of our assets. Our wholly-owned subsidiaries guaranteed our obligations under the
revolving credit facility.
Advances under our revolving credit facility, as amended, may be in the form of either base rate loans or Eurodollar loans. The interest
rate for base rate loans is equal to (1) the applicable rate, which ranges from 1.00% to 2.50%, plus (2) the highest of: (a) the federal funds rate
plus 0.5%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the
Eurodollar rate for an interest period of one month plus 1.00%. The interest rate for Eurodollar loans is equal to (1) the applicable rate, which
ranges from 2.00% to 3.50%, plus (2) the London interbank offered rate that appears on Reuters Screen LIBOR01 Page for deposits in U.S.
dollars, or, if such rate is not available, the offered rate on such other page or service that displays the average British Bankers Association
Interest Settlement Rate for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money
center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. As of December 14, 2011
(the latest date during the year ended December 31, 2011 on which we had borrowings outstanding), amounts borrowed under our revolving
credit facility bore interest at the Eurodollar rate (2.26%).
Our revolving credit facility contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries’
ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; make investments; make fundamental changes;
enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with
their affiliates. The negative covenants are subject to certain exceptions as specified in the credit facility. The credit facility also contains certain
affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of funded debt to EBITDAX (net income,
excluding any non-cash revenue or expense associated with swap contracts resulting from ASC 815, plus without duplication and to the extent
deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period,
(b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts
attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all other non-cash
charges, (e) non-cash losses from minority investments, (f) actual cash distributions received from minority investments, (g) to the extent
actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable
transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offering, and less non-cash income
attributable to equity income from minority investments) for a twelve-month period may not be greater than 2.00 to 1.00; and (2) 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, 2011.
In connection with our scheduled spring 2012 borrowing base redetermination completed in February 2012, Scotia Capital has advised
us that it has recommended an increase to our borrowing base from the current level of $125.0 million to $150.0 million, subject to the
approval of the other banks in the syndicate.
Building Loans. In June 2004, we purchased the office building we occupy in Oklahoma City, Oklahoma, for $3.7 million. One loan
associated with this building matured in March 2006 and bore interest at the rate of 6% per annum, while a second loan was scheduled to
mature in June 2011. We entered into a new building loan
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in March 2011 to refinance the $2.4 million outstanding at that time. The new agreement extends the maturity date of the building loan to
February 2016 and reduces the interest rate from 6.5% per annum to 5.82% per annum. The new building loan requires monthly interest and
principal payments of approximately $22,000 and is collateralized by the Oklahoma City office building and associated land. As of
December 31, 2011, approximately $2.3 million was outstanding on this loan.
Capital Expenditures. Our recent capital commitments have been primarily for the execution of our drilling programs, to fund Grizzly’s
delineation drilling program and initial preparation of the Algar Lake facility and for acquisitions, primarily in the Permian Basin, the Niobrara
Formation and Utica Shale. 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, subject to economic and industry conditions, and (2) explore
acquisition and disposition opportunities.
Of our net reserves at December 31, 2011, 56% 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.
At December 31, 2011, our booked inventory of prospects included approximately 24 drilling locations at WCBB. The drilling schedule
used in our December 31, 2011 reserve report anticipates that all of those wells will be drilled by 2015. During 2011, we recompleted 68 wells
and drilled 21 wells, of which 19 were completed as producers, one was non-productive and one was waiting on completion, for an aggregate
cost of $42.4 million. From January 1, 2012 through February 20, 2012, we recompleted six existing wells and drilled three new wells at our
WCBB field, and at February 20, 2012 we were in the process of drilling two additional wells. We currently intend to recomplete 60 wells and
drill 22 to 24 new wells during 2012. Our aggregate drilling and recompletion expenditures for our WCBB field during 2012 are estimated to
be approximately $36.0 million to $38.0 million.
In our East Hackberry field, in 2011, we recompleted 24 existing wells and drilled 22 wells, of which 17 were completed as producers,
two were non-productive and three were waiting on completion for an aggregate cost of $51.9 million. From January 1, 2012 through
February 20, 2012, we recompleted two existing wells and drilled two new wells at our East Hackberry field, and at February 20, 2012 we
were in the process of drilling two additional wells. We currently intend to drill 10 to 12 wells and recomplete 10 wells in our East Hackberry
field in 2012. Total capital expenditures for our East Hackberry field during 2012 are estimated to be approximately $24.0 million to $26.0
million.
In the Permian Basin, our booked inventory of prospects at December 31, 2011 included 252 gross (124 net) future development drilling
locations. During 2011, 39 gross (17 net) wells were drilled on this acreage, of which 35 were completed as producers and four were waiting
on completion for an aggregate cost of $38.4 million. From January 1, 2012 through February 20, 2012, two gross (one net) wells were
drilled on this acreage and were waiting on completion and at February 20, 2012 one gross (0.5 net) additional well was being drilled. We
currently anticipate that our capital requirements to drill a total of 23 to 25 gross (11.5 to 12.5 net) wells and recomplete five gross (2.5 net)
wells in the Permian Basin in West Texas will be approximately $23.0 million to $25.0 million in 2012. In an effort to facilitate the
development of our Permian Basin and other domestic acreage, in 2011 we acquired a 25% equity interest in Bison Drilling and Field Services
LLC, or Bison, which owns and operates four drilling rigs. Our purchase price for this interest was approximately $6.0 million, subject to
adjustment. The remaining 75% equity interest is owned by entities controlled by Wexford. Also in 2011, we acquired a 25% interest in
Muskie Holdings LLC, or Muskie, which holds certain rights in a lease covering land in Wisconsin for mining oil and natural gas fracture
grade sand, for $2.1 million. Muskie is controlled by Wexford. The 2012 budgets for Bison and Muskie have not yet been established.
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In the Niobrara Formation in northwestern Colorado, in 2011, we completed a 60 square mile 3-D seismic survey, have received a
processed version of the seismic and are selecting future drilling locations. Our total capital expenditures in the Niobrara Formation were
approximately $6.8 million in 2011 relating to the seismic survey, drilling three gross (1.5 net) wells and leasehold acquisitions. We currently
anticipate that our total capital expenditures in the Niobrara Formation will be approximately $5.0 million to $6.0 million in 2012 to drill five to
seven gross wells.
In the Utica shale in Ohio, in 2011, we acquired approximately 98,000 gross (49,000 net) acres for $118.4 million. During 2012, we
expect to spend up to an additional $30.0 million to $35.0 million to acquire up to another 27,000 gross (13,500 net) acres. In addition, during
2012, we currently anticipate spending another $72.0 million to $76.0 million to drill 20 gross (ten net) wells.
During the third quarter of 2006, we purchased a 24.9% interest in Grizzly. As of December 31, 2011, our net investment in Grizzly
was approximately $69.0 million. Our capital requirements in 2012 for this project are estimated to be approximately $40.0 million to $43.0
million, primarily for the expenses associated with the construction of the Algar Lake facility and drilling activity during the 2011-2012 winter
drilling season. In addition, in January 2012, Grizzly entered into an agreement to purchase approximately 46,700 acres of oil sands leases in
the Athabasca oil sands area for $225.0 million CAD. Our capital contribution obligation to Grizzly for our portion of the purchase price is
approximately $56.3 million and will be due at closing of the transaction. We expect to fund this amount with borrowings under our revolving
credit facility.
Net capital expenditures in 2011 relating to our interest in Thailand were approximately $2.9 million. Capital expenditures in 2012
relating to our interests in Thailand are expected to be approximately $6.0 million, which we believe will be partially funded from our share of
production from the Phu Horm field.
Our total capital expenditures for 2012 are currently estimated to be in the range of $215.0 million to $225.0 million, excluding the
acquisition costs of our Utica Shale acreage, Grizzly May River acquisition and any other potential acquisitions. This is up from the $130.0
million spent on 2011 activities due to improved commodity pricing and cost environment. We intend to continue to monitor pricing and cost
developments and make adjustments to our future capital expenditure programs as warranted.
We believe that our cash on hand, cash flow from operations and borrowings under our revolving credit facility will be sufficient to meet
our normal recurring operating needs and capital requirements for the next twelve months. In the event we elect to further expand or accelerate
our drilling programs, pursue additional acquisitions or accelerate our Canadian oil sands project, we may be required to obtain additional
funds which we would seek to do through traditional borrowings, offerings of debt or equity securities or other means, including the sale of
assets. We regularly evaluate new acquisition opportunities. 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
The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty.
For example, during the past five years, the West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per barrel, or
bbl, in December 2008 to a high of $145.31 per barrel in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of
$1.83 per million British thermal units, or MMBtu, in September 2009 to a high of $15.52 per MMBtu in January 2006. On February 15,
2012, the West Texas Intermediate posted price for crude oil was $101.80 per barrel and the Henry Hub spot market price of natural gas was
$2.43 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.
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To mitigate the effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB
production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January
2010 through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of
2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials.
In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the
period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels
of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through December 2012, we entered into
fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from January 2013 through
June 2013, we entered into fixed price swaps for 1,000 barrels of oil per day at a weighted average price of $113.20 per barrel. Under the
2010 contracts, we delivered approximately 45% of our 2010 production. Under the 2011 contracts, we delivered approximately 31% of our
2011 production. Under the 2012 contracts, we have committed to deliver approximately 32% to 35% of our estimated 2012 production. 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 forward sales contracts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant
to FASB ASC 815 and related pronouncements.
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, 2011, the plugging and abandonment trust totaled approximately $3.1
million. At December 31, 2011, we have plugged 320 wells at WCBB since we began our plugging program in 1997, which management
believes fulfills our current minimum plugging obligation.
Contractual and Commercial Obligations
The following table sets forth our contractual and commercial obligations at December 31, 2011.
Contractual Obligations
Short-term and long-term debt
Asset retirement obligations
Total
Payment due by period (1)
Total
$ 2,283,000
12,653,000
$14,936,000
Less than 1 year
141,000
$
620,000
761,000
$
1-3 years
$ 476,000
1,361,000
$1,837,000
3-5 years
$1,666,000
792,000
$2,458,000
More than 5
years
$
—
9,880,000
$9,880,000
(1) Does not include estimated interest of $129,000 less than one year, $335,000 1-3 years and $16,000 3-5 years and short-term derivative
instruments of $1,601,000 less than one year.
New Accounting Pronouncements
In December 2008, the SEC published a final rule, “Modernization of Oil and Gas Reporting.” The new rule permits the use of new
technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserve volumes.
The new requirements also allow companies to disclose their probable and possible reserves. In addition, the new disclosure requirements
require companies to (a) report the independence and qualifications of its reserve preparer, (b) file reports when a third party is relied upon to
prepare reserve estimates or conducts a reserve audit, and (c) report oil and gas reserves using an average price based upon the prior 12-month
period rather than year end prices. The new requirements were effective for
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annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. We adopted this final rule as of December 31, 2009. The
adoption of the rule resulted in a lower price used in reserve calculations and a decrease in 2009 reserves. Updated disclosures are included in
Item 2. “Properties—Proved Oil and Natural Gas Reserves” and Note 20 to our consolidated financial statements included in this report.
In January 2010, the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and Disclosures”
(currently codified in FASB ASC Topic 932, “Extractive Activities – Oil & Gas”), or FASB ASC 932. The purpose of the amendments in
this Update was to align the oil and gas reserve estimation and disclosure requirements of FASB ASC 932 with the requirements in the SEC’s
final rule, “Modernization of Oil and Gas Reporting.“ The amendments to FASB ASC 932 were effective for annual reports on Form 10-K
for fiscal years ending on or after December 31, 2009. We adopted FASB ASC 932 effective December 31, 2009, the impact of which is
noted above.
In May 2011, the FASB issued Accounting Standards Update No. 2011-04, “Fair Value Measurement: Amendments to Achieve
Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” which provides amendments to FASB ASC
Topic 820, “Fair Value Measurements and Disclosure”, or FASB ASC 820. The purpose of the amendments in this update is to create
common fair value measurement and disclosure requirements between GAAP and IFRS. The amendments change certain fair value
measurement principles and enhance the disclosure requirements. The amendments to FASB ASC 820 are effective for interim and annual
periods beginning after December 15, 2011.
In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Comprehensive Income: Presentation of Comprehensive
Income,” which provides amendments to FASB ASC Topic 220, “Comprehensive Income”, or FASB ASC 220. The purpose of the
amendments in this update is to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. The
amendments eliminate the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity
and require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive
income either in a single continuous statement or in two separate but consecutive statements. The amendments to FASB ASC 220 are effective
for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively.
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.
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, during the past five years, the West Texas Intermediate posted price for crude oil has ranged from a low of
$30.28 per barrel, or bbl, in December 2008 to a high of $145.31 per barrel in July 2008. The Henry Hub spot market price of natural gas has
ranged from a low of $1.83 per million British thermal units, or MMBtu, in September 2009 to a high of $15.52 per MMBtu in
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January 2006. On February 15, 2012, the West Texas Intermediate posted price for crude oil was $101.80 per barrel and the Henry Hub spot
market price of natural gas was $2.43 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.
For the period January 2010 through February 2010, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB
production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials. For the period March
2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a
weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November 2010, we entered into fixed price
swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011.
For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of
$108.00 per barrel. For the period from March 2012 through December 2012, we entered into fixed price swaps for 3,000 barrels of oil per
day at a weighted average price of $109.73 per barrel. For the period from January 2013 through June 2013, we entered into fixed price swaps
for 1,000 barrels of oil per day at a weighted average price of $113.20 per barrel. Under the 2010 contracts, we delivered approximately 45%
of our 2010 production. Under the 2011 contracts, we delivered approximately 31% of our 2011 production. Under the 2012 contracts, we
have committed to deliver approximately 32% to 35% of our estimated 2012 production. 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 forward sales contracts
and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815 and related
pronouncements. At December 31, 2011, we had a net asset derivative position of $1.6 million related to our fixed price swaps. Utilizing
actual derivative contractual volumes, a 10% increase in underlying commodity prices would have reduced the fair value of these instruments
by approximately $7.7 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments
by $7.7 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the
actual sales value of production covered by the derivative instrument.
Our revolving credit facility is structured under floating rate terms, as advances under this facility may be in the form of either base rate
loans or Eurodollar loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the U.S. or, if the Eurodollar rates are
elected, the Eurodollar rates. At December 14, 2011 (the latest date during the year ended December 31, 2011 on which we had borrowings
outstanding), amounts borrowed under our revolving credit facility bore interest at the Eurodollar rate of 2.26%. Based on the current debt
structure, a 1% increase in interest rates would increase interest expense by approximately $130,000 per year, based on $13.0 million
outstanding under our revolving credit facility as of December 14, 2011. As of December 31, 2011, 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.
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
60
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Index to Financial Statements
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, 2011, 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(b) 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, 2011, 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 adequate 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, 2011.
Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended
December 31, 2011 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of
December 31, 2011, as stated in their accompanying report.
/s/ James D. Palm
Name: James D. Palm
Title:
Chief Executive Officer
/s/ Michael G. Moore
Name: Michael G. Moore
Title:
Chief Financial Officer
61
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Index to Financial Statements
Board of Directors and Stockholders
Gulfport Energy Corporation:
Report of Independent Registered Public Accounting Firm
We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of
December 31, 2011, 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, Gulfport Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated
balance sheets of Gulfport Energy Corporation and Subsidiaries as of December 31, 2011 and 2010, 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, 2011
and our report dated February 27, 2012 expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
February 27, 2012
62
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Index to Financial Statements
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
For information concerning Item 10—Directors, Executive Officers and Corporate Governance, see our definitive proxy 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 proxy 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 proxy 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
proxy 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 proxy 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).
63
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Index to Financial Statements
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
List the following documents filed as part of this report:
PART IV
Exhibit
Number
2.1
2.2
3.1
3.2
3.3
4.1
4.2
4.3
4.4
4.5
10.1+
10.2+
10.3+
10.4+
10.5+
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).
Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q,
File No. 000-19514, filed by the Company with the SEC on November 6, 2009).
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).
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).
Employment Agreement, dated as of May 18, 1999 and effective as of June 1, 1999, by and between the Company 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).
Summary of Oral Employment Agreement with James D. Palm (incorporated by reference to Exhibit 10.1 to Form 8-K, File No.
000-19514, filed by the Company with the SEC on December 7, 2010).
64
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Index to Financial Statements
Exhibit
Number
10.6
10.7
10.8
10.9
10.10
14
Description
Credit Agreement, dated as of September 30, 2010, by and among the Company, as borrower, the Bank of Nova Scotia,
as administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association (incorporated by
reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 6, 2010).
Amendment, dated as of December 24, 2010, to the Credit Agreement by and among the Company, as borrower, the Bank
of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association
(incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on
December 28, 2010).
First Amendment, dated May 3, 2011 of Credit Agreement, dated September 30, 2011, by and among the Company, as
borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National
Association, KeyBank National Association and Société Générale (incorporated by reference to Exhibit 10.2 of Form 10-
Q, File No. 000-19514, filed by the Company with the SEC on May 9, 2011).
Second Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The
Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association,
as syndication agent, KeyBank National Association, as co-documentation agent, and the other lenders party thereto
(incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on
November 4, 2011).
Third Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The
Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association,
as syndication agent, KeyBank National Association and Société Générale, as co-documentation agents, and the other
lenders party thereto (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company
with the SEC on November 4, 2011).
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).
21*
Subsidiaries of the Registrant.
23.1*
23.2*
23.3*
23.4*
31.1*
31.2*
32.1*
32.2*
99.1*
99.2*
Consent of Grant Thornton LLP.
Consent of Netherland, Sewell & Associates, Inc.
Consent of Ryder Scott Company.
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.
Report of Netherland, Sewell & Associates, Inc.
Report of Ryder Scott Company.
101.INS**
XBRL Instance Document.
101.SCH**
XBRL Taxonomy Extension Schema Document.
65
Table of Contents
Index to Financial Statements
Exhibit
Number
Description
101.CAL**
XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF**
XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB**
XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE**
XBRL Taxonomy Extension Presentation Linkbase Document.
Filed herewith.
Furnished herewith, not filed.
*
**
+ Management contract, compensatory plan or arrangement.
66
Table of Contents
Index to Financial Statements
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
SIGNATURES
undersigned, thereunto duly authorized.
Date: February 27, 2012
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: February 27, 2012
Date: February 27, 2012
Date: February 27, 2012
Date: February 27, 2012
Date: February 27, 2012
Date: February 27, 2012
Date: February 27, 2012
By:
By:
By:
By:
By:
By:
By:
S-1
/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/ CRAIG GROESCHEL
Craig Groeschel
Director
/s/ DAVID L. HOUSTON
David L. Houston
Director
/s/ SCOTT E. STRELLER
Scott E. Streller
Director
Table of Contents
Index to Financial Statements
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets, December 31, 2011 and December 31, 2010
Consolidated Statements of Operations, Years Ended December 31, 2011, 2010 and 2009
Consolidated Statements of Stockholders’ Equity and Comprehensive Income, Years Ended December 31, 2011, 2010 and 2009
Consolidated Statements of Cash Flows, Years Ended December 31, 2011, 2010 and 2009
Notes to Financial Statements
F-1
Page
F-2
F-3
F-4
F-5
F-6
F-7
Table of Contents
Index to Financial Statements
Board of Directors and Stockholders
Gulfport Energy Corporation:
Report of Independent Registered Public Accounting Firm
We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of
December 31, 2011 and 2010, 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, 2011. 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, 2011 and 2010, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of
America.
As discussed in Note 1, the Company changed its method of estimating oil and gas reserves and related disclosures in 2009.
We also have 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, 2011, 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 February 27,
2012 expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
February 27, 2012
F-2
Table of Contents
Index to Financial Statements
GULFPORT ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(Amounts rounded to nearest thousand)
Assets
Current assets:
Cash and cash equivalents
Accounts receivable—oil and gas
Accounts receivable—related parties
Prepaid expenses and other current assets
Short-term derivative instruments
Total current assets
Property and equipment:
Oil and natural gas properties, full-cost accounting, $138,623,000 and $16,778,000 excluded
from amortization in 2011 and 2010, respectively
Other property and equipment
Accumulated depletion, depreciation, amortization and impairment
Property and equipment, net
Other assets:
Equity investments
Note receivable—related party
Other assets
Total other assets
Deferred tax asset
Total assets
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities
Asset retirement obligation—current
Short-term derivative instruments
Current maturities of long-term debt
Total current liabilities
Asset retirement obligation—long-term
Long-term debt, net of current maturities
Total liabilities
Commitments and contingencies (Notes 17 and 18)
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, 100,000,000 authorized, 55,621,371 issued and
outstanding in 2011 and 44,645,435 in 2010
Paid-in capital
Accumulated other comprehensive income (loss)
Retained earnings (accumulated deficit)
Total stockholders’ equity
Total liabilities and stockholders’ equity
See accompanying notes to consolidated financial statements.
F-3
December 31,
2011
December 31,
2010
$
93,897,000
28,019,000
4,731,000
1,327,000
1,601,000
129,575,000
$
2,468,000
14,952,000
573,000
1,732,000
—
19,725,000
1,035,754,000
8,024,000
(575,142,000)
468,636,000
747,344,000
7,609,000
(512,822,000)
242,131,000
86,824,000
—
5,123,000
91,947,000
1,000,000
33,021,000
20,006,000
4,182,000
57,209,000
628,000
$ 691,158,000
$ 319,693,000
$
43,872,000
620,000
—
141,000
44,633,000
12,033,000
2,142,000
58,808,000
$ 41,155,000
635,000
4,720,000
2,417,000
48,927,000
10,210,000
49,500,000
108,637,000
—
—
556,000
604,584,000
2,663,000
24,547,000
632,350,000
446,000
296,253,000
(1,768,000)
(83,875,000)
211,056,000
$ 691,158,000
$ 319,693,000
Table of Contents
Index to Financial Statements
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts rounded to nearest thousand)
Revenues:
Oil and condensate sales
Gas sales
Natural gas liquid sales
Other income (expense)
Costs and expenses:
Lease operating expenses
Production taxes
Depreciation, depletion, and amortization
General and administrative
Accretion expense
INCOME FROM OPERATIONS
OTHER (INCOME) EXPENSE:
Interest expense
Insurance proceeds
Interest income
Loss from equity method investments
INCOME BEFORE INCOME TAXES
INCOME TAX EXPENSE (BENEFIT)
NET INCOME
NET INCOME PER COMMON SHARE:
Basic
Diluted
Weighted average common shares outstanding—Basic
Weighted average common shares outstanding—Diluted
Year Ended December 31,
2011
2010
2009
$ 222,025,000
3,838,000
3,090,000
301,000
229,254,000
$121,350,000
3,468,000
2,818,000
285,000
127,921,000
$81,587,000
1,992,000
1,997,000
392,000
85,968,000
20,897,000
26,333,000
62,320,000
8,074,000
666,000
118,290,000
17,614,000
13,966,000
38,907,000
6,063,000
617,000
77,167,000
16,316,000
9,797,000
29,225,000
4,992,000
582,000
60,912,000
110,964,000
50,754,000
25,056,000
1,400,000
—
(186,000)
1,418,000
2,632,000
108,332,000
(90,000)
2,761,000
—
(387,000)
977,000
3,351,000
47,403,000
40,000
2,309,000
(1,050,000)
(564,000)
706,000
1,401,000
23,655,000
28,000
$ 108,422,000
$ 47,363,000
$23,627,000
$
$
2.22
2.20
48,754,840
49,206,963
1.08
$
$
1.07
43,863,190
44,256,092
0.55
$
$
0.55
42,667,581
43,017,648
See accompanying notes to consolidated financial statements.
F-4
Table of Contents
Index to Financial Statements
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
(Amounts rounded to nearest thousand)
Common Stock
Shares
Amount
Additional
Paid-in
Capital
Accumulated
Other
Comprehensive
Income(Loss)
Retained
Earnings
(Accumulated
Deficit)
Total
Stockholders’
Equity
Balance at January 1, 2009
Net income
Other Comprehensive Income (Loss):
Foreign currency translation adjustment
Change in fair value of derivative
instruments
Reclassification of settled contracts
Total Comprehensive Income
Stock Compensation
Issuance of Restricted Stock
Issuance of Common Stock
through exercise of options
Balance at December 31, 2009
Net income
Other Comprehensive Income (Loss):
Foreign currency translation adjustment
Change in fair value of derivative
instruments
Reclassification of settled contracts
Total Comprehensive Income
Stock Compensation
Issuance of Common Stock in public offering,
42,639,201 $426,000 $273,343,000 $ (4,803,000) $(154,865,000) $114,101,000
23,627,000 23,627,000
—
—
—
—
—
—
—
5,499,000
—
5,499,000
—
—
—
43,458
—
—
—
—
— (13,422,000)
(5,313,000)
—
529,000
—
—
—
— (13,422,000)
(5,313,000)
—
10,391,000
529,000
—
—
—
1,000
13,750
30,000
42,696,409 427,000 273,901,000 (18,039,000) (131,238,000) 125,051,000
47,363,000 47,363,000
29,000
—
—
—
—
—
—
—
—
—
2,255,000
—
2,255,000
—
—
—
—
(4,720,000)
—
— 18,736,000
—
—
492,000
—
(4,720,000)
—
— 18,736,000
63,634,000
492,000
—
net of related expenses
1,668,503 17,000 21,341,000
—
— 21,358,000
Issuance of Common Stock through exercise of
warrants
Issuance of Restricted Stock
Issuance of Common Stock through exercise of
options
Balance at December 31, 2010
Net income
Other Comprehensive Income (Loss):
Foreign currency translation adjustment
Change in fair value of derivative
instruments
Reclassification of settled contracts
Total Comprehensive Income
Stock Compensation
Issuance of Common Stock in public offering,
173,109
58,525
2,000
—
204,000
—
—
—
—
—
206,000
—
48,889
315,000
44,645,435 446,000 296,253,000
—
—
—
—
—
(1,768,000)
315,000
(83,875,000) 211,056,000
— 108,422,000 108,422,000
—
—
—
—
(1,865,000)
—
(1,865,000)
—
—
—
—
—
1,576,000
4,720,000
—
—
1,287,000
—
—
—
1,576,000
4,720,000
112,853,000
1,287,000
—
net of related expenses
10,810,000 108,000 306,053,000
—
— 306,161,000
Issuance of Common Stock through exercise of
warrants
Issuance of Restricted Stock
Issuance of Common Stock through exercise of
options
Balance at December 31, 2011
566
63,370
—
1,000
—
(1,000)
—
—
—
—
—
—
102,000
993,000
55,621,371 $556,000 $604,584,000 $ 2,663,000 $ 24,547,000 $632,350,000
992,000
1,000
—
—
F-5
Table of Contents
Index to Financial Statements
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts rounded to nearest thousand)
Cash flows from operating activities:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Accretion of discount—Asset Retirement Obligation
Depletion, depreciation and amortization
Stock-based compensation expense
Loss from equity investments
Interest income—note receivable
Unrealized gain on derivative instruments
Deferred income tax benefit
Amortization of loan commitment fees
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable
(Increase) decrease in accounts receivable—related party
Decrease (increase) in prepaid expenses
Increase in other assets
Increase (decrease) in accounts payable and accrued liabilities
Settlement of asset retirement obligation
Net cash provided by operating activities
Cash flows from investing activities:
Deductions to cash held in escrow
Additions to other property, plant and equipment
Additions to oil and gas properties
Proceeds from sale of oil and gas properties
Advances on note receivable to related party
Contributions to investment in Grizzly Oil Sands ULC
Distributions from investment in Tatex Thailand II, LLC
Contributions to investment in Tatex Thailand III, LLC
Contributions to investment in Bison Drilling and Field Services LLC
Contributions to investment in Muskie Holdings LLC
Net cash used in investing activities
Cash flows from financing activities:
Principal payments on borrowings
Borrowings on line of credit
Loan commitment fees
Proceeds from issuance of common stock, net of offering costs, and exercise of stock options
Net cash provided by (used in) financing activities
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:
Capitalized stock based compensation
Asset retirement obligation capitalized
Foreign currency translation gain (loss) on investment in Grizzly Oil Sands ULC
Foreign currency translation gain (loss) on note receivable—related party
2011
Year Ended December 31,
2010
2009
$ 108,422,000
$ 47,363,000
$ 23,627,000
666,000
62,320,000
772,000
1,418,000
(147,000)
(25,000)
(372,000)
540,000
(13,067,000)
(4,158,000)
405,000
—
1,612,000
(248,000)
158,138,000
8,000
(415,000)
(287,292,000)
1,384,000
(3,182,000)
(22,676,000)
870,000
(3,794,000)
(6,009,000)
(2,142,000)
(323,248,000)
(97,634,000)
48,000,000
(981,000)
307,154,000
256,539,000
91,429,000
2,468,000
$ 93,897,000
$
$
$
$
$
$
991,000
1,000
515,000
1,390,000
(855,000)
(1,085,000)
617,000
38,907,000
295,000
977,000
(267,000)
—
(95,000)
—
(5,460,000)
(437,000)
315,000
(75,000)
4,948,000
(1,253,000)
85,835,000
8,000
(427,000)
(101,644,000)
304,000
(2,877,000)
(842,000)
565,000
(402,000)
—
—
(105,315,000)
(52,711,000)
52,200,000
(1,144,000)
21,879,000
20,224,000
744,000
1,724,000
2,468,000
582,000
29,225,000
317,000
706,000
(547,000)
—
120,000
—
3,051,000
965,000
(1,002,000)
—
(3,686,000)
(59,000)
53,299,000
8,000
(14,000)
(49,533,000)
18,286,000
(4,377,000)
—
197,000
(3,813,000)
—
—
(39,246,000)
(18,303,000)
—
—
30,000
(18,273,000)
(4,220,000)
5,944,000
$ 1,724,000
$
$
$
$
$
$
$
1,949,000
$ 2,300,000
40,000
197,000
1,328,000
$
$
$
543,000
212,000
361,000
1,313,000
$ 3,656,000
942,000
$ 1,843,000
See accompanying notes to consolidated financial statements.
F-6
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Index to Financial Statements
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2011, 2010 AND 2009
(Amounts rounded to nearest thousand)
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business
Gulfport Energy Corporation (“Gulfport” or the “Company”) is an independent oil and gas exploration, development and production
company with its principal properties located in the Louisiana Gulf Coast, in West Texas in the Permian Basin and in Western Colorado in the
Niobrara Formation and has investments in companies operating in Canada and Thailand. The Company recently acquired leasehold interests
in the Utica Shale in Eastern Ohio.
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., Jaguar Resources
LLC, Gator Marine, Inc., Gator Marine Ivanhoe, Inc. and Puma Resources, Inc. 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. The majority of its
receivables are from two purchasers of the Company’s oil and gas and one operator of certain of the Company’s properties. 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, 2011 and December 31, 2010.
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. Under the full cost method of accounting, the Company is 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 the 12-month unweighted average of the first-day-of-the-month price for 2011, 2010 and
2009, and prior to 2009, unescalated year-end prices and costs, adjusted for any contract provisions or financial derivatives, if any, that hedge
the Company’s
F-7
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Index to Financial Statements
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, including related deferred taxes for differences between the book and tax basis of the oil and natural gas
properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required.
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
$138,623,000 and $16,778,000 at December 31, 2011 and December 31, 2010, respectively. These costs are reviewed quarterly by
management for impairment. If impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of 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 FASB ASC Topic 410, “Asset Retirement and
Environmental Obligations” (“FASB ASC 410”), 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 oil and
natural gas properties by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized
cost is included in capitalized costs and depreciated consistent with depletion of reserves. 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 3 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. The following table presents the balances of the Company’s cumulative translation adjustments included in accumulated
other comprehensive income.
December 31, 2008
December 31, 2009
December 31, 2010
December 31, 2011
Net Income per Common Share
$(4,803,000)
$
696,000
$ 2,952,000
$ 1,087,000
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
F-8
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Index to Financial Statements
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 13.
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.
The Company is subject to U.S. federal income tax as well as income tax of multiple jurisdictions. The Company’s 1996 – 2010 U.S.
federal and state income tax returns remain open to examination by tax authorities, due to net operating losses. As of December 31, 2011, the
Company has no unrecognized tax benefits that would have a material impact on the effective rate. The Company recognizes interest and
penalties related to income tax matters as interest expense and general and administrative expenses, respectively. For the year ended
December 31, 2011, there is no interest or penalties associated with uncertain tax positions in the Company’s consolidated financial
statements.
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, 2011 and
2010 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. The Company reviews its investments to
determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company recognizes an
impairment provision. There was no impairment of equity method investments at December 31, 2011 or 2010.
Accounting for Stock-Based Compensation
The Company accounts for stock-based compensation in accordance with the provisions of FASB ASC Topic 718, “Compensation—
Stock Compensation” (“FASB ASC 718”). FASB ASC 718 requires share-based payments to employees, including grants of employee stock
options and restricted stock, 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.
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, or fixed-price
contracts. The Company follows the provisions of FASB ASC 815, “Derivatives and Hedging” (“FASB ASC 815”) as amended. It requires
that all derivative instruments be recognized as assets or liabilities in the statement of financial position, measured at fair value.
F-9
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Index to Financial Statements
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.
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 FASB ASC 815, 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. Any change in fair value resulting from ineffectiveness is recognized
immediately in earnings.
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, the realization of deferred
tax assets and the realization of future net operating loss carryforwards available as reductions of income tax expense. The estimate of the
Company’s oil and gas reserves is used to compute depletion, depreciation, amortization and impairment of oil and gas properties.
Reclassification
Certain reclassifications have been made to prior period financial statements to conform to current period presentation.
Recent Accounting Pronouncements
In December 2008, the Securities and Exchange Commission published a Final Rule, “Modernization of Oil and Gas Reporting.” The
new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable
conclusions about reserve volumes. The new requirements also allow companies to disclose their probable and possible reserves. In addition,
the new disclosure requirements require companies to (a) report the independence and qualifications of its reserve preparer, (b) file reports
when a third party is relied upon to prepare reserve estimates or conducts a reserve audit, and (c) report oil and gas reserves using an average
price based upon the prior 12 month period rather than year end prices. The new requirements were effective for annual reports on Form 10-K
for fiscal years ending on or after December 31, 2009. The Company adopted the Final Rule as of December 31, 2009. The adoption of the
rule resulted in a lower price used in reserve calculations and a decrease in 2009 reserves. See Item 2. Properties and Note 20 for further
discussion of the impact of implementation.
In January 2010, the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and Disclosures”
(currently codified in FASB ASC Topic 932, “Extractive Activities—Oil & Gas”) (“FASB ASC 932”). The purpose of the amendments in
this Update was to align the oil and gas reserve estimation and disclosure requirements of FASB ASC 932 with the requirements in the
Security and Exchange Commission’s Final Rule, “Modernization of Oil and Gas Reporting.” The amendments to FASB ASC 932 were
effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. The impact of the adoption of FASB ASC
932 is noted above.
F-10
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Index to Financial Statements
In May 2011, the FASB issued Accounting Standards Update No. 2011-04, “Fair Value Measurement: Amendments to Achieve
Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” which provides amendments to FASB ASC
Topic 820, “Fair Value Measurements and Disclosure” (“FASB ASC 820”). The purpose of the amendments in this update is to create
common fair value measurement and disclosure requirements between GAAP and IFRS. The amendments change certain fair value
measurement principles and enhance the disclosure requirements. The amendments to FASB ASC 820 are effective for interim and annual
periods beginning after December 15, 2011.
In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Comprehensive Income: Presentation of Comprehensive
Income,” which provides amendments to FASB ASC Topic 220, “Comprehensive Income” (“FASB ASC 220”). The purpose of the
amendments in this update is to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. The
amendments eliminate the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity
and require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive
income either in a single continuous statement or in two separate but consecutive statements. The amendments to FASB ASC 220 are effective
for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively.
2.
ACQUISITIONS
Beginning in February 2011, the Company entered into agreements to acquire certain leasehold interests located in the Utica Shale in
Ohio. Certain of the agreements also grant the Company an exclusive right of first refusal for a period of six months on certain additional
tracts leased by the seller. Affiliates of Gulfport have participated with the Company on a 50/50 basis in the acquisition of all leases described
above. Gulfport is the operator on this acreage in the Utica Shale. As of December 31, 2011, the Company had acquired leasehold interests in
approximately 98,000 gross (49,000 net) acres in the Utica Shale for approximately $118.1 million. Gulfport funded these transactions with a
portion of the proceeds from public offerings of an aggregate of 6.2 million shares of the Company’s common stock completed in March and
July of 2011. The Company received aggregate net proceeds (before offering expenses) of approximately $179.0 million from these equity
offerings, as discussed below in Note 8. The Company also has commitments which could increase its acreage
F-11
Table of Contents
Index to Financial Statements
position in the Utica Shale to approximately 125,000 gross (62,500 net) leasehold acres. The Company intends to continue to pursue
opportunities in this area.
On June 15, 2010, Gulfport acquired an ownership interest in certain oil and gas properties located in the Niobrara Formation of
Colorado, including three gross producing wells. The effective date of the acquisition was April 1, 2010. The total purchase price for the
acquired assets, as adjusted at closing on June 15, 2010, was $7.7 million, which was recorded as oil and natural gas properties on the
accompanying December 31, 2010 consolidated balance sheet. This amount includes an adjustment for the results of operations of the assets
between the April 1, 2010 effective date and the June 15, 2010 closing date. The results of operations from these properties were included in
the December 31, 2010 consolidated statement of operations for the period from June 16, 2010 through December 31, 2010. No pro forma
financials for this acquisition are disclosed as the acquisition was not deemed significant to the Company.
During May 2010, Gulfport acquired a 50% interest in 4,979 gross (2,489 net) undeveloped acres in the Permian Basin for
approximately $7.6 million.
Gulfport funded the 2010 transactions predominately with proceeds from a 1.7 million common share offering completed in May of
2010. The Company received net proceeds (before offering expenses) of approximately $21.6 million from the equity offering, as discussed
below in Note 8.
3.
ACCOUNTS RECEIVABLE—RELATED PARTIES
Included in the accompanying December 31, 2011 and December 31, 2010 consolidated balance sheets are amounts receivable from
related parties of the Company. These receivables consist primarily of amounts billed by the Company to related parties as operator of the
Company’s Colorado and Ohio oil and gas properties. At December 31, 2011 and December 31, 2010, these receivables totaled $4,731,000
and $573,000, respectively. The Company recorded $1,184,000 and $593,000 for the years ended December 31, 2011 and 2009, for general
and administrative functions performed under various agreements by Gulfport’s personnel on behalf of the related parties, which are reflected
as a reduction of general and administrative expenses in the consolidated statements of operations. These services are solely administrative in
nature and for entities in which the Company has no property interests. No amounts were reimbursed for general and administrative functions
for the year ended December 31, 2010. The 2011 amount was billed under the acquisition team agreement discussed below. No amounts were
recorded in 2011 or 2010 under the services agreements discussed below.
The Company is a party to an administrative service agreement with Oilfield Management Services, LLC (formerly known as Great
White Energy Services LLC). Under the agreement, 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 agreement
had an initial three-year term, and upon expiration of that term the agreement has continued on a month-to-month basis. The administrative
service agreement is terminable by either party at any time with at least 30 days prior written notice.
The Company is also a party to administrative service agreements with Stampede Farms LLC, Grizzly Oil Sands ULC (“Grizzly”),
Everest Operations Management LLC and Tatex Thailand III, LLC. Under the agreements, the Company’s services include professional and
technical support. The services provided and the fees for such services can be amended by mutual agreement of the parties. Each of these
administrative service agreements had an initial two-year term, and has continued thereafter on a month-to-month basis. Each agreement may
be cancelled by either party to such agreement with at least 60 days prior written notice and is also terminable (1) by the counterparty at any
time with at least 30 days prior written notice to the Company and
F-12
Table of Contents
Index to Financial Statements
(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’s administrative agreement with Grizzly was terminated effective December 31, 2010.
The Company was reimbursed the following amounts by the specified entities in consideration for its administrative services for the
years ended December 31, 2011, 2010 and 2009. These amounts are reflected as a reduction of general and administrative expenses in the
consolidated statements of operations. Wexford Capital LP (“Wexford”) controls and/or owns a greater than 10% interest in each of these
entities. An affiliate of Wexford owns approximately 13% of Gulfport’s outstanding common stock.
Agreement
Effective Date
7/22/2006 Oilfield Management Services, LLC
Stampede Farms LLC
3/1/2008
Grizzly Oil Sands ULC*
3/1/2008
Everest Operations Management LLC
3/1/2008
Tatex Thailand III, LLC
3/1/2008
Entity
* Agreement was terminated effective December 31, 2010.
December 31,
2011
$—
—
—
—
—
2010
$—
—
—
—
—
2009
$ 61,000
—
20,000
508,000
—
For the year ended December 31, 2009, the Company was also reimbursed approximately $2,000 and $1,000 by Stampede Farms LLC
and Everest Operations Management LLC, respectively, for office space under the administrative service agreements, which is included in
other income (expense) in the consolidated statements of operations. For the years ended December 31, 2011 and 2010, the Company was
reimbursed approximately $66,000 and $20,000, respectively, by Orange Leaf Holdings, LLC, an affiliate of Gulfport, for office space which
is included in other income (expense) in the consolidated statements of operations.
Effective July 1, 2008, the Company entered into an acquisition team agreement with Everest Operations Management LLC (“Everest”)
to identify and evaluate potential oil and gas properties in which the Company and Everest may wish to invest. Upon a successful closing of
an acquisition or divestiture, the party identifying the acquisition or divestiture is entitled to receive a fee from the other party and its affiliates,
if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate share of the acquisition or divestiture
consideration. The agreement may be terminated by either party upon 30 days notice.
Effective April 1, 2010, the Company entered into an area of mutual interest agreement with Windsor Niobrara LLC (“Windsor
Niobrara”), an entity controlled by Wexford, to jointly acquire oil and gas leases on certain lands located in Northwest Colorado for the
purpose of exploring, exploiting and producing oil and gas from the Niobrara Formation. The agreement provides that each party must offer
the other party the right to participate in such acquisitions on a 50%/50% basis. The parties also agreed, subject to certain exceptions, to share
third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement.
In connection with this agreement, Gulfport and Windsor Niobrara also entered into a development agreement, effective as of April 1, 2010,
pursuant to which the Company and Windsor Niobrara agreed to jointly develop the contract area, and Gulfport agreed to act as the operator
under the terms of a joint operating agreement.
F-13
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Index to Financial Statements
4.
PROPERTY AND EQUIPMENT
The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of
December 31, 2011 and 2010 are as follows:
Oil and natural gas properties
Office furniture and fixtures
Building
Land
Total property and equipment
Accumulated depletion, depreciation, amortization and impairment
Property and equipment, net
December 31,
2011
$1,035,754,000
3,692,000
4,049,000
283,000
1,043,778,000
(575,142,000)
$ 468,636,000
2010
$ 747,344,000
3,277,000
4,049,000
283,000
754,953,000
(512,822,000)
$ 242,131,000
No impairment of oil and natural gas properties was required under the ceiling test for the years ended December 31, 2011, 2010 and
2009.
Included in oil and natural gas properties at December 31, 2011 and December 31, 2010 is the cumulative capitalization of $23,494,000
and $18,126,000, 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 $5,368,000, $4,117,000 and $3,395,000 for the years ended December 31,
2011, 2010 and 2009, respectively.
The following is a summary of Gulfport’s oil and gas properties not subject to amortization as of December 31, 2011:
Acquisition costs
Exploration costs
Development costs
Total oil and gas properties not subject to
amortization
2011
$123,721,000
689,000
—
2010
$ 8,144,000
2,692,000
—
Costs Incurred in
2009
$ 915,000
155,000
—
Prior to 2009
$ 132,000
2,175,000
—
Total
$132,912,000
5,711,000
—
$124,410,000
$10,836,000
$1,070,000
$2,307,000
$138,623,000
At December 31, 2011, approximately $5,711,000 of oil and gas properties related to the Company’s Belize properties is excluded from
amortization as it relates to non-producing properties. In addition, approximately $9,831,000 of non-producing leasehold costs resulting from
the Company’s West Texas Permian Basin properties, $303,000 of non-producing leasehold costs related to the Company’s Bakken
properties and $4,163,000 of non-producing leasehold costs related to the Company’s Colorado properties are excluded from amortization at
December 31, 2011. Approximately $161,000 of non-producing leasehold costs related to the Company’s Southern Louisiana assets,
$118,420,000 of non-producing leasehold costs related to the Company’s Ohio leasehold costs and $34,000 of non-producing leasehold costs
related to other projects are also excluded from amortization. At December 31, 2010, approximately $16,778,000 of non-producing leasehold
costs was not subject to amortization.
F-14
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Index to Financial Statements
The Company evaluates the costs excluded from its amortization calculation at least annually. Subject to industry conditions and the level
of the Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation is expected to
occur within three to five years.
A reconciliation of the asset retirement obligation for the years ended December 31, 2011 and 2010 is as follows:
Asset retirement obligation, beginning of period
Liabilities incurred
Liabilities settled
Accretion expense
Asset retirement obligation as of end of period
Less current portion
Asset retirement obligation, long-term
December 31,
2011
$10,845,000
1,390,000
(248,000)
666,000
12,653,000
620,000
$12,033,000
2010
$10,153,000
1,328,000
(1,253,000)
617,000
10,845,000
635,000
$10,210,000
5.
EQUITY INVESTMENTS
Investments accounted for by the equity method consist of the following as of December 31, 2011 and 2010:
Investment in Tatex Thailand II, LLC
Investment in Tatex Thailand III, LLC
Investment in Grizzly Oil Sands ULC
Investment in Bison Drilling and Field Services LLC
Investment in Muskie Holdings LLC
December 31,
2011
$ 1,030,000
8,282,000
69,008,000
6,366,000
2,138,000
$86,824,000
2010
$ 1,907,000
4,660,000
26,454,000
—
—
$33,021,000
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. 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 two million acres which includes the Phu Horm Field. During 2011, Gulfport
received $870,000 in distributions, reducing its total net investment in Tatex to $1,030,000. The loss on equity investment related to Tatex was
immaterial for the years ended December 31, 2011, 2010 and 2009.
Tatex Thailand III, LLC
During the first quarter of 2008, the Company purchased a 5% ownership interest in Tatex Thailand III, LLC (“Tatex III”) at a cost of
$850,000. In December 2009, the Company purchased an additional approximately 12.9% ownership interest at a cost of approximately
$3,385,000 bringing its total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining interests in Tatex III are
owned by entities controlled by Wexford. During the year ended December 31, 2011, Gulfport paid $3,794,000 in cash calls, increasing its
total net investment in Tatex III to $8,282,000. The Company recognized a loss on equity investment of $172,000, $224,000 and $207,000 for
the years ended December 31, 2011, 2010 and 2009, respectively, which is included in loss from equity method investments in the
consolidated statements of operations.
F-15
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Index to Financial Statements
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, a Canadian unlimited liability company, for approximately $8,199,000. The remaining interests in Grizzly are owned by
entities controlled by Wexford. Since 2006, Grizzly has continued to acquire leases in the Athabasca region located in the Alberta Province
near Fort McMurray near other oil sands development projects. Grizzly has drilled core holes and water supply test wells in nine separate
lease blocks for feasibility of oil production and conducted a seismic program. In March 2010, Grizzly filed an application in Alberta, Canada
for the development of a SAGD facility at Algar Lake. In November 2011, the Government of Alberta provided a formal Order-in Council
authorizing the Alberta Energy Resources Conservation (ERCB) to issue formal regulatory approval of the project. Fabrication and onsite
construction on the first phase of development at Algar Lake is currently underway. As of December 31, 2011 and 2010, Gulfport’s net
investment in Grizzly was $69,008,000 and $26,454,000, respectively. Grizzly’s functional currency is the Canadian dollar. The Company’s
investment in Grizzly was decreased by $855,000 as a result of a currency translation loss for the year ended December 31, 2011 and
increased by $1,313,000 as a result of a currency translation gain for the year ended December 31, 2010. The Company recognized a loss on
equity investment of $1,592,000, $740,000 and $498,000 for the years ended December 31, 2011, 2010 and 2009, respectively, which is
included in loss from equity method investments in the consolidated statements of operations.
The Company, through its wholly owned subsidiary Grizzly Holdings Inc., entered into a loan agreement with Grizzly effective
January 1, 2008, under which Grizzly borrowed funds from the Company. Borrowed funds initially bore interest at LIBOR plus 400 basis
points and had an original maturity date of December 31, 2012. Effective April 1, 2010, the loan agreement was amended to modify the
interest rate to 0.69% and change the maturity date to December 31, 2011. Effective October 15, 2010, the loan agreement was further
amended to change the maturity date to December 31, 2012. Interest was paid on a paid-in-kind basis by increasing the outstanding balance of
the loan. The Company loaned Grizzly approximately $3,182,000 during the year ended December 31, 2011. The Company recognized
interest income of approximately $147,000, $267,000 and $547,000 for the years ended December 31, 2011, 2010 and 2009, respectively,
which is included in interest income in the consolidated statements of operations. The note balance was decreased by approximately
$1,085,000 as a result of a currency translation loss for the year ended December 31, 2011 and increased by $942,000 as a result of a currency
translation gain for the year ended December 31, 2010. Effective December 7, 2011, Grizzly Holdings Inc. entered into a debt settlement
agreement with Grizzly under which Grizzly agreed to satisfy the entire outstanding debt by issuing additional common shares of Grizzly with
no effect to the composition of ownership structure of Grizzly. At such date, the Company’s investment in Grizzly increased by the total
$22,325,000 outstanding advances and accrued interest due from Grizzly, the cumulative $75,000 currency translation loss for the note
receivable was adjusted through accumulated other comprehensive income and the note receivable was considered paid in full.
The table below summarizes financial information for Grizzly as of December 31, 2011, 2010 and 2009:
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Gross revenue
Loss from continuing operations
Net loss
Bison Drilling and Field Services LLC
2011
$ 21,247,000
$284,361,000
$ 25,984,000
1,780,000
$
$
—
6,605,000
$
6,605,000
$
December 31,
2010
$
3,277,000
$188,786,000
$
3,708,000
$ 81,089,000
—
$
3,234,000
$
3,234,000
$
2009
$
2,064,000
$164,043,000
$
1,585,000
$ 64,365,000
$
—
1,992,000
$
1,991,000
$
During the third quarter of 2011, the Company purchased a 25% ownership interest in Bison Drilling and Field Services LLC (“Bison”)
at a cost of $6,009,000, subject to adjustment. The remaining interests in Bison are
F-16
Table of Contents
Index to Financial Statements
owned by entities controlled by Wexford. Bison owns and operates four drilling rigs. The Company recognized income on equity investment
of $357,000 for the year ended December 31, 2011, which is included in loss from equity method investments in the consolidated statements
of operations.
Muskie Holdings LLC
During the fourth quarter of 2011, the Company purchased a 25% ownership interest in Muskie Holdings LLC (“Muskie”) at a cost of
$2,142,000, subject to adjustment. The remaining interests in Muskie are owned by entities controlled by Wexford. Muskie holds certain
rights in a lease covering land in Wisconsin for mining oil and natural gas fracture grade sand. The loss on equity investment related to Muskie
was immaterial for the year ended December 31, 2011.
6. OTHER ASSETS
Other assets consist of the following as of December 31, 2011 and 2010:
Plugging and abandonment escrow account on the WCBB properties (Note 17)
Certificates of Deposit securing letter of credit
Prepaid drilling costs
Loan commitment fees
Deposits
7.
LONG-TERM DEBT
A break-down of long-term debt as of December 31, 2011 and 2010 is as follows:
Revolving credit agreement (1)
Building loans (2)
Less: current maturities of long term debt
Debt reflected as long term
Maturities of long-term debt as of December 31, 2011 are as follows:
2012
2013
2014
2015
2016
Thereafter
Total
December 31,
2011
$3,121,000
275,000
228,000
1,495,000
4,000
$5,123,000
2010
$3,129,000
275,000
7,000
767,000
4,000
$4,182,000
December 31,
2011
$
—
2,283,000
(141,000)
$2,142,000
2010
$49,500,000
2,417,000
(2,417,000)
$49,500,000
$ 141,000
150,000
159,000
168,000
1,665,000
—
$2,283,000
(1) On September 30, 2010, the Company entered into a $100 million senior secured revolving credit agreement with The Bank of Nova
Scotia, as administrative agent and letter of credit issuer and lead arranger, and Amegy Bank National Association. The revolving credit facility
initially matured on September 30, 2013
F-17
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Index to Financial Statements
and had an initial borrowing base availability of $50.0 million, which was increased to $65.0 million effective December 24, 2010. The
amounts borrowed under the credit agreement were used to repay all of the Company’s outstanding indebtedness under its prior revolving
credit facility ($42.0 million) and term loan ($2.5 million), each with Bank of America, N.A., as administrative agent, and for general corporate
purposes. The credit agreement is secured by substantially all of the Company’s assets. The Company’s wholly-owned subsidiaries
guaranteed the obligations of the Company under the credit agreement.
On May 3, 2011, the Company entered into a first amendment to the revolving credit agreement with The Bank of Nova Scotia, Amegy
Bank, Key Bank National Association (“Key Bank”) and Société Générale. Pursuant to the terms of the first amendment, Key Bank and
Société Générale were added as additional lenders, the maximum amount of the facility was increased to $350.0 million, the borrowing base
was increased to $90.0 million, certain fees and rates payable by the Company under the credit agreement were decreased, and the maturity
date was extended until May 3, 2015. On October 31, 2011, the Company entered into additional amendments to its revolving credit facility
pursuant to which, among other things, the borrowing base under this facility was increased to $125.0 million. As of December 31, 2011, the
Company had no balance outstanding under the credit agreement.
Advances under the credit agreement, as amended, may be in the form of either base rate loans or eurodollar loans. The interest rate for
base rate loans is equal to (1) the applicable rate, which ranges from 1.00% to 2.50%, plus (2) the highest of: (a) the federal funds rate plus
0.5%, (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the eurodollar
rate for an interest period of one month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from
2.00% to 3.50%, plus (2) the London interbank offered rate that appears on Reuters Screen LIBOR01 Page for deposits in U.S. dollars, or, if
such rate is not available, the offered rate on such other page or service that displays the average British Bankers Association Interest
Settlement Rate for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center
banks of whom the agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. At December 14, 2011 (the latest
date during the year ended December 31, 2011 on which the Company had borrowings outstanding), amounts borrowed under the credit
agreement bore interest at the Eurodollar rate (2.26%).
The credit agreement contains customary negative covenants including, but not limited to, restrictions on the Company’s and its
subsidiaries’ ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; make investments; make
fundamental changes; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter
into transactions with their affiliates. The negative covenants are subject to certain exceptions as specified in the credit agreement. The credit
agreement also contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the ratio of funded
debt to EBITDAX (net income, excluding any non-cash revenue or expense associated with swap contracts resulting from ASC 815, plus
without duplication and to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of consolidated
interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for
such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such
period, (d) all other non-cash charges, (e) non-cash losses from minority investments, (f) actual cash distributions received from minority
investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption,
and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and equity offering, and less
non-cash income attributable to equity income from minority investments) for a twelve-month period may not be greater than 2.00 to 1.00; and
(2) 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, 2011.
F-18
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Index to Financial Statements
In conjunction with the repayment of the Bank of America credit facilities on September 30, 2010, the Company expensed approximately
$225,000 in unamortized loan fees associated with the Bank of America revolving credit facility, which is included in interest expense in the
accompanying consolidated statements of operations.
(2) In March 2011, the Company entered into a new building loan agreement for the office building it occupies in Oklahoma City,
Oklahoma. The new loan agreement refinanced the $2.4 million outstanding under the previous building loan agreement. The new agreement
extends the maturity date of the building loan to February 2016 and reduces the interest rate from 6.5% per annum to 5.82% per annum. The
new building loan requires monthly interest and principal payments of approximately $22,000 and is collateralized by the Oklahoma City
office building and associated land.
8.
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 all directors of the Company, all
officers of the Company and 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, 2011. No additional securities will be issued under the Plan other than upon
exercise of options that are outstanding.
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 (i) 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 (ii) 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, 2011, the Company has granted 997,269 options for the purchase of shares of the Company’s common stock under the 2005
Plan.
Sale of Common Stock
On May 19, 2010, the Company sold 1,481,481 shares of its common stock in an underwritten public offering at a public offering price
of $13.50 per share less the underwriting discount. On May 25, 2010, the Company sold an additional 187,022 shares of common stock at the
public offering price less the underwriting discount in connection with the underwriters’ partial exercise of the over-allotment option granted to
them by the
F-19
Table of Contents
Index to Financial Statements
Company. The Company received the aggregate net proceeds of approximately $21.6 million from the sale of these shares after deducting the
underwriting discount and before offering expenses. A portion of the net proceeds from the offering was used to fund the Company’s
Niobrara Formation and Permian Basin acquisitions as discussed in Note 2. The remaining net proceeds from this offering were used for
general corporate purposes, including expenditures associated with the Company’s 2010 drilling programs.
On March 30, 2011, the Company completed the sale of an aggregate of 2,760,000 shares of its common stock in an underwritten public
offering at a public offering price of $32.00 per share less the underwriting discount. The Company received aggregate net proceeds of
approximately $84.3 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The
Company used the net proceeds from the equity offering to fund the Company’s acquisition of leases in the Utica Shale as discussed in Note 2
and for general corporate purposes. Pending the application of the Company’s net proceeds for such purposes, the Company repaid all of its
outstanding indebtedness under its revolving credit agreement.
On July 15, 2011, the Company completed the sale of an aggregate of 3,450,000 shares of its common stock in an underwritten public
offering at a public offering price of $28.75 per share less the underwriting discount. The Company received aggregate net proceeds of
approximately $94.7 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The
Company used a portion of the net proceeds from the equity offering to fund the Company’s acquisition of leases in the Utica Shale as
discussed in Note 2 and for general corporate purposes. Pending the application of the Company’s net proceeds for such purposes, the
Company repaid all of its outstanding indebtedness under its revolving credit agreement.
On December 5, 2011, the Company completed the sale of an aggregate of 4,600,000 shares of its common stock in an underwritten
public offering at a public offering price of $29.00 per share less the underwriting discount. The Company received aggregate net proceeds of
approximately $128.0 million from the sale of these shares after deducting the underwriting discount and before offering expenses. The
Company will continue to use the proceeds to fund capital expenditures associated with drilling, development and infrastructure, principally in
the Utica Shale in Ohio and for general corporate purposes. Pending the application of the Company’s net proceeds for such purposes, the
Company repaid all of its outstanding indebtedness under its revolving credit agreement.
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 (the “Preferred”) and (ii) a warrant to purchase up to 250 shares of common stock, par value $0.01
per share, of the Company (the “Warrants”). 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.
F-20
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Index to Financial Statements
The 2,322,962 Warrants issued have a term of ten years and a current 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 the Warrants and did not consider them
materially significant. The Company had 8,875 Warrants outstanding at December 31, 2011 which can be converted into 29,832 shares of
common stock.
9.
STOCK-BASED COMPENSATION
During the years ended December 31, 2011, 2010 and 2009, the Company’s stock-based compensation cost was $1,287,000, $492,000
and $529,000, respectively, of which the Company capitalized $515,000, $197,000 and $212,000, respectively, relating to its exploration and
development efforts.
The fair value of each option award is estimated on the date of grant using the Black-Scholes option valuation model. 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 years ended December 31, 2011, 2010 and 2009.
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, 2011, 2010 and 2009 are presented
below:
Options outstanding at December 31, 2008
Granted
Exercised
Forfeited/expired
Options outstanding at December 31, 2009
Granted
Exercised
Forfeited/expired
Options outstanding at December 31, 2010
Granted
Exercised
Forfeited/expired
Options outstanding at December 31, 2011
Options exercisable at December 31, 2011
Weighted
Average
Exercise Price
per Share
$
$
$
7.01
—
2.20
—
7.14
—
6.46
2.00
7.23
—
9.74
—
6.51
6.51
Weighted
Average
Remaining
Contractual Term
6.24
Aggregate
Intrinsic
Value
$(1,599,000)
71,000
5.38
$ 2,192,000
545,000
4.48
$ 6,621,000
2,308,000
3.41
3.41
$ 8,172,000
$ 8,172,000
Shares
522,380
—
(13,750)
—
508,630
—
(48,889)
(1,500)
458,241
—
(102,000)
—
356,241
356,241
F-21
Table of Contents
Index to Financial Statements
Unrecognized compensation expense as of December 31, 2011 related to outstanding stock options and restricted shares was
$4,819,000. The expense is expected to be recognized over a weighted average period of 2.10 years.
The following table summarizes information about the stock options outstanding at December 31, 2011:
Exercise
Price
$3.36
$9.07
$11.20
Number
Outstanding
206,241
25,000
125,000
356,241
Weighted Average
Remaining Life
(in years)
3.06
3.69
3.92
Number
Exercisable
206,241
25,000
125,000
356,241
The following table summarizes restricted stock activity for the twelve months ended December 31, 2011, 2010 and 2009:
Unvested shares as of December 31, 2008
Granted
Vested
Forfeited
Unvested shares as of December 31, 2009
Granted
Vested
Forfeited
Unvested shares as of December 31, 2010
Granted
Vested
Forfeited
Unvested shares as of December 31, 2011
10.
INSURANCE PROCEEDS
Number of
Unvested
Restricted Shares
93,456
13,332
(43,458)
(3,086)
60,244
111,667
(58,525)
—
113,386
153,332
(63,370)
—
203,348
Weighted
Average
Grant Date
Fair Value
7.04
$
8.08
8.16
15.77
$
6.01
$ 12.94
8.17
—
$ 11.72
$ 31.15
12.87
—
$ 26.02
In March 2009, the Company received insurance proceeds of approximately $1,050,000 related to damages incurred in its WCBB field
as a result of Hurricane Ike in 2008. The costs associated with repairing the field were expensed to lease operating expenses as incurred in
2008 and 2009. The Company recognized the insurance proceeds in other (income) expense in the accompanying consolidated statements of
operations. In September and October 2009, the Company received additional insurance proceeds of approximately $994,000 related to
damages incurred in the WCBB field as a result of Hurricane Ike and related debris removal. As the costs related to these repairs and debris
removal were incurred in 2009 and expensed to lease operating expense, the Company recognized the insurance proceeds in lease operating
expenses in the accompanying consolidated statements of operations.
11. 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.
F-22
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Index to Financial Statements
The fair value of the derivative instruments is 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.
12.
INCOME TAXES
The income tax provision consists of the following:
Current:
State
Federal
Deferred:
State
Federal
Total income tax expense (benefit) provision
2011
2010
2009
$
—
282,000
$ 40,000
95,000
$ 28,000
32,000
—
(372,000)
$ (90,000)
—
(95,000)
$ 40,000
—
(32,000)
$ 28,000
A reconciliation of the statutory federal income tax amount to the recorded expense follows:
Income before federal income taxes
Expected income tax at statutory rate
State income taxes
Other differences
Changes in valuation allowance
Income tax expense (benefit) recorded
2011
$ 108,332,000
37,916,000
4,227,000
(146,000)
(42,087,000)
(90,000)
$
2010
$ 47,403,000
16,591,000
2,378,000
(111,000)
(18,818,000)
40,000
$
2009
$23,655,000
8,279,000
1,370,000
(891,000)
(8,730,000)
28,000
$
The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at
December 31, 2011, 2010 and 2009 are estimated as follows:
Deferred tax assets:
Net operating loss carryforward
Oil and gas property basis difference
FASB ASC 718 compensation expense
Investment in pass through entities
AMT credit
Non-oil and gas property basis difference
Charitable contributions carryover
State net operating loss carryover
Total deferred tax assets
Deferred tax liabilities:
Oil and gas property basis difference
Investment in pass through entities
Unrealized gain on hedging activities
Total deferred tax liabilities
Total deferred tax asset
Valuation allowance
Net deferred tax asset
2011
2010
2009
$ 40,880,000
—
520,000
78,000
1,000,000
103,000
3,000
6,410,000
48,994,000
35,637,000
—
10,000
35,647,000
13,347,000
(12,347,000)
$ 1,000,000
$ 20,967,000
32,054,000
347,000
722,000
693,000
279,000
—
—
55,062,000
—
—
—
—
55,062,000
(54,434,000)
628,000
$
$ 22,268,000
49,638,000
341,000
528,000
598,000
316,000
—
—
73,689,000
—
—
—
—
73,689,000
(73,156,000)
533,000
$
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Index to Financial Statements
The Company has an available tax net operating loss carryforward estimated at approximately $116,800,000 as of December 31, 2011.
This carryforward will begin to expire in the year 2013. A valuation allowance has been provided at December 31, 2011, 2010 and 2009
because it is management’s belief, based upon the Company’s past history of no taxable income and future projections of no taxable income
during the carryforward period, it is more likely than not the net deferred tax assets will not be realized.
The Company had income tax expense of $40,000 related to state income tax for the year ended December 31, 2010.
13. EARNINGS PER SHARE
A reconciliation of the components of basic and diluted net income per common share is presented in the table below:
Basic:
Net income
Effect of dilutive securities:
Stock options and awards
Diluted:
Net income
2011
2010
2009
Per
Per
Income
Shares
Share
Income
Shares
Share
Income
Shares
Per
Share
$108,422,000 48,754,840 $2.22 $47,363,000 43,863,190 $1.08 $23,627,000 42,667,581 $0.55
—
452,123
—
392,902
—
350,067
$108,422,000 49,206,963 $2.20 $47,363,000 44,256,092 $1.07 $23,627,000 43,017,648 $0.55
For the year ended December 31, 2009, options to purchase 64,889 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 because they were anti-dilutive. There were no potential shares of common
stock that were considered anti-dilutive for the years ended December 31, 2011 and 2010.
14. HEDGING ACTIVITIES
Oil Price Hedging Activities
The Company seeks to reduce its exposure to unfavorable changes in oil prices, which are subject to significant and often volatile
fluctuation, by entering into fixed price swaps and forward sales contracts. 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.
The Company accounts for its oil derivative instruments as cash flow hedges for accounting purposes under FASB ASC 815 and related
pronouncements. All derivative contracts are marked to market each quarter end and are included in the accompanying consolidated balance
sheets as derivative assets and liabilities.
During the fourth quarter of 2010, the Company entered into fixed price swap contracts for 2011 with the purchaser of the Company’s
WCBB oil and with a financial institution. The Company’s 2011 fixed price swap contracts were tied to the 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”). During the third quarter of 2011, the Company entered into
fixed price swap contracts for 2012 with the purchaser of the Company’s WCBB oil. The Company’s 2012 fixed price swap contracts are tied
to the commodity prices on the International Petroleum Exchange (“IPE”).
F-24
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Index to Financial Statements
For the Company’s 2012 fixed price swap contracts, the Company will receive the fixed price amount stated in the contract and pay to its
counterparty the current market price for oil as listed on the IPE for Brent Crude. At December 31, 2011, the Company had the following
fixed price swaps in place:
January – December 2012
Daily Volume
(Bbls/day)
2,000
Weighted
Average Price
108.00
$
At December 31, 2011 the fair value of derivative assets related to the fixed price swaps was as follows:
Short-term derivative instruments – asset
At December 31, 2010, the fair value of derivative liabilities related to the fixed price swaps was as follows:
Short-term derivative instruments – liabilities
$1,601,000
$4,720,000
All fixed price swaps and forward sales contracts have been executed in connection with the Company’s oil price hedging program. For
fixed price swaps qualifying as cash flow hedges pursuant to FASB ASC 815, the realized contract price is included in oil sales in the period
for which the underlying production was hedged.
For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are
recognized in accumulated other comprehensive income until the hedged item is recognized in earnings. Amounts reclassified out of
accumulated other comprehensive income into earnings as a component of oil and condensate sales for the years ended December 31, 2011
and 2010 are presented below.
(Reduction) addition to oil and condensate sales
Year ended December 31,
2011
$(4,720,000)
2010
$(18,736,000)
The Company expects to reclassify $1,576,000 out of accumulated other comprehensive income into earnings as a component of oil and
condensate sales during the year ended December 31, 2012 related to fixed price swaps.
The following table presents the balances of the Company’s cumulative hedging activities included in other comprehensive income.
December 31, 2008
December 31, 2009
December 31, 2010
December 31, 2011
$
—
$(18,736,000)
$ (4,720,000)
$ 1,576,000
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
recognized a gain of $25,000 related to hedge ineffectiveness for the year ended December 31, 2011, which is included in oil and condensate
sales in the consolidated statements of operations. The Company did not recognize into earnings any amount related to hedge ineffectiveness
for the years ended December 31, 2010 and 2009.
In 2009, the Company was party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted
average daily price of $55.17 per barrel, before transportation costs and differentials, for the period April 2009 to August 2009. The Company
also was party to forward sales contracts
F-25
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Index to Financial Statements
for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs
and differentials, for the period September 2009 to December 2009. For the period January 2010 through February 2010, the Company was
party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per
barrel, before transportation costs and differentials. For the period March 2010 through December 2010, the Company was party to forward
sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel, before
transportation costs and differentials.
In the first quarter of 2009, the Company terminated forward sales contracts for 3,000 barrels per day of March 2009 production for
approximately $1.5 million and terminated forward sales contracts for 3,000 barrels per day in the second quarter of 2009 for $476,000. For
the year ended December 31, 2009, approximately $2.0 million related to such terminations is included in oil and condensate sales on the
accompanying consolidated statements of operations.
The Company delivered approximately 31% of its 2011 production under fixed price swaps.
15. FAIR VALUE MEASUREMENTS
The Company adopted FASB ASC 820 for all financial assets and liabilities measured at fair value on a recurring basis. The Company
adopted FASB ASC 820 effective January 1, 2009 for all non-financial assets and liabilities. FASB ASC 820 defines fair value as the price
that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the
measurement date. The statement establishes market or observable inputs as the preferred sources of values, followed by assumptions based
on hypothetical transactions in the absence of market inputs. The statement requires fair value measurements be classified and disclosed in one
of the following categories:
Level 1 – Quoted prices in active markets for identical assets and liabilities.
Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that
are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.
Level 3 – Significant inputs to the valuation model are unobservable.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
The following tables summarize the Company’s financial and nonfinancial liabilities by FASB ASC 820 valuation level as of
December 31, 2011 and 2010:
Assets:
Fixed price swaps
Liabilities:
Fixed price swaps
Assets:
Fixed price swaps
Liabilities:
Fixed price swaps
Level 1
As of December 31, 2011
Level 2
Level 3
$ —
$1,601,000
$ —
$ —
$
—
$ —
Level 1
As of December 31, 2010
Level 2
Level 3
$ —
$
—
$ —
$ —
$4,720,000
$ —
The estimated fair value of the Company’s fixed price swap contracts was based upon forward commodity prices based on quoted
market prices, adjusted for differentials.
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Index to Financial Statements
The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “Asset Retirement and
Environmental Obligations” (“FASB ASC 410”). The initial measurement of asset retirement obligations at fair value is calculated using
discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the
unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability
is deemed to use Level 3 inputs. See Note 4 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations
incurred during the twelve months ended December 31, 2011 were approximately $1,390,000.
16. RELATED PARTY TRANSACTIONS
In the ordinary course of business, the Company conducts business activities with certain entities affiliated with its largest stockholder.
Windsor Permian, LLC (“Windsor”), an entity controlled by Wexford, operates the Permian Basin wells in West Texas. At
December 31, 2011 and 2010, the Company owed Windsor approximately $5,593,000 and $5,871,000, respectively, related to reimbursement
for services provided. Approximately $5,489,000 and $2,386,000 of services provided by Windsor are included in lease operating expenses in
the consolidated statements of operations for the years ended December 31, 2011 and 2010, respectively. Approximately $50,614,000 and
$21,666,000 related to services performed by Windsor are included in oil and natural gas properties on the accompanying consolidated balance
sheets at December 31, 2011 and 2010, respectively.
Athena Construction LLC (“Athena”), an entity controlled by Wexford, performs services for the Company at its WCBB and Hackberry
fields. At December 31, 2011 and December 31, 2010, the Company owed Athena approximately $676,000 and $791,000, respectively,
related to these services. Approximately $423,000 and $438,000 of services provided by Athena are included in lease operating expenses in
the consolidated statements of operations for the years ended December 31, 2011 and 2010, respectively. Approximately $2,851,000 and
$2,554,000 related to services performed by Athena are included in oil and natural gas properties on the accompanying consolidated balance
sheets at December 31, 2011 and 2010, respectively.
Great White Directional Services LLC (“Directional”) performs services for the Company at its WCBB and Hackberry fields. At
December 31, 2011 and December 31, 2010, the Company owed Directional approximately $2,449,000 and $952,000, respectively, related to
these services. Approximately $6,068,000 and $3,008,000 relating to services performed by Directional are included in oil and natural gas
properties on the accompanying consolidated balance sheets at December 31, 2011 and 2010, respectively. Directional was controlled by
Wexford until it was sold to an unrelated third party in August 2011.
Great White Pressure Control (“Pressure Control”) performs services for the Company at its WCBB field. At December 31, 2010, the
Company owed Pressure Control approximately $80,000 related to these services. Approximately $80,000 of services performed by Pressure
Control are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2010. No services
were performed by Pressure Control in 2011. Pressure Control was controlled by Wexford until it was sold to an unrelated third party in
August 2011.
Black Fin P&A, LLC (“Black Fin”), an entity controlled by Wexford, performs services for the Company at its WCBB field. At
December 31, 2011, the Company owed Black Fin $436,000 related to these services. No amounts were owed to Black Fin at December 31,
2010. Approximately $436,000 and $826,000 of services performed by Black Fin are included in oil and natural gas properties on the
accompanying consolidated balance sheets at December 31, 2011 and 2010, respectively.
F-27
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Index to Financial Statements
17. 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 could access
the trust for use in plugging and abandonment charges associated with the property, although it has not yet done so. As of December 31,
2011, the plugging and abandonment trust totaled approximately $3,121,000. At December 31, 2011, the Company has plugged 320 wells at
WCBB since it began its plugging program in 1997, which management believes fulfills its current minimum plugging obligation.
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, 2011, 2010 and 2009, Gulfport incurred $310,000, $316,000 and $279,000, 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, subject to adjustment for cost of living increases.
The Company has entered into an oral agreement the Company’s Chief Executive Officer, with respect to his compensation and benefits,
pursuant to which he is entitled to an annual salary of $200,000 and, at the discretion of the Company’s board of directors, an annual cash
incentive bonus. The compensation committee of the Board of Directors may make upward adjustments to this salary.
18. CONTINGENCIES
The Louisiana Department of Revenue (“LDR”) is disputing Gulfport’s severance tax payments to the State of Louisiana from the sale
of oil under fixed price contracts during the years 2005 to 2007. The LDR maintains that Gulfport paid approximately $1,800,000 less in
severance taxes under fixed price terms than the severance taxes Gulfport would have had to pay had it paid severance taxes on the oil at the
contracted market rates only. Gulfport has denied any liability to the LDR for underpayment of severance taxes and has maintained that it was
entitled to enter into the fixed price contracts with unrelated third parties and pay severance taxes based upon the proceeds received under those
contracts. Gulfport has maintained its right to contest any final assessment or suit
F-28
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Index to Financial Statements
for collection if brought by the State. On April 20, 2009, the LDR filed a lawsuit in the 15 Judicial District Court, Lafayette Parish, in
Louisiana against Gulfport seeking $2,275,729 in severance taxes, plus interest and court costs. Gulfport filed a response denying any liability
to the LDR for underpayment of severance taxes and is defending itself in the lawsuit. The LDR had taken no further action on this lawsuit
since filing its petition two years ago until recently when it propounded discovery requests to which Gulfport has responded. Gulfport recently
served discovery requests on the LDR and is awaiting the LDR’s response.
th
In December 2010, the LDR filed two identical lawsuits against Gulfport in different venues to recover allegedly underpaid severance
taxes on crude oil for the period January 1, 2007 through December 31, 2010, together with a claim for attorney’s fees. The petitions do not
make any specific claim for damages or unpaid taxes. As with the first lawsuit filed by the LDR in 2009, Gulfport denies all liability and will
vigorously defend the lawsuit. The cases are in the early stages, and Gulfport has not yet filed a response to the recent lawsuits. Recently, the
LDR filed motions to stay the lawsuits before Gulfport filed any responsive pleadings. The LDR has advised Gulfport that it intends to pursue
settlement discussions with Gulfport and other similarly situated defendants in separate proceedings.
Other Litigation
In November 2006, Cudd Pressure Control, Inc. (“Cudd”) filed a lawsuit against Gulfport, Great White Pressure Control LLC (“Great
White”) and six former Cudd employees 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 alleged RICO violations and several other
causes of action relating to Great White’s employment of the former Cudd employees and sought unspecified monetary damages and
injunctive relief. On stipulation by the parties, the plaintiff’s RICO claim was dismissed without prejudice by order of the court on
February 14, 2007. Gulfport filed a motion for summary judgment on October 5, 2007. The court entered a final interlocutory judgment in
favor of all defendants, including Gulfport, on April 8, 2008. On November 3, 2008, Cudd filed its appeal with the U.S. Court of Appeals for
the Fifth Circuit. The Fifth Circuit vacated the district court decision finding, among other things, that the district court should not have entered
summary judgment without first allowing more discovery. The case was remanded to the district court, and Cudd filed a motion to remand the
case to the original state court, which motion was granted. On February 3, 2010, Cudd filed its second amended petition with the state court
(a) alleging that Gulfport conspired with the other defendants to misappropriate, and misappropriated Cudd’s trade secrets and caused its
employees to breach their fiduciary duties, and (b) seeking unspecified monetary damages. On April 13, 2010, Gulfport’s motion to be
dismissed from the proceeding for lack of personal jurisdiction was denied. This state court proceeding is in its initial stages. In 2011, the
parties have continued with written discovery and production of documents. On February 15, 2011, Cudd filed a third amended petition
seeking $26.5 million (based on a report prepared by its expert) plus disgorgement of $6 million in payments by Great White to the individual
defendants and punitive damages. Gulfport denies these claims with respect to itself. Recently, the parties began the process of scheduling and
taking additional depositions and it is anticipated that the case will remain in the discovery phase for at least the next several months.
On July 30, 2010, six individuals and one limited liability company sued 15 oil and gas companies in Cameron Parish Louisiana for
contamination across the surface of where the defendants operated in an action entitled Reeds et al. v. BP American Production Company et
al., 38th Judicial District. No. 10-18714. The plaintiffs’ original petition for damages, which did not name Gulfport as a defendant, alleges that
the plaintiffs’ property located in Cameron Parish, Louisiana within the Hackberry oil field is contaminated as a result of historic oil and gas
exploration and production activities. Plaintiffs allege that the defendants conducted, directed and participated in various oil and gas exploration
and production activities on their property which allegedly have contaminated or otherwise caused damage to the property, and have sued the
defendants for alleged breaches of oil, gas and mineral leases, as well as for alleged negligence, trespass, failure to warn, strict liability,
punitive damages, lease liability, contract liability, unjust enrichment, restoration damages, assessment and response costs and stigma
damages. On December 7, 2010, Gulfport was served with a copy of the plaintiffs’
F-29
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Index to Financial Statements
first supplemental and amending petition which added four additional plaintiffs and six additional defendants, including Gulfport, bringing the
total number of defendants to 21. It also increased the total acreage at issue in this litigation from 240 acres to approximately 1,700 acres. In
addition to the damages sought in the original petition, the plaintiffs now also seek: damages sufficient to cover the cost of conducting a
comprehensive environmental assessment of all present and yet unidentified pollution and contamination of their property; the cost to restore
the property to its pre-polluted original condition; damages for mental anguish and annoyance, discomfort and inconvenience caused by the
nuisance created by defendants; land loss and subsidence damages and the cost of backfilling canals and other excavations; damages for loss
of use of land and lost profits and income; attorney fees and expenses and damages for evaluation and remediation of any contamination that
threatens groundwater. In addition to Gulfport, current defendants include ExxonMobil Oil Corporation, Mobil Exploration & Producing
North America Inc., Chevron U.S.A. Inc., The Superior Oil Company, Union Oil Company of California, BP America Production Company,
Tempest Oil Company, Inc., ConocoPhillips Company, Continental Oil Company, WM. T. Burton Industries, Inc., Freeport Sulphur
Company, Eagle Petroleum Company, U.S. Oil of Louisiana, M&S Oil Company, and Empire Land Corporation, Inc. of Delaware. On
January 21, 2011, Gulfport filed a pleading challenging the legal sufficiency of the petitions on several grounds and requesting that they either
be dismissed or that plaintiffs be required to amend such petitions. In response to the pleadings filed by Gulfport and similar pleadings filed by
other defendants, the plaintiffs filed a third amending petition with exhibits which expands the description of the property at issue, attaches
numerous aerial photos and identifies the mineral leases at issue. In response, Gulfport and numerous defendants re-urged their pleadings
challenging the legal sufficiency of the petitions. Some of the defendants’ grounds for challenging the plaintiffs’ petitions were heard by the
court on May 25, 2011 and were denied. The court signed the written judgment on December 9, 2011. Gulfport noticed its intent to seek
supervisory review on December 19, 2011 and the trial court fixed a return date of January 11, 2012 for the filing of the writ application.
Gulfport filed its supervisory writ and the matter is currently pending before the Louisiana Third Circuit Court of Appeal. Gulfport has served
discovery requests and is currently responding to discovery requests from the plaintiffs. It is anticipated that the discovery phase of this case
will become more active in the upcoming months.
Due to the current early stages of the LDR, Cudd and Reed 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 $250,000. At December 31, 2011, Gulfport held cash in excess of insured limits in these banks totaling $93,397,000.
During the year ended December 31, 2011, Gulfport sold approximately 93% and 7% of its oil production to Shell Trading Company
(“Shell”) and Windsor, respectively, 100% of its natural gas liquids production to Windsor, and 50%, 27% and 22% of its natural gas
production to Hilcorp Energy Company (“Hilcorp”), Chevron and Windsor, respectively. During the year ended December 31, 2010, Gulfport
sold approximately 75% and 19% of its oil production to Shell and Windsor, respectively, and 50%, 32%, and 10% of its natural gas
F-30
Table of Contents
Index to Financial Statements
production to Windsor, Chevron, and Hilcorp, respectively. During the year ended December 31, 2009, Gulfport sold approximately 92% and
7% of its oil production to Shell and Windsor, respectively, 100% of its natural gas liquids production to Windsor, and 45%, 38%, and 16%
of its natural gas production to Windsor, Chevron, and Hilcorp, respectively.
19. 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.
In December 2009, the Company received a final distribution from the Litigation Trust of approximately $234,000. No proceeds were
received from the Litigation Trust for the years ended December 31, 2011 or 2010.
20. 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 United
States:
Capitalized Costs Related to Oil and Gas Producing Activities
Proven properties
Unproven properties
Accumulated depreciation, depletion, amortization and impairment reserve
Net capitalized costs
F-31
2011
$ 897,130,000
132,912,000
1,030,042,000
(571,213,000)
$ 458,829,000
2010
$ 730,566,000
11,756,000
742,322,000
(509,248,000)
$ 233,074,000
Table of Contents
Index to Financial Statements
Costs Incurred in Oil and Gas Property Acquisition and Development Activities
Acquisition
Development of proved undeveloped properties
Exploratory
Recompletions
Capitalized asset retirement obligation
Total
Results of Operations for Producing Activities
2011
$119,522,000
123,489,000
3,994,000
17,259,000
1,390,000
$265,654,000
2010
$ 17,627,000
64,652,000
—
16,917,000
1,328,000
$100,524,000
2009
$ 1,885,000
28,652,000
502,000
8,980,000
361,000
$40,380,000
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
Income tax expense (benefit)
Current
Deferred
Results of operations from producing activities
Depletion per barrel of oil equivalent (BOE)
2011
$228,953,000
(47,230,000)
(61,965,000)
119,758,000
2010
$127,636,000
(31,580,000)
(38,600,000)
57,456,000
2009
$ 85,576,000
(26,113,000)
(28,939,000)
30,524,000
282,000
(372,000)
(90,000)
$119,848,000
26.56
$
40,000
—
40,000
$ 57,416,000
19.54
$
28,000
—
28,000
$ 30,496,000
17.25
$
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Index to Financial Statements
Oil and Gas Reserves (Unaudited)
The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2011,
2010 and 2009 and changes in proved reserves during the last three years. The reserve reports use an average price equal to the unweighted
arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended
December 31, 2011, 2010 and 2009, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2009.
Volumes for oil are stated in thousands of barrels (MBbls) and volumes for gas are stated in millions of cubic feet (MMcf). The prices used
for the 2011 reserve report are $96.19 per barrel and $4.12 per MMbtu, adjusted by lease for transportation fees and regional price
differentials, and for oil and gas reserves, respectively. The prices used at December 31, 2010 and 2009 for reserve report purposes are $76.16
per barrel and $4.38 per MMbtu and $57.90 per barrel and $3.87 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.
Proved Reserves
Beginning of the period
Purchases in oil and gas reserves in place
Extensions and discoveries
Sales of oil and gas reserves in place
Revisions of prior reserve estimates
Current production
End of period
Proved developed reserves
Proved undeveloped reserves
2011
2010
2009
Oil
Gas
Oil
Gas
Oil
Gas
19,704
2
3,940
—
(4,714)
(2,187)
16,745
7,485
9,260
16,158
19
2,091
—
(1,662)
(878)
15,728
6,152
9,576
17,488
3,913
5,574
—
(5,426)
(1,845)
19,704
7,230
12,474
14,332
3,482
5,303
—
(6,171)
(788)
16,158
6,068
10,090
21,771
1,728
2,614
(736)
(6,294)
(1,595)
17,488
6,165
11,323
22,235
1,135
2,874
(282)
(11,139)
(491)
14,332
4,325
10,007
The Company experienced downward reserve revisions in estimated proved reserves in 2011. These downward revisions were primarily
the result of the drilling of PUDs during the Company’s 2011 drilling program and ethane takeaway issues in the Permian Basin. The
Company experienced downward reserve revisions in estimated proved reserves in 2010. These downward revisions were primarily the result
of the five-year schedule for proved undeveloped reserves from the SEC’s “Modernization of Oil and Gas Reporting” Final Rule. The
Company experienced downward reserve revisions in estimated proved reserves in 2009. These downward revisions were primarily the result
of implementing the five-year schedule for proved undeveloped reserves from the SEC’s “Modernization of Oil and Gas Reporting” Final
Rule.
Discounted Future Net Cash Flows (Unaudited)
The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of
December 31, 2011, 2010 and 2009 using an unweighted average first-of-the-month price for the period January through December for 2011,
2010 and 2009.
F-33
Table of Contents
Index to Financial Statements
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)
Future cash flows
Future development and abandonment costs
Future production costs
Future production taxes
Future income taxes
Future net cash flows
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows
2011
$1,594,050,000
(306,810,000)
(295,383,000)
(124,739,000)
(229,649,000)
637,469,000
(260,788,000)
$ 376,681,000
Year ended December 31,
2010
$1,479,295,000
(301,651,000)
(305,814,000)
(136,323,000)
(159,171,000)
576,336,000
(260,849,000)
$ 315,487,000
2009
$1,005,029,000
(209,975,000)
(236,003,000)
(97,841,000)
(50,229,000)
410,981,000
(170,207,000)
$ 240,774,000
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 $52,855,000, $49,897,000 and $55,364,000 during years 2012, 2013 and 2014, respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)
Sales and transfers of oil and gas produced, net of production costs
Net changes in prices, production costs, and development costs
Acquisition of oil and gas reserves in place
Extensions and discoveries
Revisions of previous quantity estimates, less related production costs
Sales of reserves in place
Accretion of discount
Net changes in income taxes
Change in production rates and other
Total change in standardized measure of discounted future net cash flows
F-34
2011
$(181,723,000)
136,071,000
72,000
107,110,000
(112,553,000)
—
31,549,000
(36,674,000)
117,342,000
$ 61,194,000
Year ended December 31,
2010
$ (96,056,000)
122,147,000
63,043,000
88,227,000
(89,155,000)
—
24,077,000
(54,879,000)
17,309,000
$ 74,713,000
2009
$ (59,463,000)
183,426,000
20,981,000
32,638,000
(77,531,000)
(13,185,000)
12,624,000
(22,238,000)
37,282,000
$114,534,000
Table of Contents
Index to Financial Statements
21. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table summarizes quarterly financial data for the years ended December 31, 2011 and 2010:
Revenues
Income from operations
Income tax expense (benefit)
Net income
Income per share:
Basic
Diluted
Revenues
Income from operations
Income tax expense
Net income
Income per share:
Basic
Diluted
22. SUBSEQUENT EVENTS
2011
First
Quarter
$46,638,000
22,105,000
—
21,174,000
Second
Quarter
$55,589,000
28,156,000
1,000
27,265,000
Third
Quarter
$58,081,000
29,118,000
—
29,009,000
Fourth
Quarter
$68,946,000
31,585,000
(91,000)
30,974,000
$
$
0.47
0.47
$
$
0.57
0.57
$
$
0.58
0.57
$
$
0.59
0.59
2010
First
Quarter
$27,355,000
10,526,000
—
9,981,000
Second
Quarter
$28,875,000
11,004,000
40,000
10,389,000
Third
Quarter
$33,181,000
13,468,000
—
12,678,000
Fourth
Quarter
$37,533,000
14,779,000
—
14,315,000
$
$
0.23
0.23
$
$
0.24
0.24
$
$
0.28
0.28
$
$
0.32
0.32
In January 2012, Grizzly entered into an agreement to purchase approximately 46,700 acres of oil sands leases in the Athabasca oil
sands area for $225.0 million CAD. Gulfport’s share of the purchase price is approximately $56.3 million and will be due at closing of the
transaction. Grizzly intends to develop the area using SAGD recovery technology.
On February 13, 2012, Gulfport entered into fixed price swaps for 1,000 barrels of oil per day at a weighted average price of $ 113.20
per barrel for the period of March 2012 through June 2013. The Company will receive the fixed price amount stated in the contract and pay to
its counterparty the current market price for oil as listed on the IPE for Brent Crude.
F-35
Table of Contents
Index to Financial Statements
Exhibit
Number
2.1
2.2
3.1
3.2
3.3
4.1
4.2
4.3
4.4
4.5
10.1+
10.2+
10.3+
10.4+
EXHIBIT INDEX
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).
Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q,
File No. 000-19514, filed by the Company with the SEC on November 6, 2009).
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).
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).
Employment Agreement, dated as of May 18, 1999 and effective as of June 1, 1999, by and between the Company 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).
E-1
Table of Contents
Index to Financial Statements
Exhibit
Number
10.5+
10.6
10.7
10.8
10.9
10.10
14
21*
23.1*
23.2*
23.3*
23.4*
31.1*
31.2*
32.1*
Description
Summary of Oral Employment Agreement with James D. Palm (incorporated by reference to Exhibit 10.1 to Form 8-K, File
No. 000-19514, filed by the Company with the SEC on December 7, 2010).
Credit Agreement, dated as of September 30, 2010, by and among the Company, as borrower, the Bank of Nova Scotia, as
administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association (incorporated by reference
to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 6, 2010).
Amendment, dated as of December 24, 2010, to the Credit Agreement by and among the Company, as borrower, the Bank of
Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association
(incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on
December 28, 2010).
First Amendment, dated May 3, 2011 of Credit Agreement, dated September 30, 2011, by and among the Company, as
borrower, the Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National
Association, KeyBank National Association and Société Générale (incorporated by reference to Exhibit 10.2 of Form 10-Q,
File No. 000-19514, filed by the Company with the SEC on May 9, 2011).
Second Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank
of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, as
syndication agent, KeyBank National Association, as co-documentation agent, and the other lenders party thereto (incorporated
by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 4, 2011).
Third Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank of
Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, as
syndication agent, KeyBank National Association and Société Générale, as co-documentation agents, and the other lenders
party thereto (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the
SEC on November 4, 2011).
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 Ryder Scott Company.
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.
E-2
Table of Contents
Index to Financial Statements
Exhibit
Number
32.2*
99.1*
99.2*
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.
Description
Report of Netherland, Sewell & Associates, Inc.
Report of Ryder Scott Company.
101.INS**
XBRL Instance Document.
101.SCH**
XBRL Taxonomy Extension Schema Document.
101.CAL**
XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF**
XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB**
XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE**
XBRL Taxonomy Extension Presentation Linkbase Document.
Filed herewith.
Furnished herewith, not filed.
*
**
+ Management contract, compensatory plan or arrangement.
E-3
SUBSIDIARIES OF GULFPORT ENERGY CORPORATION
Exhibit 21
Name of Subsidiary
Grizzly Holdings, Inc.
Jaguar Resources LLC
Puma Resources, Inc.
Gator Marine, Inc.
Gator Marine Ivanhoe, Inc.
Jurisdiction of Organization
Delaware
Delaware
Delaware
Delaware
Delaware
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We have issued our reports dated February 27, 2012, with respect to the consolidated financial statements and internal control over financial
reporting included in the Annual Report of Gulfport Energy Corporation on Form 10-K for the year ended December 31, 2011. We hereby
consent to the incorporation by reference of said reports in the Registration Statements of Gulfport Energy Corporation on Forms S-8 (File
No. 333-135728, effective July 12, 2006; File No. 333-129178, effective October 21, 2005; and File No. 333-55738, effective February 16,
2001), on Form S-3 (File No. 333-168180, effective July 28, 2010) and on Form S-3ASR (File No. 333-175435, automatically effective
July 11, 2011).
Exhibit 23.1
/s/ GRANT THORNTON LLP
Oklahoma City, OK
February 27, 2012
Exhibit 23.2
CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC.
We hereby consent to the inclusion in the Form 10-K of Gulfport Energy Corporation (“Form 10-K”), of our report dated January 20, 2012,
on oil and gas reserves of Gulfport Energy Corporation and its subsidiaries as of December 31, 2011, to all references to our firm in the Form
10-K and to the incorporation by reference of said report in the Registration Statements of Gulfport Energy Corporation on Forms S-8 (File
No. 333-135728, effective July 12, 2006; File No. 333-129178, effective October 21, 2005; and File No. 333-55738, effective February 16,
2001), on Form S-3 (File No. 333-168180, effective July 28, 2010) and on Form S-3ASR (File No. 333-175435, automatically effective
July 11, 2011).
NETHERLAND, SEWELL &
ASSOCIATES, INC.
By: /s/ J. CARTER HENSON, JR.
J. Carter Henson, Jr., P.E.
Senior Vice President
Houston, Texas
February 27, 2012
CONSENT OF RYDER SCOTT COMPANY, LP
We have issued our report dated January 13, 2012 for the year ended December 31, 2011 on estimates of proved reserves and future net cash
flows of certain oil and natural gas properties located in the Permian Basin of West Texas acquired by Gulfport Energy Corporation
(“Gulfport”). As independent oil and gas consultants, we hereby consent to the inclusion of our report and the information contained therein in
this Annual Report on Form 10-K of Gulfport (this “Annual Report”) and to all references to our firm in this Annual Report. We hereby also
consent to the incorporation by reference of such report and the information contained therein in the Registration Statements of Gulfport on
Forms S-8 (File No. 333-135728, effective July 12, 2006; File No. 333-129178, effective October 21, 2005; and File No. 333-55738,
effective February 16, 2001), on Form S-3 (File No. 333-168180, effective July 28, 2010) and on Form S-3ASR (File No. 333-175435,
automatically effective July 11, 2011).
Exhibit 23.3
RYDER SCOTT COMPANY, LP
/s/ RYDER SCOTT COMPANY, LP
RYDER SCOTT COMPANY, LP
TBPE Firm Registration No. F-1580
February 27, 2012
Oklahoma City, Oklahoma
CONSENT OF PINNACLE ENERGY SERVICES, LLC
We have issued our report letters dated January 26, 2011 for 2010 and February 9, 2010 for 2009, on estimates of proved reserves and future
net cash flows of certain oil and natural gas properties located in the Permian Basin of West Texas acquired by Gulfport Energy Corporation
(“Gulfport”). As independent oil and gas consultants, we hereby consent to the inclusion of the information contained in our report letters in
this Annual Report on Form 10-K of Gulfport (this “Annual Report”) and to all references to our firm in this Annual Report. We hereby also
consent to the incorporation by reference of such information in the Registration Statements of Gulfport on Forms S-8 (File No. 333-135728,
effective July 12, 2006; File No. 333-129178, effective October 21, 2005; and File No. 333-55738, effective February 16, 2001), on Form S-
3 (File No. 333-168180, effective July 28, 2010) and on Form S-3ASR (File No. 333-175435, automatically effective July 11, 2011).
Exhibit 23.4
PINNACLE ENERGY SERVICES, LLC
/s/ JOHN PAUL DICK
Name: John Paul Dick
Title:
Manager, Registered Petroleum
Engineer
February 27, 2012
Oklahoma City, Oklahoma
CERTIFICATION
Exhibit 31.1
I, James D. Palm, Chief Executive Officer of Gulfport Energy Corporation, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Gulfport Energy Corporation;
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;
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;
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: February 27, 2012
/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.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Gulfport Energy Corporation;
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;
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;
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: February 27, 2012
/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)
(2)
the Annual Report on Form 10-K of the Company for the period ended December 31, 2011 (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
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the
Company.
Date: February 27, 2012
/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.
Exhibit 32.2
CERTIFICATION OF PERIODIC REPORT
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)
(2)
the Annual Report on Form 10-K of the Company for the year ended December 31, 2011 (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
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the
Company.
Date: February 27, 2012
/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.
Exhibit 99.1
January 20, 2012
Mr. Mike Moore
Gulfport Energy Corporation
14313 North May Avenue, Suite 100
Oklahoma City, Oklahoma 73134
Dear Mr. Moore:
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2011, to the Gulfport Energy
Corporation (Gulfport) interest in certain oil and gas properties located in Colorado and Louisiana. We completed our evaluation on or about
the date of this letter. It is our understanding that the proved reserves estimated in this report constitute approximately 33 percent of all proved
reserves owned by Gulfport. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S.
Securities and Exchange Commission (SEC) and, with the exception of the exclusion of per-well overhead expenses and future income taxes,
conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented
immediately following this letter. This report has been prepared for Gulfport’s use in filing with the SEC; in our opinion the assumptions,
data, methods, and procedures used in the preparation of this report are appropriate for such purpose.
We estimate the net reserves and future net revenue to the Gulfport interest in these properties, as of December 31, 2011, to be:
Category
Proved Developed Producing
Proved Developed Non-Producing
Proved Undeveloped
Total Proved
Totals may not add because of rounding.
(MBBL)
2,111.5
2,502.0
1,185.5
5,798.9
(MMCF)
1,279.8
1,766.2
579.2
3,625.2
Total
133,802.2
149,128.6
71,708.5
354,639.3
Present Worth
at 10%
116,661.9
118,881.7
49,218.3
284,761.9
Net Reserves
Oil
Gas
Future Net Revenue (M$)
The oil reserves shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to
42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.
The estimates shown in this report are for proved reserves. As requested, probable reserves that exist for these properties have not been
included. No study was made to determine whether possible reserves might be established for these properties. This report does not include
any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.
Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status.
The estimates of reserves and future revenue included herein have not been adjusted for risk.
Gross revenue shown in this report is Gulfport’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future
net revenue is after deductions for Gulfport’s share of production taxes and ad valorem taxes, capital costs, abandonment costs, and operating
expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine
its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether
discounted or undiscounted, should not be construed as being the fair market value of the properties.
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the
period January through December 2011. For oil volumes, the average Shell Trading (US) Company West Texas/New Mexico Intermediate
posted price of $92.69 per barrel is adjusted by field for quality, transportation fees, and regional price differentials. For gas volumes, the
average Henry Hub spot price of $4.118 per MMBTU is adjusted by field for energy content, transportation fees, and regional price
differentials. As requested, an economic projection is included in the proved developed producing category to account for the incremental
income received from certain field-specific oil price hedge contracts currently in place for Cote Blanche Bay, W Field. All prices are held
constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the
properties are $105.39 per barrel of oil and $4.310 per MCF of gas.
Operating costs used in this report are based on operating expense records of Gulfport, the operator of the properties, and include only direct
lease- and field-level costs. As requested, these costs do not include the per-well overhead expenses allowed under joint operating agreements,
nor do they include the headquarters general and administrative overhead expenses of Gulfport. Operating costs are held constant throughout
the lives of the properties.
Capital costs used in this report are based on actual costs from recent activity. Capital costs are included as required for workovers, new
development wells, and production equipment. Based on our understanding of Gulfport’s future development plans, a review of the records
provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in
this report are Gulfport’s estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and
abandonment costs are held constant to the date of expenditure.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or
condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates
do not include any costs due to such possible liability.
We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Gulfport
interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our
projections are based on Gulfport receiving its net revenue interest share of estimated future gross gas production.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil
and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible;
probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates
of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir
performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but
not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent
manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the
reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the
revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and
uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary
from assumptions made while preparing this report.
For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data,
production data, historical price and cost information, and property ownership
interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with
the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum
Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance
analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in
accordance with SEC definitions and regulations. A substantial portion of these reserves are for behind-pipe zones, non-producing zones, and
undeveloped locations; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties
with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the
interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from Gulfport, public data sources, and the nonconfidential files of Netherland, Sewell &
Associates, Inc. (NSAI) and were accepted as accurate. Supporting geoscience, performance, and work data are on file in our office. The titles
to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The
technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence,
objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and
petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.
Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By: /s/ C.H. (Scott) Rees III
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer
By: /s/ Mike K. Norton
Mike K. Norton, P.G. 441
Senior Vice President
By: /s/ Derek F. Newton
Derek F. Newton, P.E. 97689
Vice President
Date Signed: January 20, 2012
Date Signed: January 20, 2012
DFN:JLJ
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also
included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum
Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance
and Disclosure Interpretations.
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options
to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’
fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions
(depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of
interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support
proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:
(i)
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii) Same environment of deposition;
(iii) Similar geological structure; and
(iv) Same drive mechanism.
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of
interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity
greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state
it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but
that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from
the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively
minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means
not involving a well.
Supplemental definitions from the 2007 Petroleum Resources Management System:
Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open
and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery
project is in operation.
Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves
are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started
producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for
mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional
completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively
low expenditure compared to the cost of drilling a new well.
Definitions - Page 1 of 7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and
storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and
facilities and other costs of development activities, are costs incurred to:
(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific
development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the
extent necessary in developing the proved reserves.
(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and
of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring
devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv) Provide improved recovery systems.
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically
producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated
development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be
productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that
exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at
the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative
production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to
have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.
Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after
acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment
and facilities and other costs of exploration activities, are:
(i)
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries
and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred
to as geological and geophysical or “G&G” costs.
(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title
defense, and the maintenance of land and lease records.
(iii) Dry hole contributions and bottom hole contributions.
(iv) Costs of drilling and equipping exploratory wells.
(v) Costs of drilling exploratory-type stratigraphic test wells.
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a
service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
Definitions - Page 2 of 7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural
feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious
strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated
as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify
localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
(16) Oil and gas producing activities.
(i) Oil and gas producing activities include:
(A)
(B)
(C)
(D)
The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and
original locations;
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil
or gas from such properties;
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including
the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1) Lifting the oil and gas to the surface; and
(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other
nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a
view to such extraction.
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the
outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the
terminal point for the production function as:
a.
b.
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or
a marine terminal; and
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a
purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a
refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that
are saleable in the state in which the hydrocarbons are delivered.
(ii) Oil and gas producing activities do not include:
(A)
(B)
Transporting, refining, or marketing oil and gas;
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does
not have the legal right to produce or a revenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and
gas can be extracted; or
(D)
Production of geothermal steam.
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding
proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the
total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
Definitions - Page 3 of 7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of
available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to
define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than
the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative
technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to
results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the
same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other
geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are
in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or
lower than the proved area if these areas are in communication with the proved reservoir.
(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the
potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir
above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the
reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir
fluid properties and pressure gradient interpretations.
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which,
together with proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated
proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual
quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of
available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable
certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in
communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the
hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could
reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes
and their associated probabilities of occurrence.
(20) Production costs.
(i)
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating
costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and
facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
(A)
(B)
Costs of labor to operate the wells and related equipment and facilities.
Repairs and maintenance.
(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
Definitions - Page 4 of 7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
Severance taxes.
(D)
(E)
(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation,
refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities,
their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation,
depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become
part of the cost of oil and gas produced along with production (lifting) costs identified above.
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known
reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or
probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be
reasonably certain that it will commence the project within a reasonable time.
(i)
The area of the reservoir considered as proved includes:
(A)
The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to
contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as
seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact
with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an
associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience,
engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to,
fluid injection) are included in the proved classification when:
(A)
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a
whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable
technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B)
The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The
price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined
as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined
by contractual arrangements, excluding escalations based upon future conditions.
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be
recovered. If probabilistic methods are used, there should be at least a 90%
Definitions - Page 5 of 7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much
more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical),
engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to
increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field
tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in
an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as
of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable
expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or
related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those
reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a
known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas
may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be
disclosed as of the end of the year:
a.
Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity
participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those
reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for
reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve
quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a.
b.
c.
d.
e.
f.
Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves
to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by
contractual arrangements in existence at year-end.
Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in
developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming
continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented
separately from estimated production costs.
Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with
consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and
gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions
and tax credits and allowances relating to the entity’s proved oil and gas reserves.
Future net cash flows. These amounts are the result of subtracting future development and production costs and future
income tax expenses from future cash inflows.
Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net
cash flows relating to proved oil and gas reserves.
Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed
discount.
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined
by impermeable rock or water barriers and is individual and separate from other reservoirs.
Definitions - Page 6 of 7
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may
be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and
undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells
include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for
in-situ combustion.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific
geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification
also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified
as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from
new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i)
(ii)
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably
certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of
economic producibility at greater distances.
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating
that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or
environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time
periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se
justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though
development may extend past five years include, but are not limited to, the following:
•
•
•
•
•
The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only
the minimum number of wells necessary to maintain the lease generally would not constitute significant development
activities);
The company’s historical record at completing development of comparable long-term projects;
The amount of time in which the company has maintained the leases, or booked the reserves, without significant
development activities;
The extent to which the company has followed a previously adopted development plan (for example, if a company has
changed its development plan several times without taking significant steps to implement any of those plans, recognizing
proved undeveloped reserves typically would not be appropriate); and
The extent to which delays in development are caused by external factors related to the physical operating environment
(for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by
internal factors (for example, shifting resources to develop properties with higher priority).
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of
fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by
actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other
evidence using reliable technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves.
Definitions - Page 7 of 7
GULFPORT ENERGY CORPORATION
Exhibit 99.2
Estimated
Future Reserves and Income
Attributable to Certain
Leasehold Interests
SEC Parameters
As of
December 31, 2011
\s\ Don P. Griffin
Don P. Griffin, P.E.
TBPE License No. 64150
Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
[SEAL]
TBPE REGISTERED ENGINEERING FIRM F-1580
1100 LOUISIANA SUITE 3800 HOUSTON, TEXAS 77002-5235 TELEPHONE(713) 651-9191
FAX (713) 651-0849
January 13, 2012
Gulfport Energy Corporation
14313 N. May, Suite 100
Oklahoma City, Oklahoma 73134
Gentlemen:
At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income
attributable to certain leasehold interests of Gulfport Energy Corporation (Gulfport) as of December 31, 2011. The subject properties are
located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United
States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas
Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 6,
2012, and presented herein, was prepared for public disclosure by Gulfport in filings made with the SEC in accordance with the disclosure
requirements set forth in the SEC regulations.
The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the
total net proved gas reserves of Gulfport as of December 31, 2011.
The results of this study are summarized below.
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold Interests of
Gulfport Energy Corporation
As of December 31, 2011
Net Remaining Reserves
Oil/Condensate – Mbbl
Plant Products – Mbbl
Gas – MMCF
Income Data ($M)
Future Gross Revenue
Deductions
Future Net Income (FNI)
Discounted FNI @ 10%
Developed
Proved
Producing
Non-Producing
Undeveloped
Total
Proved
1,853
660
2,853
244
46
197
5,989
2,085
8,996
8,086
2,791
12,046
$210,025
52,844
$157,181
$ 84,900
$
$
$
24,859
2,238
22,621
$ 675,799
348,154
$ 327,645
$910,683
403,236
$507,447
14,551
$ 102,837
$202,288
SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4
621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501
TEL (403) 262-2799
TEL (303) 623-9147
FAX (403) 262-2790
FAX (303) 623-4258
Gulfport Energy Corporation
January 13, 2012
Page 2
The estimated reserves and future net income amounts presented in this report, as of December 31, 2011, are related to hydrocarbon
prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the
ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-
month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual
future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the
amounts of income actually received may differ significantly from the estimated quantities presented in this report.
Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (Mbbl). All gas volumes are reported on an “as sold
basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are
located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).
TM
The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic
System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used
software package Aries
solely at the request of Gulfport. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and
calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line
economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The
rounding differences are not material.
The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the
wells, ad valorem taxes, recompletion costs, and development costs. The future net income is before the deduction of state and federal income
taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment
for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 94.9 percent and gas reserves account for
the remaining 5.1 percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly.
Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary
form as follows.
Discount Rate
Percent
5
15
20
25
Discounted Future Net Income ($M)
As of December 31, 2011
Total
Proved
$303,812
$144,573
$108,577
$ 84,579
The results shown above are presented for your information and should not be construed as our estimate of fair market value.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Gulfport Energy Corporation
January 13, 2012
Page 3
Reserves Included in This Report
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations
Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included
as an attachment to this report.
The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report.
The proved developed non-producing reserves included herein consist of the shut-in category.
No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas
volumes included herein do not attribute gas consumed in operations as reserves.
Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a
given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty
relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the
date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the
estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal
classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-
classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Gulfport’s request, this
report addresses only the proved reserves attributable to the properties evaluated herein.
Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible from a given date forward. The proved reserves included herein were estimated using
deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of
confidence that the quantities will be recovered.”
Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic
conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical,
and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is
much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future
operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this
report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs
related thereto, could be more or less than the estimated amounts.
Gulfport’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may
include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production
practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax are subject to
change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered
and amounts of proved income actually received to differ significantly from the estimated quantities.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Gulfport Energy Corporation
January 13, 2012
Page 4
The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Gulfport owns an interest;
however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental
liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating
practices.
Estimates of Reserves
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of
recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in
accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of
estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These
analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and
(3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of
reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given
the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated
performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.
In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a
range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is
identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are
estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by
the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that
addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable
certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are
those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as
not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable
reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible
reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or
engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised
due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or
geopolitical or economic risks as previously noted herein.
The proved reserves for the properties included herein were estimated by performance methods, analogy, or a combination of methods.
Approximately 90 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance
methods. These performance methods involved decline curve analysis which utilized extrapolations of historical production and pressure data
available through October 2011 in those cases where such data were
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Gulfport Energy Corporation
January 13, 2012
Page 5
considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Gulfport or obtained from public data sources
and were considered sufficient for the purpose thereof. The remaining 10 percent of the proved producing reserves were estimated by analogy
or a combination of performance and analogy. These methods were used where there were inadequate historical performance data to establish
a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.
All of the proved developed non-producing and undeveloped reserves included herein were estimated by the analogy method. The data
utilized from the analogues were considered sufficient for the purpose thereof.
To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and
assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that
cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.
Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date
forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be
determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other
costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance
with rules adopted by the SEC, omitted from consideration in making this evaluation.
Gulfport has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports
and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data
furnished by Gulfport with respect to property interests owned, production and well tests from examined wells, normal direct costs of
operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, and development
costs, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps,
well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not
conducted an independent verification of the data furnished by Gulfport. We consider the factual data used in this report appropriate and
sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.
In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose
hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves
herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission
(SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein
collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and
disclosure requirements as required by the SEC regulations.
Future Production Rates
For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production
decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until
a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has
been established, this trend was used as the basis for estimating future production rates.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Gulfport Energy Corporation
January 13, 2012
Page 6
Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are
not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Gulfport.
Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen
factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the
sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less
than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities,
compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints
set by regulatory bodies.
Hydrocarbon Prices
The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the
ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-
month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under
contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the
contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.
Gulfport furnished us with the above mentioned average prices in effect on December 31, 2011. These initial SEC hydrocarbon prices
were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the
hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes
the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price
reference and benchmark prices may be defined by contractual arrangements.
The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark
prices for gravity, quality, local conditions, gathering and transportation fees, and/or distance from market, referred to herein as “differentials.”
The differentials used in the preparation of this report were furnished to us by Gulfport. The differentials furnished to us were accepted as
factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by
Gulfport to determine these differentials.
In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the
“average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before
production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of
the geographic areas included in the report.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Gulfport Energy Corporation
January 13, 2012
Page 7
Geographic Area
North America
United States
Product
Price
Reference
Oil/Condensate
NGLs
WTI Cushing
WTI Cushing
Henry Hub —
Colorado Interstate
Average
Benchmark
Prices
Average
Realized
Prices
$96.19/Bbl
$96.19/Bbl
$93.11/Bbl
$57.09/Bbl
The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property
Gas
$4.12/MMBTU
$4.04/MCF
evaluations.
Costs
Operating costs for the leases and wells in this report are based on the operating expense reports of Gulfport and include only those
costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the
leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we
have not conducted an independent verification of the operating cost data used by Gulfport. No deduction was made for loan repayments,
interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.
Development costs were furnished to us by Gulfport and are based on authorizations for expenditure for the proposed work or actual
costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness;
however, we have not conducted an independent verification of these costs. Gulfport’s estimates of zero abandonment costs after salvage
value for onshore properties were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage
value and makes no warranty for Gulfport’s estimate.
The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with
Gulfport’s plans to develop these reserves as of December 31, 2011. The implementation of Gulfport’s development plans as presented to us
and incorporated herein is subject to the approval process adopted by Gulfport’s management. As the result of our inquiries during the course
of preparing this report, Gulfport has informed us that the development activities included herein have been subjected to and received the
internal approvals required by Gulfport’s management at the appropriate local, regional and/or corporate level. In addition to the internal
approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA)
requirements or other administrative approvals external to Gulfport. Additionally, Gulfport has informed us that they are not aware of any
legal, regulatory, political or economic obstacles that would significantly alter their plans.
Current costs used by Gulfport were held constant throughout the life of the properties.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Gulfport Energy Corporation
January 13, 2012
Page 8
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout
the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary,
Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large
number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve
as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment
decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our
services.
Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of
reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related
topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional
accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s
license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to Gulfport. Neither we nor any of our employees have any interest in the subject
properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties
which were reviewed.
The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder
Scott. The professional qualifications of the undersigned, the technical person primarily responsible for the evaluation of the reserves
information discussed in this report, are included as an attachment to this letter.
Terms of Usage
The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set
forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Gulfport.
We have provided Gulfport with a digital version of the original signed copy of this report letter. In the event there are any differences
between the digital version included in filings made by Gulfport and the original signed report letter, the original signed report letter shall
control and supersede the digital version.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Gulfport Energy Corporation
January 13, 2012
Page 9
The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please
contact us if we can be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration No. F-1580
\s\ Don P. Griffin
Don P. Griffin P.E.
TBPE License No. 64150
Senior Vice President
[SEAL]
DPG/pl
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder
Scott Company, L.P. Don P. Griffin was the primary technical person responsible for overseeing the estimate of the reserves, future
production and income presented herein.
Mr. Griffin, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible for coordinating and
supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott,
Mr. Griffin served in a number of engineering positions with Amoco Production Company. For more information regarding Mr. Griffin’s
geographic and job specific experience, please refer to the Ryder Scott Company website at
http://www.ryderscott.com/Experience/Employees.php.
Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975 and is a
licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum
Evaluation Engineers.
In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a
minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Griffin
fulfills. As part of his 2009 continuing education hours, Mr. Griffin attended an internally presented 16 hours of formalized training relating to
the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal
Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Griffin attended an
additional 15 hours of training during 2010 covering such topics as reservoir engineering, geoscience and petroleum economics evaluation
methods, procedures and software and ethics for consultants.
Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of
petroleum reserves, Mr. Griffin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in
Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of
Petroleum Engineers as of February 19, 2007.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas
Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and
Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions
to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The
“Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to
herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and
Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of
Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the
aforementioned SEC document are denoted in italics herein).
Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a
given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty
relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the
date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the
estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal
classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-
classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations
as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas
reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources
other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is
required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions
change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for
supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure
maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement
fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
Page 2
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered
as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of
processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-
centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized
extraction technology and/or significant processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory.
Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves
categories.
RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of
a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable
expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or
related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those
reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated
from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results).
Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known
reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or
probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be
reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
PETROLEUM RESERVES DEFINITIONS
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(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to
contain economically producible oil or gas on the basis of available geoscience and engineering data.
PROVED RESERVES (SEC DEFINITIONS) CONTINUED
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as
seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with
reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an
associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience,
engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to,
fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a
whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable
technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price
shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an
unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by
contractual arrangements, excluding escalations based upon future conditions.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
RESERVES STATUS DEFINITIONS AND GUIDELINES
As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)
and
PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17,
Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are
based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are
denoted in italics herein).
DEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is
relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by
means not involving a well.
Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified
according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.
Developed Producing Reserves
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the
estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS
RESERVES STATUS DEFINITIONS AND GUIDLINES
Page 2
Developed Non-Producing
Developed Non-Producing Reserves include shut-in and behind-pipe reserves.
Shut-In
Shut-in Reserves are expected to be recovered from:
(1)
(2)
(3)
completion intervals which are open at the time of the estimate, but which have not started producing;
wells which were shut-in for market conditions or pipeline connections; or
wells not capable of production for mechanical reasons.
Behind-Pipe
Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future
re-completion prior to start of production.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
UNDEVELOPED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain
of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic
producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating
that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of
fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual
projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using
reliable technology establishing reasonable certainty.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS